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.
PV-10 (Present value of future net cash flow). The present value of estimated future revenues to be generated from the production of estimated proved reserves, net of capital expenditures and operating expenses, using the simple 12 month arithmetic average of first of the month prices and current costs (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, depreciation, depletion and amortization or impairment, discounted using an annual discount rate of 10%. While this non-GAAP measure does not include the effect of income taxes as would the use of the standardized measure calculation, we believe it provides an indicative representation of the relative value of our company on a comparative basis to other companies and from period to period.
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.
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.
PART I
Items 1 and 2. Business and Properties
Overview
Lilis Energy, Inc. and its consolidated subsidiaries (collectively, “we,” “us,” “our,” “Lilis Energy,” “Lilis,” or the “Company”) is an upstream independent oil and natural gas company engagedfocused on the exploration, development, production, and acquisition of oil, natural gas and NGLs from properties in the acquisition, drillingPermian Basin. Our operations are focused in the Delaware Basin of the Permian in Winkler, Loving, and Reeves Counties, Texas and Lea County, New Mexico, where the production is approximately 74% Liquids, a relatively high liquid production ratio compared to many of our peers. Over 90% of our revenues are generated from the sale of Liquids.
Our History
The Company was incorporated in the State of Nevada in 2007. The name of the corporation was changed from Recovery Energy, Inc. to “Lilis Energy, Inc.” in December 2013, and at such time, the Company was primarily focused on the exploration, development and production of oil and natural gas properties and prospects. We were incorporated in August 2007 in the State of Nevada as Universal Holdings, Inc. Denver-Julesburg (DJ) Basin.
In
October 2009, we changed our name to Recovery Energy, Inc. and in December 2013, we changed our name to Lilis Energy, Inc.On June 23, 2016, we completed thea transformative merger transaction contemplated by the Agreement and Plan of Merger dated as of December 29, 2015, as amended to date (the “Merger Agreement”) by and among us,with Brushy Resources, Inc., a Delaware corporation (“Brushy”) and Lilis Merger Sub, Inc., a Delaware corporation, a wholly-owned subsidiary of ours (“Merger Sub”). Pursuant to the terms of the Merger Agreement, at the effective time (the “Effective Time”Brushy Resources” or “Brushy”), Merger Sub merged with and into Brushy (the “Merger”), with Brushy continuing as the surviving corporation and becoming a wholly-owned subsidiary of ours.The Mergerwhich resulted in the acquisition of our propertiesthe Company’s initial assets in the Delaware Basin as well asPermian Basin. Given the majoritystacked-pay opportunities and high rates of our current operating activity.
Additionally, in connection with the Merger on June 23, 2016, we effected a 1-for-10 reverse stock split (the “Reverse Split”). As a result of the Reverse Split, every ten shares of issued and outstanding common stock were automatically converted into one newly issued and outstanding share of common stock, without any changereturn in the par value per share. However,Permian Basin, the number of authorized shares of common stock remained unchanged.
Shortly after the Merger, we began to develop a drilling programCompany determined that it would focus exclusively on our properties using hydraulic fracture stimulation techniques. Our primary focus is drilling horizontal wells in the Delawareexpanding and developing its core Permian Basin of West Texas, which we believe will provide attractive returns on a majority of our acreage positions. Our goal is to earn economic returns to our shareholders through cash flow from new production of oil, natural gas and NGLs, as well as through derisking the development profile of our portfolio of properties in order to add overall value. Our drilling program utilizes the development of new horizontal wells across several potentially productive formations in the Delaware Basin but initially targeting the Wolfcamp formation. We drilled our first horizontal well in late 2016assets and completed it in February 2017.
Overviewthe divestiture of Our Business and Strategy
We are anall of its oil and natural gas company, engagedproperties located in the acquisition, development and production of conventional and unconventional oil and natural gas properties. We have accumulated approximately 6,924 net acres in the DelawareDJ Basin in Winkler and Loving Counties, Texas and Lea County, New Mexico. March 2017.
Our leasehold position is largely contiguous, allowing us to maximize development efficiency, manage full-cycle finding costs and potentially enabling us to generate higher returns for our shareholders. In addition, 66% of our acreage positions is held by production, and weBusiness/Strategy
We are the named operator on 100% of our acreage. These characteristics give us control over the pace of development and the ability to design a more efficient and profitable drilling program that maximizes recovery of hydrocarbons. We expect that substantially all of our estimated 2017 capital expenditure budget will bepure play Permian Basin company focused on the development and expansionproduction of Liquids. In each of the past two years, over 90% of our Delaware Basin acreagerevenues have been generated from the sale of Liquids.
We are actively working on increasing liquidity including seeking strategic financing options. There is no assurance that our efforts will be successful and operations. We also planas a result there is substantial doubt about our ability to continue as a going concern. See Note 2 - Liquidity and Going Concern to our consolidated financial statements included in this Annual Report for additional information regarding our plans to improve our liquidity and our ability to continue to selectivelycomply with the financial covenants under our Revolving Credit Agreement.
Oil and
opportunistically pursue strategic bolt-on acreage acquisitions.As of March 1, 2017, our net production was 618 Boe/d (44% oil and liquids) of which 522 Boe/d was from our Delaware Basin area and 96 Boe/d from our Denver-Julesburg Basin area. Natural Gas Properties
As of December 31, 2016, on consolidated basis,2019, we had proved reserves of 1,195 MBoe (46% oil and liquids).Our Delaware Basin Properties
We haveowned leasehold acreage in approximately 6,924 net27,920 gross (19,562 net) acres in the Delaware Basin, comprised of 6,424approximately 16,012 net acres in Winkler, Loving, and LovingReeves Counties, Texas and 500approximately 3,550 net acres in Lea County, New Mexico. Average net sales production volumes from our properties increased approximately 3% to
5,102 BOE/d in 2019 from 4,965 BOE/d in 2018.
Our undeveloped leasehold acreage at December 31, 2019 was 15,250 gross (8,050 net) acres, of which 5,670 net acres have expiration dates in 2020 and will expire if the Company does not obtain necessary funding to either extend the leases or begin drilling before their expiration dates. As a result, we have recorded an impairment of unproved leasehold of $56.2 million during the year ended December 31, 2019.
On February 28, 2020, the Company closed the sale of approximately 1,185 undeveloped net acres in Lea County, New Mexico, for net cash proceeds of approximately $24.1 million, subject to customary purchase price adjustments (the “Marlin Disposition”).
We currently estimate our properties include at least five to seven productive zones and hold more than 1,000 future drilling locations across all of the productive zones within this position.
Reserves Data
Proved Reserves
The
aerial extentfollowing table presents our estimated net proved oil and natural gas reserves based on the reserves report prepared by LaRoche Petroleum Consultants, Ltd. (“LaRoche”) as of
December 31, 2019, and the reserves reports prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”) for the years 2018 and 2017. Each reserves report has been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). All of our proved reserves included in the reserves reports are located in the Delaware Basin
stretches across Ward, Reeves, Loving, Winkler, Pecos, and Culberson Counties in Texas and also runs north into Lea and Eddy Counties in New Mexico. The Delaware Basin is comprised of multiple stacked petroleum systems. Drilling and completion technology has evolved with more modern vintage wells utilizing longer laterals, more numerous fracture stimulation stages, and higher volumes of proppant. Our 2017 drilling program will primarily target the Wolfcamp formation in up to 10 wells. We are targeting horizontal lateral lengths of 5,000 to 7,500 feet, holding hydraulic fracture stimulation stages per wellbore at each 200 foot increment, and an average of 2,200 pounds of proppant per lateral foot. Considering offset operator activity and our internal estimates, we believe our net average well cost will be between approximately $6.0 million and $8.0 million per well based on the lateral length range of 5,000 to 7,500 feet, with average estimated ultimate recoveries, or EURs, ranging from approximately 738 to 915 MBoe per well, and initial 30-day average production ranging between approximately 1,200 to over 1,750 Boe/d per well.Our Denver-Julesburg Basin Properties
In addition to our core Delaware Basin focus area, we have approximately 14,254 net acres in the Denver-Julesburg Basin (“DJ Basin”) comprised of 280 net acres in the core of the Wattenberg field in Weld County, Colorado and 13,974 net acres in Laramie County, Wyoming, Nebraska and other partsPermian Basin:
Summary of
Colorado. Our acreage position has multi-zone potential with producing wells in the Niobrara, Codell, and J Sand. Our 2017 capital expenditure budget does not contemplate committing significant capital to our DJ Basin project area, and we are currently reviewing strategic alternatives with respect to these properties.Business Strengths and Strategies
Our primary business objective is to increase our Delaware Basin leasehold position, reserves, production and cash flows at attractive rates of return on invested capital in order to enhance shareholder value. To achieve this objective, key elements of our strategy include:
| · | Geographic focus in one of North America’s leading unconventional oil plays. We have accumulated a leasehold position of approximately 6,924 net acres in the Delaware Basin as of March 1, 2017. We believe the Delaware Basin has one of the highest rates of return among such formations in North America based on results of offset operators. In addition to leveraging our technical expertise in this core area, our geographically-concentrated acreage position allows us to capitalize on economies of scale with respect to drilling and production costs. 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 Delaware Basin operating area. We plan on allocating all of our 2017 capital budget to our Delaware Basin activities. |
| · | Develop our Delaware Basin leasehold position. We intend to focus on developing our acreage position in the Delaware Basin in order to maximize the value of our resource potential through utilizing the best-in-class drilling and completion techniques at the lowest possible costs. Through the development of our properties, we will seek to derisk our acreage position and drilling program and substantially increase our production and cash flow, thereby increasing the value of our properties. Our current leasehold position in the Delaware Basin has significant stacked-pay potential. We currently estimate our properties include at least seven productive zones and hold approximately 500 future drilling locations across all of the productive zones within this position. Initially, we intend to focus our horizontal development on the Wolfcamp formation, followed by the Bone Spring and Avalon formations through a combination of re-entering existing vertical wellbores and new drilling locations. |
| · | Pursue strategic acquisitions, organic leasing, and other creative structures to continue to develop and grow our production and leasehold position. We continue to identify and seek to acquire additional acreage and producing assets in the Delaware Basin. We believe that we can continue our successful track record of growing our acreage position in and around our core area at attractive costs. Since entering the Delaware Basin in June 2016, we have grown our acreage position 98% from 3,500 net acres to 6,924. We have accomplished this through buying smaller packages that are complementary to our core position and also by acquiring smaller, fragmented working interest positions on existing leaseholds. |
| · | Leverage our extensive operational expertise to reduce costs and enhance returns. We are focused on continuously improving our operating costs and metrics. We evaluate our operating metrics against those of other operators in our area in order to measure our performance and optimize our drilling and completion techniques. We utilize this process to make informed decisions about our capital expenditure program and drilling and completion activity. We intend to leverage our contiguous acreage position and our knowledge of the Delaware Basin to capture operational and economic efficiencies. |
| · | Employ leading drilling and completion techniques. We intend to employ industry best practices well design drilling and completion techniques by replicating leading Delaware Basin operators. Our contiguous acreage position is offset by RSP Permian, Matador, Devon, Shell, Anadarko, and XTO, among other operators, and we will continue to observe and monitor their drilling activity and well results in the area as we execute on our development plan. |
| · | Maintain financial liquidity and flexibility. We intend to utilize cash flow from operations, available working capital, borrowings under our multiple-draw term loan and access the capital markets in order to fund and execute our capital expenditure and development program. We believe this financial liquidity and flexibility will result in steady growth in leasehold, production, cash flow and proved reserves. |
| · | Hedging.We intend to opportunistically use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs and capital programs. We intend to use hedging primarily to manage price risks and returns on certain acquisitions and drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive. |
Principal Oil and Natural Gas Interests
All references to production, sales volumes and reserve quantities are net to our interest unless otherwise indicated.
Reserves
|
| | | | | | | | |
| | For the Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Proved Developed Reserves | | | | | |
| Oil (MBbls) | 5,335 |
| | 6,278 |
| | 2,531 |
|
| NGLs (MBbls) | 2,278 |
| | 2,654 |
| | 645 |
|
| Total Liquids (MBbls) | 7,613 |
| | 8,932 |
| | 3,176 |
|
| Natural Gas (MMcf) | 29,445 |
| | 27,046 |
| | 6,594 |
|
| Total MBOE | 12,521 |
| | 13,440 |
| | 4,275 |
|
| | | | | | |
| Proved Undeveloped Reserves | | | | | |
| Oil (MBbls) | — |
| | 14,927 |
| | 4,640 |
|
| NGLs (MBbls) | — |
| | 5,723 |
| | 960 |
|
| Total Liquids (MBbls) | — |
| | 20,650 |
| | 5,600 |
|
| Natural Gas (MMcf) | — |
| | 51,703 |
| | 9,466 |
|
| Total MBOE | — |
| | 29,267 |
| | 7,178 |
|
| | | | | | |
| Total Proved Reserves | | | | | |
| Oil (MBbls) | 5,335 |
| | 21,205 |
| | 7,171 |
|
| NGLs (MBbls) | 2,278 |
| | 8,377 |
| | 1,605 |
|
| Total Liquids (MBbls) | 7,613 |
| | 29,582 |
| | 8,776 |
|
| Natural Gas (MMcf) | 29,445 |
| | 78,749 |
| | 16,060 |
|
| Total MBOE | 12,521 |
| | 42,707 |
| | 11,453 |
|
Proved Undeveloped Reserves
As of December 31, 2016,2019, we owned interestsdid not recognize any proved undeveloped reserves. During 2019, our proved undeveloped (“PUD”) reserves decreased 29,267 MBOE primarily due to capital constraints, as discussed below, and the conversion of one PUD to proved developed producing (“PDP”) reserves in 2019. Costs incurred to develop the PUD were approximately 19,968 net acres,$7.5 million during 2019.
All of which 14,994 net acres are classifiedour PUD reserves were reclassified as undeveloped acreage and allunproved due to our inability to meet the Reasonably Certain criteria for recognizing PUD reserves because of which are located in west Texas and New Mexico within the Delaware Basin and Colorado, Wyoming and Nebraska withinuncertainty regarding the DJ Basin. Our primary targets withinavailability of capital to us for the Delaware Basin are the Wolfcamp formationdevelopment of these reserves as well as the Bone Springs and Avalon Formations.As of December 31, 20162019, which was driven by further pricing declines during the fourth quarter of 2019. See
Note 2 - Liquidity and March 1, 2017, we had 2 gross (1.2 net) and 1 gross (0.6 net) wellsGoing Concern to our consolidated financial statements in this Annual Report. As a result, the Company recognized approximately $75.3 million of impairment relating to the value of PUD reserves which were reclassified as unproved in the processfourth quarter of being drilled, respectively, all2019.
For additional information regarding the changes in our proved reserves, see our “Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities” to our consolidated financial statements in Item 15 of this Annual Report.
Control over Reserve Estimates
The Company’s estimated proved oil and gas reserves have been prepared by the
Delaware Basin.Reserves
The table below presents summary information with respect toindependent petroleum engineering firm LaRoche as of December 31, 2019 and CG&A as of December 31, 2018, assisted by the estimatesengineering and operations departments of the Company. For the year ended December 31, 2019, LaRoche estimated reserves for our properties comprising 100% of the PV-10 of our proved oil and gas reserves for the years ended December 31, 2016as described in more detail herein, in compliance with SEC definitions and 2015. We engaged Cawley, Gillespie & Associates, Inc. (“CG&A”)guidance and Forrest A. Garb & Associates to audit internally preparedin accordance with generally accepted petroleum engineering estimates for all of our proved reserves at year-end 2016 and 2015, respectively.Of these reserves, approximately 50% were classified as Proved Developed Producing (“PDP”). Proved Undeveloped (“PUD”) and Proved Non-Producing (“PNP”) included in this estimate are from 0 vertical well locations and 2 horizontal well locations. As of December 31, 2016, total proved reserves were approximately 46% oil and NGLs and 54% natural gas. As of December 31, 2015, total proved reserves were approximately 59% oil and NGLs and 41% natural gas.
The following table provides summary information regarding our proved reserves as of December 31, 2016 and 2015, and production for the years ended December 31, 2016 and 2015.
Estimated Total Proved Reserves
| | | December 31, | |
| | | 2016 | | | 2015 | |
| | | Delaware
Basin | | | DJ Basin | | | Total | | | Delaware
Basin | | | DJ Basin | | | Total | |
| Oil (MMBBL) | | | 0.455 | | | | 0.096 | | | | 0.551 | | | | - | | | | 0.033 | | | | 0.033 | |
| Natural Gas (BCF) | | | 3.507 | | | | 0.365 | | | | 3.872 | | | | - | | | | 0.141 | | | | 0.141 | |
| Total (MMBOE) | | | 1.04 | | | | 0.156 | | | | 1.196 | | | | - | | | | 0.057 | | | | 0.057 | |
| % Oil | | | 44 | % | | | 61 | % | | | | | | | - | | | | 59 | % | | | | |
| % Developed | | | 100 | % | | | 100 | % | | | | | | | - | | | | 100 | % | | | | |
| Avg. Net Production (BOE/D) | | | 317 | | | | 87 | | | | 404 | | | | - | | | | 215 | | | | 215 | |
During the years ended December 31, 2016 and 2015, we recognized an impairment expense of approximately $4.7 million and $24.5 million, respectively. The $4.7 million impairment charge during the year ended December 31, 2016 was primarily due to the lower commodity prices sustained for the majority of 2016 in the DJ Basin and the $24.5 million impairment charge for the year ended December 31, 2015 was attributable to the lack of capital to develop our undeveloped oil and gas properties and lower commodity prices.
principles.
Internal Controls over Reserves Estimate
Our policy regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and
natural gas
reservereserves quantities and values in compliance with the regulations of the
Securities Exchange Commission (the “SEC”).SEC. Responsibility for compliance in
reservereserves bookings is delegated to our Chief
FinancialExecutive Officer with assistance from our
senior geologist consultant and a senior reserve engineering consultant. In 2016, we established a Reserves Committee to provide additional oversightVice President of our reserves estimation and certification process. The members of the Reserves Committee consist of Brennan Short, our Chief Operating Officer, Ron Ormand, our Executive Chairman and Glenn Dawson, a member of our Board of Directors.Technical reviews are performed throughout the year by our Vice President of Reservoir Engineering, our senior reserve engineering consultant and our geologist and other consultants who evaluate all available geological and engineering data, under the guidance of the Chief Financial Officer.data. This data, in conjunction with economic data and ownership information, is used in making a determination of estimated proved reservereserves quantities. The 2016 reserve process was overseen by Chris Cantrell,Indranil (Neil) Barman, our senior reserve engineering consultant. Mr. Cantrell holds a BachelorVice President of ScienceReservoir Engineering, has more than 23 years of industry experience and has been evaluating oil and natural gas properties since 2004. He received his Ph.D. degree in Petroleum Engineering conferred byfrom Texas A&M University in 1995. Heand is a registered professional engineer licensed in the State of Texas, license number 90521. He has been continuously involvedTexas.
For the year ended December 31, 2019, our Reserves Committee, a committee of our Board of Directors, assisted management and the Board of Directors with their oversight of our reserves estimation and certification process and the work of our independent reserves engineer. Following the resignation of three directors, effective as of April 15, 2020, the Board of Directors dissolved the Reserves Committee as a result of a reduction in evaluatingthe size of the Board of Directors.
Our reserves estimates and the corresponding report from LaRoche, along with the process for developing such estimates, are also reviewed by our geologist and the Audit Committee of our Board of Directors to ensure compliance with SEC disclosure and internal control requirements and to verify the independence of our third-party consultants. The Audit Committee of our Board of Directors reviews the final reserves estimate in conjunction with LaRoche’s reserves report.
Third-Party Reserves Study
Our controls over reserves estimates include retaining an independent third-party consultant, LaRoche, as our independent petroleum engineering consulting firm to perform a reserves report of our proved reserves for 2019. We provided LaRoche with information about our oil and
natural gas properties,
since 1997,including production information, prices and
is a member of the Society of Petroleum Engineerscosts, and
the American Petroleum Institute.
Third-party Reserves Study
An independent third-party reserve study as of December 31, 2016, wasLaRoche performed by CG&Areserves studies using its own engineering assumptions and otherthe economic data provided by us. All of our total calculated proved reserve PV-10reserves value was auditedestimated by LaRoche for 2019, and all of the information regarding our 2019, 2018, and 2017 reserves in this Annual Report is derived from the third party reports of LaRoche and CG&A. CG&A
LaRoche is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services for over
2040 years. The
individual at CG&A primarilytechnical personnel responsible for
overseeing our reserve audit is Todd Brooker, Senior Vice President of CG&A, who received a Bachelor of Science degree in Petroleum Engineering frompreparing the
University of Texasreserves estimates at LaRoche meet the requirements regarding qualifications, independence, objectivity, and
is a registered Professional Engineerconfidentiality set forth in the
StatesStandards Pertaining to the Estimating and Auditing of
Texas. He is also a member ofOil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
The CG&A report dated January 12, 2017, LaRoche is filed as Exhibit 99.1 to this Annual Reportan independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists. They do not own an interest in any of our properties and are not employed on Form 10-K.
a contingent fee basis. All reports by LaRoche were developed utilizing their own geological and engineering data, supplemented by data provided by Lilis
Oil and
natural gas reserves and the estimates of the present value of future net cash flows therefrom were determined based on prices and costs as prescribed by the SEC and Financial Accounting Standards Board (“FASB”) guidelines.
ReserveReserves calculations involve the estimate of future net recoverable reserves of oil and
natural gas and the timing and amount of future net cash flows to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that
reservereserves 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,
20162019, 2018, and
2015, commodity prices over2017, we based the
prior 12-month period and year end costs were used in estimatingestimated discounted future net cash flows
from proved reserves on the trailing 12-month averages of oil and natural gas index prices, calculated as the un-weighted arithmetic average for the first-day-of-the-month price for each month and costs in
accordance with SEC guidelines.In addition to a third-party reserve study, our reserves andeffect on the corresponding report are reviewed by our Chief Financial Officer, geologist and the Audit Committeedate of our Board of Directors. Our Chief Financial Officer is responsible for reviewing and verifying that the estimate, holding the prices and costs constant throughout the life of provedthe properties.
The price of oil and natural gas has fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil. If these reduced prices continue or if prices of oil, natural gas and NGLs experience additional substantial decline, our oil, natural gas and NGL reserves
is reasonable, complete,may be materially and
accurate. The Audit Committee of our Board of Directors reviews the final reserves estimate in conjunction with CG&A’s audit letter.adversely affected.
Oil and Natural Gas Production,
Production Prices, and Production Costs
Production Volumes and Sales Prices
The following table summarizes the average volumes and realized prices of oil and natural gas produced from our properties in which we held an interest during the periods indicated,indicated:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Production | | | | | |
| Oil (Bbls)-net production | 1,131 |
| | 1,090 |
| | 372 |
|
| Oil (per Bbl)-average realized price | $ | 52.19 |
| | $ | 53.26 |
| | $ | 47.92 |
|
| Natural gas liquids (Bbls)-net production | 221 |
| | 246 |
| | 74 |
|
| Natural gas liquids (per Bbl)-average realized price | $ | 17.52 |
| | $ | 28.11 |
| | $ | 22.49 |
|
| Natural Gas (Mcf)-production | 3,064 |
| | 2,856 |
| | 776 |
|
| Natural Gas (per Mcf)-average realized price | $ | 1.04 |
| | $ | 1.84 |
| | $ | 2.74 |
|
| Barrels of oil equivalent (BOE) | 1,862 |
| | 1,812 |
| | 575 |
|
| Average daily net production (BOE) | 5,102 |
| | 4,965 |
| | 1,576 |
|
| Average Sales Price per BOE | $ | 35.47 |
| | $ | 38.75 |
| | $ | 37.57 |
|
The average oil and
NGL sales prices above are calculated by dividing revenue from oil sales by volume of oil sold, in “Bbls.” The average natural gas sales prices above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in “Mcf.” The total average sales price amounts are calculated by dividing total revenues by total volume sold, in BOE. The average production
cost per BOE:| | | For the Year Ended
December 31, | |
| | | 2016 | | | 2015 | |
| Product | | | | | | | | |
| Oil (Bbl.) | | | 61,088 | | | | 7,067 | |
| Oil (Bbls)-average price | | $ | 39.59 | | | $ | 41.36 | |
| | | | | | | | | |
| Natural Gas (MCFE)-volume | | | 400,775 | | | | 32,291 | |
| Natural Gas (MCFE)-average price | | $ | 2.54 | | | $ | 2.39 | |
| | | | | | | | | |
| Barrels of oil equivalent (BOE) | | | 127,863 | | | | 12,449 | |
| Average daily net production (BOE) | | | 350 | | | | 34 | |
| Average Price per BOE | | $ | 26.87 | | | $ | 29.67 | |
| (1) | Includes proceeds from the sale of natural gas liquids (“NGL’s”) |
costs above are calculated by dividing production costs by total production in BOE. | | | For the Year Ended
December 31, | |
| | | 2016 | | | 2015 | |
| Production costs per BOE | | $ | 9.75 | | | $ | 15.70 | |
| Production taxes per BOE | | | (1.30 | ) | | | 2.24 | |
| Depreciation, depletion, and amortization per BOE | | | 12.25 | | | | 46.93 | |
| Total operating costs per BOE | | $ | 20.70 | | | $ | 64.87 | |
| Gross margin per BOE | | $ | 6.17 | | | $ | (35.20 | ) |
| Gross margin percentage | | | 23 | % | | | (119 | )% |
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
amortizationDrilling Activity
amortization:
|
| | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Production costs per BOE | $ | 10.79 |
| | $ | 9.51 |
| | $ | 12.21 |
|
| Production taxes per BOE | 1.77 |
| | 2.05 |
| | 2.06 |
|
| Depreciation, depletion, and amortization per BOE | 17.85 |
| | 14.00 |
| | 12.21 |
|
| Impairment of oil and gas properties per BOE | 122.60 |
| | — |
| | 18.26 |
|
| Total operating costs per BOE | $ | 153.01 |
| | $ | 25.56 |
| | $ | 44.74 |
|
Acreage
The following table sets forth our approximate gross and net developed and undeveloped leasehold acreage as of December 31, 2019:
|
| | | | | | | | | | | | | | | | | |
| | Undeveloped Acreage | | Developed Acreage | | Total |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Delaware Basin | 15,250 |
| | 8,050 |
| | 12,670 |
| | 11,512 |
| | 27,920 |
| | 19,562 |
|
On February 28, 2020, the Company closed the sale of approximately 1,185 undeveloped net acres in Lea County, New Mexico, for net cash proceeds of approximately $24.1 million, subject to customary purchase price adjustments.
Undeveloped Acreage Expirations
Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the net undeveloped acreage, as of December 31, 2019, that will expire over the next three years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates:
|
| | | | | | | | |
| | 2020 | | 2021 | | 2022 |
| Delaware Basin | 5,670 |
| | 1,570 |
| | 90 |
|
As of the date of this Annual Report, leases holding 1,285 net acres in Reeves County and 593 net acres in Winkler County have expired in 2020. We have additional acreage that may expire depending on the timing and availability of capital for continued development of our leasehold acreage and lease renewals.
Our undeveloped leasehold acreage at December 31, 2019 was 15,250 gross (8,050 net) acres, of which 5,670 net acres have expiration dates in 2020 and will expire if the Company does not obtain necessary funding to either extend the leases or begin drilling before their expiration dates, less 560 net leasehold acres as part of the February 28, 2020 Lea County, New Mexico leasehold divestiture. As a result of the uncertainty regarding the availability of capital to fund drilling operations or extend leases holding undeveloped acreage, we recorded $56.2 million of impairments for undeveloped acreage for the year ended December 31, 2019.
Productive Wells
As of December 31,
2016, we have drilled 1.2 net productive wells.As of December 31, 2016 and 2015,2019, we had working interests in 3518 gross (21(14.8 net) oil wells and 623 gross (1.27(19.8 net) wells, respectively. 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,
but are currently shut-in.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.
Acreage
Drilling Activity
For the year ended December 31, 2019, we drilled 5 gross (4.4 net) horizontal wells in the Delaware Basin. We completed and placed on production 7 gross (5.4 net) horizontal wells. As of December 31,
2016, we owned 36 producing2019, 4 gross (3.8 net) wells
within the Delaware Basin in Texaswere drilled but not yet completed. All of these wells were successful, and
New Mexico and in the DJ Basin in Colorado, as well as approximately 34,858 gross (19,968 net) acres, of which 25,752 gross (14,994 net) acresnone were
classified as undeveloped acreage. Our primary assets included acreage located in Winkler and Loving Counties in Texas, Lea County in New Mexico; Laramie and Goshen Counties in Wyoming; Banner, Kimball, and Scotts Bluff Counties in Nebraska; and Weld, Arapahoe and Elbert Counties in Colorado.As of December 31, 2015, we owned 8 producing wells in Wyoming, Nebraska and Colorado within the DJ Basin, as well as approximately 18,000 gross (16,000 net) acres, of which 10,000 gross (8,000 net) acres were classified as undeveloped acreage. Our primary assets included acreage located in Laramie and Goshen Counties in Wyoming; Banner, Kimball, and Scotts Bluff Counties in Nebraska; and Weld, Arapahoe and Elbert Counties in Colorado.
a dry hole.
The following table sets forth
our gross and net developed and undeveloped acreage asinformation with respect to the number of
December 31, 2016 and 2015:| | | Undeveloped | | | Developed | |
| | | Gross | | | Net | | | Gross | | | Net | |
| DJ Basin | | | 16,678 | | | | 13,576 | | | | 1,923 | | | | 678 | |
| Delaware Basin | | | 9,074 | | | | 1,418 | | | | 7,183 | | | | 4,295 | |
| Total acreage as of December 31, 2016 | | | 25,752 | | | | 14,994 | | | | 9,106 | | | | 4,973 | |
| | | | | | | | | | | | | | | | | |
| DJ Basin | | | 10,000 | | | | 8,000 | | | | 8,000 | | | | 8,000 | |
| Total acreage as of December 31, 2015 | | | 10,000 | | | | 8,000 | | | | 8,000 | | | | 8,000 | |
Aswells drilled during the years indicated. Each of March 1, 2017, our inventory of developed and undeveloped acreage includes approximately 40,618 gross (21,178 net) acres, of which 9,106 gross (5,248 net) acres that are held by production. We will continue to pursue additional properties, acquire other properties primarily targetedthese wells was drilled in the Delaware Basin but potentially throughout North America,in the Permian Basin.
|
| | | | | | | | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Exploratory: | | | | | | | | | | | |
| Productive | 5 |
| | 4.4 |
| | 9 |
| | 8.7 | | 5 |
| | 4.2 |
| Dry | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Development: | | | | | | | | | | | |
| Productive | — |
| | — |
| | 6 |
| | 5.6 | | — |
| | — |
|
| Dry | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total: | | | | | | | | | | | |
| Productive | 5 |
| | 4.4 |
| | 15 |
| | 14.3 | | 5 |
| | 4.2 |
| Dry | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Present Activities
As of December 31, 2019, we had no wells in the process of drilling, completing, dewatering or drill wellsshut-in awaiting infrastructure.
Title to Properties
We generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests. Prior to commencement of operations on
such acreage, a thorough title examination will usually be conducted, and any significant defects will be remedied before proceeding with operations. We believe the title to our
coreleasehold properties
is good, defensible and customary with practices in the oil and natural gas industry, subject to
holdsuch exceptions that we believe do not materially detract from the
property by production if financing is available to ususe of such properties. We have identified title defects during 2018 and
the2019 which resulted in impairment of undeveloped acreage costs and further title defects may exist which would result in impairment of undeveloped acreage costs. Our properties are
economic.Titlepotentially subject to Properties
Approximately 66%customary royalty and other interests, liens for current taxes, and other burdens which do not materially interfere with the use of or affect our leasehold interests are held by production, withcarrying 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. The credit agreement was entered into on September 29, 2016 (the “Credit Agreement”) by and among our wholly-owned subsidiaries, Brushy, ImPetro Operating, LLC, a Delaware limited liability company (“Operating”) and ImPetro Resources, LLC, a Delaware limited liability company (“Resources”, and together with Brushy and Operating, the “Borrowers”), and the lenders party thereto (each a “Lender” and together, the “Lenders”) and T.R. Winston & Company, LLC acting as collateral agent. We believe the security interests granted in
With respect to our properties
doof which we are not
materially interferethe record owner, we rely on contracts with the
useowner or operator of
the property or
affectassignment of leases, pursuant to which, among other things, we generally have the
value of, such properties.Marketing and Pricing
We derive revenue and cash flow principally from the sale ofright to have our interest placed on record.
Competitive Business Conditions
The oil and natural
gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas. Prices may also affect the amount of cash flow available for capital expenditures and other cash requirements and our ability to borrow money or raise additional capital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of natural gas and crude oil. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:
| · | changes in global supply and demand for oil and natural gas; |
| · | the actions of the Organization of Petroleum Exporting Countries; |
| · | the price and quantity of imports of foreign oil and natural gas; |
| · | acts of war or terrorism; |
| · | political conditions and events, 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; |
| · | technological advances affecting energy consumption; |
| · | transportation options from trucking, rail, and pipeline; and |
| · | the price and availability of alternative fuels. |
Furthermore, regional natural gas, condensate, oil and NGL prices may move independently of broad industry price trends. 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.
From time to time, we may enter into derivative contracts. These contracts economically hedge our exposure to decreases in the prices of oil and natural gas. Hedging arrangements may expose us to risk of significant financial loss in some 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. |
In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. As of December 31, 2016, we had no hedging agreements in place.
Major Customers
Our major customers for the year ended December 31, 2016 include Noble Energy, Inc., Texican Natural Gas Company, and Energy Transfer Partners, L.P., who accounted for approximately 41%, 38%, and 16% of our revenue for the year ended December 31, 2016, respectively. Our major customers for the year ended December 31, 2015 include, Shell Trading (US) Company, PDC Energy, Inc., and Noble Energy, Inc., who accounted for approximately 43%, 26%, and 21% of our revenue for the year ended December 31, 2015, respectively. We do not believe that the loss of any single customer would materially affect our business because there are numerous other potential purchasers of our production.
Seasonality
Generally, but not always, the demand and price levels for natural gas increase during colder winter months and decrease during warmer summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity has placed increased demand on storage volumes. Demand for crude oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are much more driven by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. The impact of seasonality on crude oil has been somewhat magnified by overall supply and demand economics attributable to the narrow margin of production capacity in excess of existing worldwide demand for crude oil.
Competition
The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties. We believe our leasehold position provides a solid foundation for an economically robust exploration program and our future growth. Our success and growth also depends on our geological, geophysical, and engineering expertise, design and planning, and our financial resources. We believe the location of our acreage, our technical expertise, available technologies, our financial resources and expertise, and the experience and knowledge of our management enables us to compete effectively in our core operating areas. However, we face intense competition from a substantial number of major and independent oil and natural gas companies, many of which have larger technical staffs and greater financial and operational resources than we do.
resources. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects. We also compete with other oil and natural gas companies in attempting to secure drilling rigs and other equipment and services necessary for the drilling, completion, production, processing and maintenance of wells. Consequently,our wells, and we maycould face shortages or delays in securing these services from time to time. time if availability is limited. In addition, we compete to hire and retain professionals, including experienced geologists, geophysicists, engineers, and other professionals and consultants. We believe the location of our acreage, our technical expertise, available technologies, our financial resources, and the experience and knowledge of our management enables us to compete effectively in our core operating areas, but we recognize that many of our competitors have greater financial and operational resources.
The oil and
natural gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas. Competitive conditions may also be affected by future new energy, climate-related, financial, and other policies, legislation, and regulations.
In addition,
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 competeare directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for people, includingoil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs. The price of oil and natural gas has fallen significantly since the beginning of 2020, due in part to failed Organization of Petroleum Exporting Countries (“OPEC”) negotiations as well as concerns about the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil and gas. The resulting precipitous decline in oil and gas pricing experienced geologists, geophysicists, engineers,during March 2020, through the date of this Annual Report, if prolonged. or a further deterioration of the market price for oil and other professionalsnatural gas, will further negatively impact our ability to continue to operate as a going concern.
We have an active hedging program to mitigate risk regarding our cash flow and consultants. Throughoutto protect returns from our development activity in the event of decreases in the prices received for our production; however, hedging arrangements may expose us to risk of significant financial loss in some circumstances and may limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs.
Major Customers
We sell our production to a small number of customers which is common in the oil and natural gas industry,industry. The following table outlines our major customers and their percentage contribution to our total revenues for the needyears ended December 31, 2019 and 2018:
|
| | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| Texican Crude & Hydrocarbon, LLC | | 19 | % | | 87 | % |
| ARM Energy Management, LLC | | 68 | % | | — | % |
| Lucid Energy Delaware, LLC | | 12 | % | | 10 | % |
| ETC Field Services LLC | | 1 | % | | 2 | % |
| | | 100 | % | | 100 | % |
Delivery Commitments
ARM Sales Agreement
On August 2, 2018, the Company executed a five-year agreement with SCM Crude, LLC, an affiliate of Salt Creek Midstream, LLC (“SCM”), to
attractsecure firm takeaway pipeline capacity and
retain talented people has grownpricing on a long-haul pipeline to the Gulf Coast region commencing July 1, 2019. On March 11, 2019, the agreement was replaced with a five-year agreement between the Company and ARM Energy Management, LLC (“ARM”), a related company to SCM. The new agreement accelerated the start date to March 2019 and guarantees firm takeaway capacity on a long-haul pipeline to Corpus Christi, Texas, once completed, at a
time whenspecified price. Under the
numberterms of
talented people available is constrained. We are not insulated from this resource constraint, and we must compete effectively in this market in orderthe new contract, the Company received pricing differentials on the crude oil sales contract subject to minimum quantities of crude oil to be
successful.delivered as follows:
|
| |
| Date | Quantity (Barrels per Day) |
| March 2019 - June 2019 | 5,000 |
| July 2019 - December 2019 | 4,000 |
| January 2020 - June 2020 | 5,000 |
| July 2020 - June 2021 | 6,000 |
July 2021 - December 2024 (1) | 7,500 |
(1) Extending to the later of December 2024 or 5 years from the EPIC Crude Oil pipeline in-service date (no later than June 2025).
Further, ARM has agreed to purchase crude from the Company based upon Magellan East Houston pricing with a fixed “differential basis”. As of December 31, 2019, the agreement no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under
the contract and the net settlement criteria being met. See Note 9 - Derivatives to our consolidated financial statements for information regarding the recognition of the net settlement mechanism as an embedded derivative over the remainder of the contract.
Regulation of the Oil and Natural Gas Industry
General.
General
Our operations covering the exploration, production and sale of oil and natural gas exploration, production, and related operations are subject to various types ofextensive federal, state and local laws and regulations. These laws and regulations, which are under continual review for amendment, include matters relating to drilling and production practices; the disposal of water from operations and the processing, handling and disposal of hazardous materials; bonding, permitting and licensing, and reporting requirements; taxation; and marketing, transportation and pricing practices.
The failure to comply with these laws and regulations
cancould result in substantial
penalties, including administrative, civil, or criminal penalties. These laws and regulations
materially impactincrease our
operationscost of doing business and can
potentially affect our profitability.
However, we do not believe that these laws and regulations affect us in a manner significantly different than our competitors. Matters regulated include, but are not limited to, permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells and unitization and pooling of properties, restoration of surface areas, plugging and abandonment of wells, requirements for the operation of wells, production and processing facilities, land use, subsurface injection, air emissions, the disposal of fluids used or other wastes obtained in connection with operations, the valuation and payment of royalties and taxation of production. At various times, regulatory agencies have imposed price controls and limitations on production. In order to conserve supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding production. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and natural gas, by-products from oil and natural gas and other substances and materials produced or used in connection with oil and natural gas operations. While we believe that we will be able to substantially comply with all applicable laws and regulations through our strict attention to regulatory compliance, the requirements of such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the FERC and the courts. We cannot predict when or whether any such proposals may become effective. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.
Regulation of Production of Oil and Natural Gas.
The production of oil and natural gas is subject to regulation under a wide range of
local,federal, state and
federal statutes, rules,local laws, orders and regulations.
Federal, state and localThese statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations.
WeThe states in which we own
interests inand operate properties
located in Texas, which regulates drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of Texas also govern a number ofhave 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
orso as to have reductions in well spacing or density.
Moreover, Texas imposes a 4.6% severance tax on oil productionWe believe we are in substantial compliance with these laws and
a 7.5% severance tax on natural gas production. The failureregulations; however, should we fail to comply with these
ruleslaws and regulations,
can result inwe could face substantial penalties.
Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Environmental, Health, and Safety Regulations.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 safetysafety. There are various governmental agencies, including the U.S. Environmental Protection Agency (“EHS”EPA”). We are committed, the U.S. Occupational Safety and Health Administration (“OSHA”) and analogous state agencies, that have the authority to strictenforce compliance with these regulationslaws and the utmost attention to EHS issues.regulations. Environmental laws and regulations may require that permits be obtained before drilling commences or facilities are commissioned,commissioned; restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities,activities; govern the handling and disposal of waste material,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. As a result, these laws and regulations may substantially increase
We do not believe that our environmental risks are materially different from those of comparable companies in the costs of exploring for, developing, or producing oil and natural gas and may prevent or delay the commencement or continuation of certain projects. In addition, these laws and regulations may impose substantial clean-up, remediation, and other obligationsindustry. We believe our present activities substantially comply, in the event of any discharges or emissions in violation of theseall material respects, with existing environmental laws and regulations. Further, legislativeNevertheless, environmental laws may result in a curtailment of production or material increases in the cost of production, development or exploration, and regulatory initiativesmay otherwise adversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks are generally not fully insurable. We are committed to strict compliance with these regulations. During the years ended December 31, 2019 and 2018, we incurred approximately $220,000 and approximately $38,000, respectively, related to global warming or climate change could have an adverse effect oncompliance with environmental laws for our operations and the demand for oil and natural gas. See “Risk Factors-Risks Relating to the Oil and Gas Industry-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.” gas properties.
The following is a summary of the more significant existing and proposed environmental and occupational health and safety laws and regulations to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial
position. During the years ended December 31, 2016 and 2015, we incurred $182,000 and $130,000, respectively, related to compliance with environmental laws for our DJ Basin.position:
The Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, of 1976, 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. At present, theThe RCRA includes an exemption that allowsfor certain oil and natural gas exploration and production waste to be classifiedfrom regulation as nonhazardoushazardous 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. For example,Most recently, in 2010, a petition was filed byApril 2019, EPA concluded that rescinding the Natural Resources Defense Council (“NRDC”) with the Environmental Protection Agency (“EPA”) requesting that the agency reassess its prior determination that certainRCRA exploration and production wastes arewaste exemption was not subjectnecessary “at this time”.
In the event that we fail to
comply with requirements for the
RCRAmanagement of hazardous waste,
requirements. The EPA has not yet acted on the petition. On May 5, 2016, moreover, the NRDC, alongadministrative, civil and/or criminal penalties can be imposed. We believe that we are in substantial compliance with
other environmental organizations, commenced a lawsuit against the EPA, asking the U.S. District Court for the District of Columbiacurrent applicable requirements related to
order the agency to “revise” its RCRA regulations as they pertain to oil and gas wastes. On December 28, 2016, the court signed a consent decree, resolving the lawsuit, under which the EPA agreed that, by March 15, 2019, it will either sign a notice of proposed rulemaking for a revision of its RCRA regulations as they pertain to oil and gas wastes (in which case it will take a final action on the proposed rulemaking by July 15, 2021) or sign a determination that no such revision is necessary.hazardous waste management. Repeal or modification of the RCRA oil and
natural gas exemption,
by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes,
wouldcould increase the volume of hazardous waste we are required to manage and dispose of and
wouldcould cause us to incur
perhaps significantly,potentially significant increased operating expenses.
Water Discharges. The Federal Water Pollution Control Act also(also known as the Clean Water Act), the Safe Drinking Water Act, (the “Clean Water Act”) imposesthe 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 fill and pollutants into regulated waters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and other regulated waters of the United States has complicated, and will continue to complicate and increase the cost of, obtaining such permits or other approvals. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the crude oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain crude oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. 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. TheIn June 2015, the EPA and the U.S. Army Corps of Engineers released a Connectivity Reportjointly promulgated rules redefining the scope of waters protected under the Clean Water Act, and in September 2013, which determined that virtually all tributary streams, wetlands, open water in floodplains and riparian areas are connected. This report supported the drafting of proposed rules providing updated standards for what will be considered jurisdictional waters of the United States. Those rules were finalized on May 27, 2015. Then, on October 9, 2015, in presiding over a challenge to the rules, the U.S. Court of Appeals for the Sixth Circuit stayed them nationwide. It later determined (in FebruaryThe EPA and U.S. Army Corps of 2016) that it has jurisdiction to adjudicate the challenge. In January of 2017, the U.S. Supreme Court accepted an appeal of that determination. In the meantime, the Sixth Circuit’s stayEngineers have resumed nationwide use of the rules remains in place.agencies’ prior regulations defining the term “waters of the United States.” On February 28, 2017, moreover, 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. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.The Oil Pollution Act of 1990 (“
OPA”Oil Pollution Act”) and regulations thereunder
imposeare 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
OPA assigns strict liability toOil 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.
While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by the OPA. In addition, to the extent we acquire offshore leases and those operations affect state waters, we may be subject to additional state and local clean-up requirements or incur liability under state and local laws. The OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. We cannot predict whether the financial responsibility requirements under the OPA amendments will adversely restrict our proposed operations or impose substantial additional annual costs to us or otherwise materially adversely affect us. The impact, however, should not be any more adverse to us than it will be to other similarly situated owners or operators.Safe Drinking Water Act
The Safe Drinking Water Act, of 1974, 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. Class II underground injection wells, a predominant storage method for crude oil and natural gas wastewater, are strictly controlled, and certain wastes, absent an exemption, cannot be injected into such wells. Failure to abide by our permits could subject us to civil or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits. In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well. The RRC requires operators to obtain a permit from the agency for the operation of saltwater disposal wells and establishes minimum standards for injection well operations.
In response to recent seismic events near underground injection wells used for the disposal of oil and
natural gas-related wastewaters, federal and
some state agencies have
begunbeen 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
responseTexas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well. The RRC requires operators to
these concerns, regulators in some states are considering additional requirements related to seismic safety. For example,obtain a permit for the
operation of saltwater disposal wells and establishes minimum standards for injection well operations. The RRC has adopted
new permit rules for injection wells to address these seismic activity concerns within the state.
Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. These
new 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,
these costs are commonly incurred by all oil and gas producers and we do not believe that the costs associated with the disposal of produced water will have a material adverse effect on our operations.
Failure to comply with these regulations may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.
Air Pollutant Emissions. The federal Clean Air Act (the “Clean Air Act”), and comparable state and local air pollution laws, adopted to fulfill its mandate provide a framework for national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws generally require utilization of air emissions control equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. In May 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major
source, which would subject operators to more stringent air permitting processes and requirements. These laws and regulations may increase our costs of compliance, and we may face administrative, civil and criminal penalties if we fail to comply with the requirements of the Clean Air Act and associated state laws and regulations. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.
Over the next several years, we may be required to incur capital expenditures for air pollution control equipment or other air emissions-related issues. The EPA promulgated significant New Source Performance Standards (“NSPS OOOO”) in 2012, as amended in 2013 and 2014, which have added administrative and operational costs. On May 12, 2016, the EPA issued regulations (effective August 2, 2016) that build on the NSPS OOOO standards by directly regulating methane and volatile organic compound (“VOC”) emissions from various types of new and modified oil and gas sources. Some of those sources are already regulated under NSPS OOOO, while others, like hydraulically fractured oil wells, pneumatic pumps, and certain equipment and components at compressor stations, are covered for the first time. On March 10, 2016, moreover, the EPA announced that it is moving towards issuing performance standards for methane emissions from existing oil and gas sources. The agency said that it will “begin with a formal process (i.e., an Information Collection Request) to require companies operating existing oil and gas sources to provide information to assist in the development of comprehensive regulations to reduce methane emissions.” On November 10, 2016, the EPA issued the Information Collection Request (“ICR”) and explained that “[r]ecipients of the operator survey (also referred to as Part 1) will have 60 days after receiving the ICR to complete the survey and submit it to EPA….Recipients of the more detailed facility survey (also referred to as Part 2) will have 180 days after receiving the ICR to complete that survey and submit it to the agency.” On October 1, 2015, under the Clean Air Act, the EPA lowered the national ambient air quality standard for ozone from 75 ppb to 70 ppb. This change could result in an expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.
Along these lines, on October 20, 2016, the EPA finalized Control Techniques Guidelines to reduce emissions from a number of existing oil and gas sources that are located in certain ozone nonattainment areas and states in the Ozone Transport Region (which is comprised of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, Vermont, the District of Columbia, and Northern Virginia). These guidelines will lead to direct regulation of VOC emissions and have the incidental effect of reducing methane emissions. The regulations will take the form of reasonably available control technology requirements.
Regulation of “Greenhouse Gas” EmissionsIn response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the
. The EPA under the Clean Air Act, 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.sources to address findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHG”) present an endangerment to public health and the environment. Facilities required to comply with PSD requirements for their GHG emissions will be required to meet “best available control technology” standards for those emissions, which will be established on a case-by-case basis. EPA rulemakings related to GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, theThe EPA has adoptedalso issued rules requiring the monitoring and reporting of GHG emissions, from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certainthe reporting of our operations. In October 2015, the EPA finalized rules (effective January 1, 2016) that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources includeGHG emissions from gathering and boosting facilities as well assystems, completions and workovers from hydraulically fracturedof oil wells. The revisions also include the additionwells using hydraulic fracturing, and blowdowns of well identification reporting requirements for certain facilities. In addition, as noted above, the EPA has finalized new source performance standards related to methane emissions from the oil and natural gas industry.While Congress has from time to time considered legislation to reduce emissions of GHGs,GHG, there has not been significant activity in the form of adopted federal legislation to reduce GHG emissions at the federal level 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.GHG. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGsGHG from, our equipment and operations could require us to incur costs to reduce emissions of GHGsGHG associated with our operations. In addition, substantial limitations
Restrictions on GHG emissions
that may be imposed could adversely affect
demandour operations and restrict or delay our ability to obtain air permits for
the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrationsnew or modified sources, as well as increase our costs of
GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.
Hydraulic Fracturing Activities. Hydraulic fracturing is an important anda common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight unconventional formations. For additional information about hydraulic fracturing and related regulatory matters, see “Risk Factors-Risks Relating to the Oil and Gas Industry.” Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and additional operating restrictions or delays /cancellations in the completion of oil and gas wells.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.
The discharge of oil, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require us to incur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities of oil and gas wells. Discharged hydrocarbons may migrate through soil to fresh water aquifers or adjoining property, giving rise to additional liabilities.
Several states
including Texas, 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
effective September 1, 2011, requiring oil and
natural gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The RRC adopted rules and regulations implementing this legislation that apply to all wells for which the RRC issues an initial drilling
permit after February 1, 2012.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.
Further, in May 2013, the The RRC also adopted new 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. In addition, the Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The RRC has adopted rules and regulations implementing this legislation that apply to all wells for which the RRC issues an initial drilling permit after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on an internet web site 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.
We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless,activities; however, 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 the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.A variety of federal For additional information about hydraulic fracturing and state lawsrelated regulatory matters, see “Risk Factors-Risks Relating to the Oil and regulations govern the environmental aspects of natural gas and oil production, transportation and processing. These laws and regulations may impose liability in the event of discharges, including for accidental discharges, failure to notify the proper authorities of a discharge, and other noncompliance. Compliance with such laws and regulations may increase the cost of oil and gas exploration, development and production; although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings. Failure to comply with the requirements of the applicable laws and regulations could subject us to substantial civil and/or criminal penalties and to the temporary or permanent curtailment or cessation of all or a portion of our operations.
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. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We could be subject to liability under CERCLA, including for jointly-owned drilling and production activities that generate relatively small amounts of liquid and solid waste that may be subject to classification as hazardous substances under CERCLA.
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
nonetheless handle
other hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary
operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.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.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.
In addition, 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. 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
suchthese 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
(“FWS”) 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.
As a result of a pair of 2011 settlement agreements, the FWS is required to make determinations on whether more than 250 species should be listed as endangered or threatened under the FSA. It must make the determinations by no later than completion of the agency’s 2017 fiscal year. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act.
The federal government has issued indictments under the Migratory Bird Treaty Act to several oil and gas companies after dead migratory birds were found near reserve pits associated with drilling activities. 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.
NEPA
Additionally, significant federal decisions, such as the issuance of federal permits or authorizations for certain oil and gas exploration and production activities may be subject to the National Environmental Policy Act (“NEPA”)
OSHA. The NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. This process has the potential to delay oil and gas development projects.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 any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.
State Laws. There are numerous state laws and regulations in the states where we operate that relate to the environmental aspects of our business. Some of those laws and regulations are discussed above. They relate to, among other things, requirements to remediate spills of deleterious substances associated with oil and natural gas activities, the conduct of salt water disposal operations, and the methods of plugging and abandonment of oil and natural gas wells which have been unproductive. Numerous state laws and regulations also relate to air and water quality.In General
We do not believe that ourwe are in substantial compliance with all state laws governing environmental risks will be materially different from those of comparable companiesmatters and all permitting requirements; however, in the oil and gas industry. We believe our present activities substantiallyevent that we fail to comply in all material respects, with existing environmentalsuch laws, and regulations. Nevertheless, environmental laws may result in a curtailment of production or material increase 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, generally are not fully insurable.
In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.
face substantial penalties and incur significant costs.
Natural Gas Sales and Transportation.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. FERCThe Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. 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.
Commencing in 1985, FERC
has also promulgated a series of orders, regulations and
rule makings that significantly fosteredrules 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.
FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
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.Transportation
Sales of crude oil, condensate and
natural gas liquidsNGLs are not currently regulated and are made at negotiated prices.
Nevertheless, Congress could reenact price controls in the future.Our crude oil sales are affected by the availability, terms and cost of transportation.
The transportation of oil in common carrier pipelines is
also 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.
Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, weWe 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.competitors, as effective interstate and intrastate rates are equally applicable to all comparable shippers.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Federal Income Tax. and State Severance Taxes
Federal income tax laws significantly affect our operations. The principal provisions that affect us are those that permit us, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize/depreciate, our domestic “intangible drilling and development costs” and to claim depletion on a portion of our domestic oil and natural gas properties based on 15% of our oil and natural gas gross income from such properties (up to an aggregate of 1,000 barrels per day of domestic crude oil and/or equivalent units of domestic natural gas).
Additionally, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. Texas and New Mexico currently impose a severance tax on oil production of 4.60% and 8.39%, respectively, and a severance tax on natural gas production of 7.50% and 9.24%, respectively.
Federal Leases. For those operationsLeases
Operations on federal oil and
natural gas leases
such operations must comply with
numerouscertain 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
various federal agencies. In addition, on federal lands in the United States, the Office of Natural Resources Revenue (“ONRR”) prescribes,
or severelyand in some cases limits, the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the
lease. In particular, ONRR prohibitslease, including the deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees.
Further, theThe 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.
The natural gas and crude oil industry as a whole has resisted the proposed rules under an assumption that royalty burdens will substantially increase. We cannot predict what, if any, effect any new rule will have on our operations.
Some of our operations are conducted on federal lands pursuant to oil and
natural gas leases administered by the
BLM.Bureau of Land Management (“BLM”). These leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated.
In May 2010, the BLM adopted changes to its oil and gas leasing program that require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process. These changes have increased the amount of time and regulatory costs necessary to obtain oil and gas leases administered by the BLM. In addition, the BLM, on March 20, 2015, issued its final regulations for hydraulic fracturing on federal and tribal lands. The new regulations require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land. The new regulations become effective on June 24, 2015. BLM has also announced its intention to conduct a separate rulemaking to address venting and flaring of natural gas from oil and gas operations on public land. These hydraulic fracturing-related rulemakings may adversely affect our operations conducted on federal lands.
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,
including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated
byin 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.
To date
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 havecould 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
experienced any material adverse effectall, of the operating risks to which our business is exposed. We evaluate the purchase of insurance, coverage limits and deductibles on
our operations from obligations under environmental, health, and safety laws and regulations. We believe that we are in substantial compliance with currently applicable environmental, health, and safety laws and regulations, and that continued compliance with existing requirements will not have a materially adverse impact on us.an annual basis.
As of December 31, 2016,2019, we had nineteen43 employees, all of whom were full-time employees. Our employees are not represented by any labor union or covered by any collective bargaining agreements.
As a result of layoffs and two part-time employees,furloughs in response to COVID-19 and intend to continue to add additional personnel as our operational requirements grow. current commodity market conditions, the Company currently has 20 active employees.
We
plan to continue to leverage the use ofalso retain certain independent consultants and contractors to provide various professional services, including additional land, legal, engineering, geology, environmental and tax
services.services on a contract or fee basis as necessary for our operations. Available Information
We have closed our
Principal Executive Office and Corporate Offices
Our principal executive offices are in Denver, Colorado on February 28, 2017 and moved our corporate headquarter to 300 E. Sonterra Blvd.,leased office space located at 201 Main St, Suite No. 1220, San Antonio, Texas 78258,700, Fort Worth, TX 76102, and our telephone number is (210) 999-5400. (817) 585-9001.
Availability of Company Reports
Our web site is www.lilisenergy.com. Additional information that may be obtained through our web site does not constitute part of this Annual Report on Form 10-K. Our Annual Reportsannual reports on Form 10-K, Quarterly Reportsquarterly reports on Form 10-Q, Current Reportscurrent reports on Form 8-K and amendments to those reports are accessible freefiled or furnished pursuant to Section 13(a) or 15(d) of chargethe Exchange Act of 1934 will be available through our Internet website at our website.https://www.lilisenergy.com as soon as reasonably practical after we electronically file such material with, or furnish it to, the SEC. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov. The information on, or that can be accessed through, our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report or incorporated into any of our other filings at www.sec.gov.with the SEC.
Item 1A. Risk Factors
Investing in our shares
Our business involves a high degree 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 shares.risk. You should carefully consider all of the risks described in this Annual Report, on Form 10-K, in addition to the other information contained in this Annual Report. If any of the following risks, or any risk described elsewhere in this Annual Report, on Form 10-K, before you make an investment inactually occur, our business, prospects, financial condition, results of operations, or cash flows could be materially adversely affected. In any such case, the trading price of our common stock.stock could decline. Additional risks not presently known to us or that we currently deem immaterial may also adversely affect our business.
Risks Relating to Our Business
Failure to comply with any of the financial covenants contained in our Revolving Credit Agreement could cause an event of default and have a material adverse effect on our business.
Our Revolving Credit Agreement (hereinafter defined and described in more detail) requires the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter. See Note 10 to our consolidated financial statements in this Annual Report for a more detailed description of these financial covenants. Failure to comply with these covenants could cause an event of default under our Revolving Credit Agreement and have a material adverse effect on our business.
As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. A failure to comply with the covenants, ratios or tests in our Revolving Credit Agreement, or any future indebtedness, including borrowing base deficiency payments, could result in an event of default. If an event of default occurs and is not cured or waived, our lenders, (i) would not be required to lend any additional amounts to us, (ii) could elect to declare all outstanding borrowings, together with accrued and unpaid interest and fees to be due and payable, (iii) could require us to apply all of our available cash to repay these borrowings and (iv) could prevent us from making debt service payments under our other agreements. A potential event of default and subsequent acceleration of indebtedness would have a material adverse effect on our business, financial condition and results of operations, and raises substantial doubt about our ability to continue as a going concern.
We have identified conditions and events that raise doubt about our ability to continue as a going concern.
We have incurred losses and negative cash flows from operating activities for the years ended December 31, 2019 and 2018 and, as of December 31, 2019, and we had a stockholders’ deficit of $238.2 million. We anticipate negative operating cash flows to continue for the foreseeable future due to, among other things, significant uncertainty in the outlook for oil and gas development and external market pressures due to the effects of pandemics, epidemics and other global health concerns such as the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil and gas that are not within our control. For example, the price of oil and natural gas has fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations and to concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil. As of December 31, 2019, our cash and cash equivalents was $3.8 million and our working capital deficit was $143.5 million. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants, among other waivers of default, as of December 31, 2019. In addition, we currently have no availability for borrowing under our Revolving Credit Agreement.
As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. The Company does not expect to be in compliance with debt covenants in future periods without additional sources of liquidity or future amendments to the Revolving Credit Agreement.
We have been unable to secure further sources of liquidity, and as a result, substantial doubt exists about our ability to continue as a going concern as of the date of the filing of this Annual Report and our auditors have included a going concern paragraph in their Report of Independent Registered Public Accounting Firm. The accompanying consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of recorded assets, or the amounts and classification of liabilities that might be different should we be unable to continue as a going concern based on the outcome of these uncertainties described above. If we are unable to continue as a going concern, we may have to liquidate our assets and may receive less than the value at which those assets are carried on our audited financial statements, and it is likely
that investors will lose all or a part of their investment. See Note 2 - Liquidity and Going Concern to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this Annual Report for further detail.
Our ability to continue as a “going concern” contemplates the realization of assets and satisfaction of liabilities in the normal course of business, including the effective implementation and success of management’s plans to mitigate the conditions that raise substantial doubt about our ability to continue as a going concern.
Our consolidated financial statements included in Item 8 of this Annual Report have been presented on the basis that we would continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. Our liquidity and ability to comply with debt covenants under our Revolving Credit Agreement have been negatively impacted by the recent decrease in commodity prices, which have fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil and gas. As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants and the Company will not be in compliance in future periods without additional sources of liquidity. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt Concern to our consolidated financial statements in this Annual Report), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. The uncertainty related to our continued operations, liquidity, and compliance with the financial covenants under our Revolving Credit Agreement raises substantial doubt regarding our ability to continue as a going concern. The consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern.
In order to continue to improve our leverage position and current ratio to meet the financial covenants under the Revolving Credit Agreement and satisfy the borrowing base deficiency payment, we are currently pursuing or considering a number of actions, which in certain cases may require the consent of current lenders and stockholders. In November 2019, our board of directors formed a committee of independent directors (the “Special Committee”) tasked with reviewing and evaluating strategic alternatives that may enhance the value of the Company, including alternatives that may be available to identify and access further sources of liquidity. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters.
The Special Committee continues to explore other financing alternatives and deleveraging transactions. We are also addressing operational matters identifiedsuch as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs, and we intend to continue to pursue and consider other strategic alternatives.
There can be no assurance that we will be able to implement any of these plans successfully, or describedthat such plans, if executed, will result in compliance with our Revolving Credit Agreement covenants or allow us to continue as a going concern.
Oil, natural gas and NGL prices are highly volatile. If commodity prices continue to experience substantial decline, our operations, financial condition, and level of expenditures for the development of our oil, natural gas and NGL reserves may continue to be materially and adversely affected.
The prices we receive for our oil, natural gas, and NGL production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, natural gas, and NGLs are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.
Historically, the commodities markets have been volatile, and these markets will likely continue to be volatile in the future. The price of oil has fallen approximately $43.00 a barrel based on WTI from December 31, 2019 to the date of this Annual Report, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil. If these reduced prices continue or if prices of oil, natural gas and NGLs experience additional substantial decline, our operations, financial condition and level of expenditures for the development of our oil, natural gas and NGL reserves may continue to be materially and adversely affected. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, including:
changes in global supply and demand for oil and natural gas;
the ability and willingness of the OPEC and non-OPEC countries, such as Russia, to set and maintain production levels and prices for oil and the other actions of OPEC;
the price and quantity of imports of foreign oil and natural gas;
political conditions, including embargoes, affecting oil-producing activity;
the level of global oil and natural gas exploration and production activity;
the level of global oil and natural gas inventories;
weather conditions;
technological advances affecting energy consumption
the price and availability of alternative fuels; and
epidemics, pandemics or other major public health issues, such as COVID-19.
Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gas that we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In addition, we may be required to record asset carrying value write-downs if prices remain low. The current low prices of oil and natural gas or an additional significant decline in the prices of oil and natural gas will adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.
We are analyzing and evaluating strategic alternatives to address our capital structure and there can be no assurance that we will be successful in identifying, undertaking or completing any strategic alternative, that any such strategic alternative will address our capital structure and not have a negative impact on our stockholders or that the process will not have an adverse impact on our business.
In November 2019, we formed the Special Committee as part of a process to analyze and evaluate various strategic alternatives to address our capital structure and to position us for future success. The Special Committee continues to explore other financing alternatives and deleveraging transactions. The process of reviewing strategic alternatives may be time consuming and disruptive to our business operations and, if we are unable to effectively manage the process, our business, financial condition and results of operations could be adversely affected. We could incur substantial expenses associated with identifying and evaluating potential strategic alternatives. No decision has been made with respect to any strategic alternative and we cannot assure you that we will be able to identify, undertake and complete any strategic alternative that will address our capital structure and not have a negative impact on our stockholders or provide any guidance on the timing of such action, if any.
Any potential strategic alternative would be dependent upon a number of factors that may be beyond our control. We do not intend to comment regarding the evaluation of strategic alternatives until such time as we have determined that further disclosure is necessary or appropriate. As a consequence, perceived uncertainties related to our future may result in the loss of potential business opportunities and may make it more difficult for us to attract and retain qualified personnel and business partners.
Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting our obligations under our indebtedness.
We entered into the Revolving Credit Agreement in 2018. As of December 31, 2019, $115.0 million was outstanding under our Revolving Credit Agreement. As provided for in the Seventh Amendment to the Revolving Credit Agreement, and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million. The reduction in the borrowing base resulted in a borrowing base deficiency of $25.0 million. We have made scheduled repayments of $17.3 million and pursuant to the Fourteenth Amendment to the Revolving Credit Agreement, the remaining $7.8 million is due on June 5, 2020.
We may incur additional debt, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity and develop and acquire properties to the extent desired. If we are able to utilize our credit facilities in the future or if we obtain additional financing, our level of indebtedness could affect our operations, including limiting our ability to obtain additional debt or equity financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes. Additionally, if we increase our indebtedness, the debt service requirements of the additional indebtedness could make it more difficult for us to satisfy our financial obligations; and a substantial portion of our cash flows from operations would be dedicated to the payment of principal and interest on our indebtedness and would not be available for other purposes, including our operations, capital expenditures and future business opportunities. A higher level of indebtedness and/or preferred stock also increases the risk that we may default on our obligations.
The UK’s Financial Conduct Authority, or FCA, which regulates LIBOR, stated on July 27, 2017, that following 2021 it will no longer encourage panel banks to contribute to LIBOR, as it has done to date. Borrowings under our Revolving Credit Agreement bear interest at a floating rate of either LIBOR or a specified base rate plus a margin determined based upon the usage of the borrowing base. In the event LIBOR becomes unavailable prior to the maturity of our Revolving Credit Agreement, the rate of interest payable on our Revolving Credit Agreement may change. Uncertainty regarding the future of or changes to LIBOR or the unavailability of LIBOR could adversely affect our financial condition.
The Revolving Credit Agreement and Second Lien Credit Agreement, guaranteed and further secured by ussubstantially all our assets, contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.
Our Revolving Credit Agreement and Second Lien Credit Agreement contain restrictive covenants that limit our ability to, among other things:
incur additional indebtedness;
create additional liens;
incur fundamental changes;
sell certain of our assets;
merge or consolidate with another entity;
pay dividends or make other distributions;
engage in transactions with affiliates; and
enter into certain swap agreements.
The requirement that we comply with these provisions may have a material adverse effect on our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.
We may from time to time enter into alternative or additional debt agreements that contain restrictive covenants that may prevent us from taking actions that we believe would be in filingsthe 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 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 resultscompanies that are reflectednot similarly restricted.
In addition, our Revolving Credit Agreement requires us to maintain certain financial ratios. We may from time to time be out of compliance with covenants under our debt agreements, which will require us to seek waivers from our lenders. In connection with the preparation of this Annual Report and the associated financial statements, the Company became aware, and promptly informed its Lenders, that it did not satisfy the current ratio and leverage ratio covenants in any forward-looking statement. Somethe Revolving Credit Agreement, as of the fiscal quarter ended December 31, 2019. Accordingly, the Company requested that our lenders consent to a waiver with respect to such provision. On March 30, 2020, the Company entered into that certain Twelfth Amendment and Waiver to Second Amended and Restated Credit Agreement, whereby our lenders granted a waiver with respect to the breach of the leverage ratio and current ratio covenants, among other waivers of default. As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. If we fail to comply with these important factors, but not necessarilyprovisions 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 important factors, include the following:Risks Relatingfunds borrowed thereunder to Our Business
be due and payable, together with the accrued and unpaid interest, and the lenders under or Revolving Credit Agreement could elect to terminate their commitments thereunder.
If we are not ableunable 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
significant amounts, we may not be able to develop our current prospectsdecreased production and
properties, or we may forfeit our interest in certain prospects and we may not be able to continue to operate our business.
proved reserves over time.
We
need significant additional capital to continue to operate our properties and continue operations. Currently, a significant portion of our revenue after field level operating expenses is required to be paid to our lenders as debt service.In the near term, we intendplan to finance our capital expenditures with cash on hand, cash flow from operations sales of non-core property assets,and future issuanceissuances of debt and/or equity securities and entry into a new credit facility.securities. Our cash flow from operations and access to capital is subject to a number of variables,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 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 other capital resources may not provide cash in sufficient amountsfunds to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 20172020 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, sales of non-core property assets, offerings of debt or equity securities or other means.
Our undeveloped leasehold acreage with expiration dates in 2020 at December 31, 2019 was 5,670 net acres and will expire if the Company does not obtain necessary funding to either extend the leases or begin drilling before their expiration dates. As a result, we have recorded an impairment of unproved leasehold of $56.2 million during the year ended December 31, 2019.
As of the date of this Annual Report, leases holding 1,285 net acres in Reeves County and 593 net acres in Winkler County have expired in 2020. We
have additional acreage that may
not be able to obtain debt or equity financingexpire depending on
terms favorable, or at all.If we are unable to fund ourthe timing and availability of capital requirements, we may be required to curtail our operations relating to the exploration andfor continued development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or may be otherwise unable to implement their development plan, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings. The occurrence of such events may prevent us from continuing to operate our business and our common stock and preferred stock may not have any value.
We have substantial liquidity needs and may be required to seek additional financing to fund our 2017 capital budget. If we are unable to obtain financing on satisfactory terms or maintain adequate liquidity, our ability to fund our capital budget, replace our proved reserves or to maintain production levels and generate revenue will be limited.
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 Series A preferred and Series B preferred notes. Our capital program will require additional financing above the level of cash generated by our operations to fund 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 face uncertainty regarding the adequacy of our liquiditylease renewals.
Värde Partners, Inc., its portfolio companies, and
capital resources to fund our 2017 capital budget. Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to maintain adequate cash on hand, including our ability to access additional financing, and (ii) our ability to generate cash flow from operations. Our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control. We can provide no assurance that additional financing will be available or, if available, offered to us on acceptable terms. Given our existing debt and the estimated value of our proved reserves on December 31, 2016, we do not expect to have access to reserve-based revolving debt capacity during 2017. As a result, our access to additional financing is, and for the foreseeable future will likely continue to be, dependent up our access to new equity and equity-linked capital. As a result, the adequacy of our capital resources is difficult to predict at this time
Oil, NGL and natural gas prices are volatile and have declined significantly from levels experienced in recent years. If commodity prices experience a further, substantial decline, our operations, financial condition, and level of expenditures for the development of our oil, NGL, and natural gas reserves may be materially and adversely affected.
The prices we receive for our oil, NGLs, and natural gas production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, NGLs, and natural gas 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, NGLs, and natural gas experience a further, substantial decline, our operations, financial condition and level of expenditures for the development of our oil, NGLs, and natural gas 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 and include the following:
| · | the level of global exploration and production; |
| · | the level of global inventories; |
| · | the ability and willingness of members of the Organization of the Petroleum Exporting Countries to agree to and maintain oil price and production controls; |
| · | worldwide and regional economic conditions affecting the global supply and demand for oil, NGLs and natural gas; |
| · | the price and quantity of imports of foreign oil, NGLs and natural gas; |
| · | political and economic conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia; |
| · | prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices; |
| · | the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices; |
| · | localized and global supply and demand fundamentals and transportation availability; the cost of exploring for, developing, producing and transporting reserves;
weather conditions and other natural disasters;
technological advances affecting energy consumption; |
| · | the price and availability of alternative fuels;
expectations about future commodity prices; and
domestic, local and foreign governmental regulation and taxes. |
Lower commodity prices may reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of oil, NGLs, and natural gas that we can produce economically, andits affiliates (collectively, “Värde”) beneficially own a significant portion of our exploitation, developmentcommon stock. Värde is not limited in their ability to compete with us, and exploration projects could become uneconomic. This may resultthe waiver of the corporate opportunity provisions in our having to make significant downward adjustmentsthe certificates of designation relating to our estimated proved reserves.Series C Preferred Stock, Series D Preferred Stock, Series E Preferred Stock, and Series F Preferred Stock, may allow Värde to benefit from corporate opportunities that might otherwise be available to us. As a result, if commodity prices remain depressed for a lengthy periodconflicts of time or experience a further substantial or extended decline, ourinterest could arise in the future business, financial condition, results of operations, liquidity, or ability to finance planned capital expenditures may be materiallybetween us and adversely affected.
Our level of indebtedness could adversely affect our ability to raise additional capital to fundVärde concerning conflicts over our operations limitor business opportunities.
Värde is a family of private investment funds that beneficially owns a significant portion of our
abilitycommon stock as a result of the conversion rights available to
react to changesthem under the Series E Preferred Stock (as hereinafter defined and described). Värde also has investments in other companies in the
economyenergy industry. The certificates of designation governing the preferences, rights and limitations of the Series E Preferred Stock provide that Värde is not restricted from owning assets or
our industry and prevent us from meeting our obligations under our indebtedness.On September 29, 2016, we entered into the Credit Agreementengaging in businesses that provides for a three-year senior secured term loancompete directly or indirectly with an aggregate principal amount of $31.0 million outstanding as of December 31, 2016, and $38.1 million outstanding as of March 1, 2017. We may borrow up to an aggregate principal amount of $50 million under the Credit Agreement. Our degree of leverage could have important consequences, including the following:
| · | it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, further exploration, debt service requirements, acquisitions and general corporate or other purposes; |
| · | a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest on our indebtedness and will not be available for other purposes, including our operations, capital expenditures and future business opportunities; |
| · | the debt service requirements of other indebtedness in the future could make it more difficult for us to satisfy our financial obligations; |
| · | we could be vulnerable to any downturn in general economic conditions and in our business, and we could be unable to carry out capital spending and exploration activities that are currently planned; and |
| · | 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, which may be difficult to obtain. |
We may incur additional debt, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity and develop and acquire propertiesus. In particular, subject to the extent desired. A higher levellimitations of indebtedness and/applicable law, if Värde, or preferred stock increases the risk that we may default on our obligations. Our ability to meet our debt obligations and to reduce our levelany agent, shareholder, member, partner, director, officer, employee, investment manager or investment advisor of indebtedness depends on our future performance. General economic conditions, natural gas and oil prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. Factors that will affect our ability to raise cash through an offeringVärde who is also one of our capital stockdirectors or officers, becomes aware of a refinancing of our debt include financial market conditions, the value of our assets, the number of shares of capital stock wepotential business opportunity, transaction or other matter, they will have authorized, unissued and unreserved and our performance at the time we need capital.
The Credit Agreement, guaranteed and further secured by substantially all our assets, contains restrictive covenantsno duty to communicate or offer that opportunity to us.
As such, Värde may
limit our ability to respond to changes in market conditions or pursue business opportunities.The Credit Agreement contains restrictive covenants that limit our ability to, among other things:
| · | incur additional indebtedness; |
| · | create additional liens; |
| · | 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 materially adversely affect 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 maybecome aware, from time to time, enter into alternative or additional debt agreements that contain covenant restrictions that may prevent us from taking actions that we believe would be in the best interest of ourcertain business may require us to sell assets or take other actions to reduce indebtedness to meet such covenants,opportunities (such as acquisition opportunities) and may make it difficultdirect 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 successfully executepursue. Additionally, any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our business strategy or effectively compete with companies that are not similarly restricted.
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
management does not expect that our disclosure controls and procedures and internal controls
willmay not prevent all possible errors and
all fraud. A control system, no matter how well conceived and operated, can provide only reasonable
not absolute, assurance that the objectives of the control system are being met. In addition, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls are evaluated relative to their costs. Because of the inherent limitations in all control systems, no evaluation of our controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected.
The design of any system of controls is based in part upon the likelihood of future events, and any design may not succeed in achieving its intended goals under all potential future conditions. Over time, a control may become inadequate because of changes in conditions, or the degree of compliance with our policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without
detection.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
theour Chief Executive Officer and
theour 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.
Through September 30, 2016, management had concluded
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 itsa weakness in internal controlcontrols over financial reporting was not effective. Duringmay go undetected. Therefore, even effective internal controls can provide only reasonable assurance with respect to the fourth quarterpreparation and fair presentation of 2016, we completed our remediation efforts, but we may discover additional areas offinancial statements.
A material weakness in our internal control over financial reporting in the future which may require improvement.could adversely impact our ability to provide timely and accurate financial information. If we are unable to assert that our internal control overreport financial reporting isinformation timely and accurately or to maintain effective indisclosure 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 future period, or if our auditors are unable to express an opinion onone of which could adversely affect the effectivenessvaluation of our internal controls, wecommon stock and could lose investor confidenceadversely affect our business prospects.
Decreases in
the accuracyoil and
completeness of our financial reports, which could have an adverse effect on our stock price.If oil or natural gas prices decrease or explorationmay 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
efforts are unsuccessful, wells in progress are deemed unsuccessful, or major tracts of undeveloped acreage expire, orplans, production data, economics and other
similar adverse events occur,factors, we may be required to
write-downwrite down the carrying value of our
developed properties.
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 wells, completing productive wells, or plugging and abandoning non-productive wells, costs related to expired leases, or leases underlying producing and non-producing wells, and overhead charges directly related to acquisition and exploration activities. Underproperties.
We perform the full cost method of accounting, capitalized oil and natural gas property that comprise the full cost pool, 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. This ceiling test is performed at least quarterly. Shouldquarterly and, in the event capitalized costs of the full cost pool exceed this ceiling, we would recognize an impairment expense. We recognized an impairment expense of approximately $4.7$228.3 million and $24.5 million for the yearsyear ended December 31, 2016 and 2015, respectively. At2019. We did not recognize an impairment expense for the year ended December 31, 2016, the Company’s estimates of undiscounted future cash flows indicated that the carrying amounts were not expected to be recovered due to a decrease in proved reserves. During 2016, commodity prices continued to trade in a low range. With low commodity prices sustained for the majority of 2016 in the DJ Basin, some of our properties became uneconomic triggering impairment charge of $4.7 million at December 31, 2016. The impairment charge of $24.5 million in 2015 was due to the lower commodity prices and lack of capital to develop our undeveloped oil and gas properties. 2018.
Future write-downs
couldwill likely 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
reservereserves 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; asreserves values. As such, these situations could result in
future additional impairment
expenses.If commodity prices stay at current levels or decline further, we could incur full cost ceiling impairmentsexpenses in future quarters. Because the ceiling calculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter prices in 2016 compared to 2015 is a lower ceiling value each quarter. This may result in ongoing impairments each quarter until prices stabilize or improve.future. Impairment charges would not affect cash flow from operating activities but would adversely affectcould have a material adverse effect on our net income and stockholders’ equity.
Our estimated reserves are based on many assumptions that may prove inaccurate. Any significant inaccuracies in
these reserveour reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
No one can measure underground accumulations of oil and natural gas in an exact way.
Oil and natural gas
reservereserves 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
reservereserves estimates or underlying assumptions
willcould materially affect the quantities and present value of our reserves which could adversely affect
our business, results of operations,
and financial
condition and our ability to make cash distributions to shareholders.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.
In accordance with SEC requirements, we based the estimated discounted future net cash flows from provedIf our reserves
on the 12-month average oil and 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.Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we used when calculating discounted future net cash flows for reporting requirements in compliance with the FASB in Accounting Standards Codification, which is referred to as ASC 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oilunderlying assumptions prove inaccurate, it could have a negative impact on our earnings and natural gas industry in general.
Oil and natural gas prices are highly volatile, and our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital,net income, as well as the carrying valuetrading price of our properties, are substantially dependent on prevailing prices of oil and natural gas.
Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following:
| · | changes in global supply and demand for oil and natural gas; |
| · | the actions of the Organization of Petroleum Exporting Countries; |
| · | the price and quantity of imports of foreign oil and natural gas; |
| · | acts of war or terrorism; |
| · | political conditions and events, 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; |
| · | technological advances affecting energy consumption; |
| · | the price and availability of alternative fuels; and |
| · | market concerns about global warming or changes in governmental policies and regulations due to climate change initiatives. |
Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.
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 need 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.
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,
from time to time, we
may enterhave entered into derivative contracts that economically hedge our oil and
natural gas price on a portion of our production. These contracts may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the contract. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in
which: | · | there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received; |
| · | our production and/or sales of oil or natural gas are less than expected; |
| · | payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or |
| · | the other party to the hedging contract defaults on its contract obligations. |
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
anyour current or future derivatives contracts may fail to fulfill their contractual obligations to us.
As of December 31, 2016, we had no hedging agreements in place.
Our identified drilling locations are scheduled
outto 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 and other factors.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
these or any otherour 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. Analogies drawn from available data from other wells, more fully explored prospects or producing fields may not be applicable to current drilling prospects.The budgeted costs of planning, drilling, completing and operating wellsquantities as such studies are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling and operating processes. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells endure a much greater risk of loss than development wells. 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 drilling plans accordingly. merely an interpretive tool.
Drilling for oil and natural gas involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing, and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including:
| · | unexpected or adverse drilling conditions; |
| · | elevated pressure or irregularities in geologic formations; |
| · | equipment failures or accidents; |
| · | adverse weather conditions; |
| · | compliance with governmental requirements; and |
| · | shortages or delays in the availability of drilling rigs, crews, and equipment. |
unexpected or adverse drilling conditions;
elevated pressure or irregularities in geologic formations;
equipment failures or accidents;
adverse weather conditions;
compliance with governmental requirements; and
shortages or delays in the availability of drilling rigs, crews, and equipment, including as the result shortages of personnel due to epidemics, pandemics or other major public health issues, such as COVID-19.
Additionally, the budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling and operating processes. If we decide to drill a certain location, there is a risk that (i) no commercially productive oil or natural gas reservoirs will be found or produced, or (ii)actual drilling
and development costs are significantly more than the current estimated costs, we may
drill or participate in new wells that are not
productive or drill wells that are productive, but that do not produce sufficient net revenuesbe able to
return a profit aftercontinue operations as proposed and could be forced to modify our drilling
operating and other costs.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.
Our overall drilling success rate or drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in production and revenues and materially
harmaffect our operations and financial condition by reducing available cash and resources.
Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from the well or abandonment of the well.
Financial difficulties encountered by our oil and natural gas purchasers,
third partythird-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,
and natural gas
and NGLs to unaffiliated
third partythird-party purchasers, independent marketing companies and
mid-streammidstream companies. Any delays in payments from such purchasers caused by
their financial
problems encountered by themdifficulties, including those resulting from the impacts of COVID-19 and its impact on the global economy, will have an immediate negative effect on our results of operations and cash flows.
Liquidity
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.
Prospects in which we decide to participate may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return.
A prospect is a property in which we own an interest and contains what we believe, based on available reservoir, seismic and/or geological information, to be indications of commercial oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional technical assessment, data acquisition and/or seismic data processing and interpretation. There is no definitive method to predict in advance of drilling and testing and wider-scale development whether any particular prospect will yield oil or natural gas in sufficient quantities to be economically viable. The use of reservoir, geologic and 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. The analysis we perform using data from other wells, more fully explored prospects or producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling prospects.
Our industry is highly competitive, which may adversely affect our
performance, including our ability to participate in ready to drill prospects in our core areas.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
are: | · | leasehold prospects under which oil and natural gas reserves may be discovered; |
| · | drilling rigs and related equipment to explore for such reserves; and |
| · | knowledge personnel to conduct all phases of oil and natural gas operations. |
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. Virtually all
Many of
theseour competitors have financial and other resources substantially greater than ours.
SuchThe 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
risk suffering numerousmay face various consequences,
including:including the breach of our obligations under our oil and natural gas leases and the potential loss of those leasehold interests; damage to our reputation in the oil and natural gas community; inability to retain personnel or attract capital; a slowdown in our operations and decline in revenue; and a decline in the market price of our common stock. | · | the breach of our obligations under the oil and gas leases by which we hold our prospects and the potential loss of those leasehold interests; |
| · | loss of reputation in the oil and gas community; |
| · | inability to retain staff or attract capital; |
| · | a general slowdown in our operations and decline in revenue; and |
| · | decline in market price of our common stock. |
Seismic studies do not guarantee that hydrocarbons are present or, if present, will produce in economic quantities.
We may use seismic studies to assist with assessing prospective drilling opportunities on current properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or if present will produce in economic quantities.
Properties that we acquire may not produce oil or natural gas as projected, and we may be unable to determine
reservereserves 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
ishas been to pursue selective acquisitions of undeveloped acreage potentially containing oil and natural gas reserves. If we choose,
and have the capital resources, to pursue an acquisition, we will perform a review of the target
properties; however,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
eachan acquisition. Even a detailed review of records and properties may not
necessarily 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
thesethe liabilities are incurred.
We may incur losses or costs as a result of title deficiencies in the properties in which we invest.
If an examination of the title history of a property that we purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such oil and natural gas lease as well as any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost.
Prior to the drilling of an oil and natural gas well, however, it is the normalcustomary 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 and operations are all located in a limited numberthe Delaware Basin, making us vulnerable to risks associated with operating in one major geographic area.
As of
geographic areas, which exposes us to various risks, including the risk of damage or business interruptions from natural disasters or weather events.
AllDecember 31, 2019, all of our estimated proved reserves at December 31, 2016, all of our 2016 and 2015 sales were generatedlocated in the Delaware Basin in Winkler, Loving, and LovingReeves Counties, West Texas and Lea County, New Mexico and the DJ Basin in southeastern Wyoming, northeastern Colorado and southwestern Nebraska.
Although these areas are well-established oilfield infrastructures,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, significant 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.
Our operational risk is concentrated due to our reliance on a small number of wells, operators and oil and gas purchasers.
We
have concentrated operational risks both in terms of producing oil and gas properties, the operators we use and in the purchasers of our oil and gas production. An operational failure by an operator, the decline of production from a property and the termination of a contractual agreement with an operator or purchaser could have a material negative impact on our company. Our properties are located in areas where we have multiple markets for our oil and gas. As such, the loss of any single purchaser will not have a material impact with our ability to sell our oil and gas.We willmay 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
Delaware assets, but do not control all our DJ Basin development.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
a greater proportion of locationswells 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
including: | · | the timingand may adversely affect our financial condition and amount of capital expenditures; |
| · | the operator’s expertise and financial resources; |
| · | approval of other participants in drilling wells; |
| · | selection of technology; and |
| · | the rate of production of reserves, if any. |
This limited ability to exercise control over the operations of some of drilling locations may cause a material adverse effect on results of operations and financial condition.
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 produced from these areas through trucking, gathering systems and pipelines, some of which we do not own.pipelines. The lack of availability of capacity on third-party systems and facilities has impacted our ability to sell natural gas and could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of our development plans for properties. plans.
Although we have
some contractual control over the transportation of our production through firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions,
mechanical issues, adverse weather conditions, work-loads, epidemics, pandemics or
mechanical reliabilityother major public health issues, such as COVID-19, or other reasons
including adverse weather conditions or work-loads. Activist or other efforts may delay or halt the constructionoutside of
additional pipelines or facilities. Third-party systems and facilities may not be availableour control. Additionally, if our natural gas contains levels of hydrogen sulfide that require treatment prior to
ustransportation, it could cause delays in the
future at a price that is acceptable to us.transportation and marketing of our production. Any significant
change in market factors or other conditionschanges affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay
our production,
thereby harming our business and, in turn,which could negatively impact our results of operations, cash flows, and financial condition.
The shut-in of our wells could negatively impact our production, liquidity, and, ultimately, our operations, results, and performance.
Our success is influenced byproduction 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 natural gas,field’s production could result in the shut-in of our wells. As of December 31, 2019, we had two wells shut-in.
In response to recent commodity prices and NGLour efforts to strengthen our capital through reducing operating costs, during April 2020 the Company elected to shut-in 12 wells which were identified as uneconomic as a result of the continued decline in
commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate.
The 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
specific areas where we operate, and these prices may be lower than prices at major markets.Regional natural gas, condensate, oil and NGLs prices may move independently of broad industry price trends. Because someshut-in of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTIwells or other major market pricing.
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 and other factors. Thus, ourpressures. 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.
Part of our strategy involves drilling in existing or emerging unconventional shale plays using available horizontal drilling and completion techniques. The results of our planned
Any future plans for exploratory and development drilling
in these plays are subject to drilling and completion execution risks, and drilling results may not meet our economic expectations for reserves or production.
As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.
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,
during completion operations, properimproper design and engineering
versusfor the reservoir parameters, and
successfullyunsuccessfully cleaning out the wellbore after completion of the final fracture stimulation stage.
Our experience with horizontal well applications utilizing the latest drilling and completion techniques specifically in the formations where we are currently operating is limited; however, we contract with local experts in the area to design, plan and conduct our drilling and completion operations. Ultimately, the
The success of
theseour drilling and completion techniques can only be developed over time as more wells are drilled and production profiles are
established over a sufficiently long time period.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
and limited takeaway capacity or otherwise,
and/or natural gas and oil prices decline, 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.plans, if and when we are able to resume drilling and completions activity.
The oil and
natural gas industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of and demand for rigs, equipment and supplies may increase substantially and their availability may be limited. In addition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases.
The higher prices of oil and gas during the last several years have increased activity which has resulted in shortages of drilling rigs, equipment and personnel, which have resulted in increased costs and delays in the areas where we operate. 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.
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
operationsoil and natural gas exploration and production activities are subject to the
operating risks
inherent in theand hazards associated with drilling for and producing oil and natural gas,
industry, including
the risks of: | · | fire, explosions and blowouts; |
| · | negligence of personnel; |
| · | pipe or equipment failure; |
| · | abnormally pressured formations; and |
| · | environmental accidents such as oil spills, natural gas environment (including groundwater contamination). |
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 from:
| · | significantly increased costs; |
| · | severe damage to or destruction of property, natural resources and equipment; |
| · | pollution or other environmental damage; |
| · | clean-up responsibilities; |
| · | regulatory investigation; |
| · | penalties and suspension of operations; or |
| · | attorney’s fees and other expenses incurred in the prosecution or defense of litigation. |
Weus, 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
theseall losses or liabilities. We do not carry business interruption
insurance. Lossesinsurance, and
liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial conditionwe cannot fully insure against pollution and
operations.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.
We may not have enough insurance to cover all of the risks faced and operators of prospects in which we participate may not maintain or may fail to obtain adequate insurance.
In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks faced. We do not carry business interruption insurance.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. In addition, we cannot insure fully against pollution and environmental risks. 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.
Oil Losses and natural gasliabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations, are subject to particular hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. We do not operate all of the properties in which we hold an interest. In the projects in which we own a non-operating interest directly, the operator for the prospect maintains insurance of various types to cover operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event that is not fully covered by insurance could result inincluding the loss of our total investment in a particular prospectprospect.
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
adverse effectnegative impact on
financial conditionour operations or business reputation and
results of operations.Failuresubject us to adequately protect critical dataconsequences such as litigation and technology systems could materially affect our operations.
direct costs associated with incident response.
Information technology solution failures, network disruptions,
and breaches of data security
and cyberattacks could disrupt our operations by causing delays,
or cancellation of customer orders, 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,
or 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,
may 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.
We have limited management and staff and
willmay be dependent upon partnering arrangements.
As of December 31, 2016,2019, we had nineteen43 full-time employeesemployees. As a result of layoffs and two part-timefurloughs in response to COVID-19 and current commodity market conditions, the Company currently has 20 active employees. We leverage the services of independent consultants and contractors to perform various professional services, including engineering, oil and natural gas well planning and supervision, and land, legal, environmental, accounting and tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing.
Our dependence on third-party consultants and service providers creates a number of risks, including but not limited
to: | · | the possibility that such third parties may not be available to us as and when needed; and |
| · | the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects. |
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.personnel or changes to our Board of Directors.
We depend to a large extent on the services of certain key management personnel
including Abraham Mirman, our Chief Executive Officer 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.
The successful acquisition of producing properties requires an assessment of several factors, including: | · | future oil and natural gas prices and their appropriate differentials; |
| · | well and facility integrity; |
| · | development and operating cost; |
| · | regulatory constraints and plans; and |
| · | potential environmental and other liabilities. |
The accuracy of these assessments is inherently uncertain. In connection with these assessments,If and when we perform a review of the subject properties. Our review will not reveal all existing or potential problems nor will it permit usare able to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.
Significantdo this, significant acquisitions and other strategic transactions may involve other 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. |
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
thisthe 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 have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.
Significant growth in the size and scope of our operations would place a strain on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial staff and control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and gas industry could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.
We may face difficulties in securing and operating under authorizations and permits to drill, complete or operate our wells.
The
recentcontinued 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 than in other countries.Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one major geographic area.
Most of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects 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 operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.
Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has remained relatively steady despite the recent downturn in commodity prices. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has continued to be competitive, and would be expected to increase substantially in the future if commodity prices rebound. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.
Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could result in oil and gas production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our results of operations, liquidity and financial condition.
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.
Risks Relating to the Oil and Gas Industry
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.
In December 2009, the
The EPA
has determined that emissions of carbon dioxide, methane and other “greenhouse
gases” present an endangerment togases,” or “GHGs,” endanger public health and the environment because emissions of such gases are, according to the EPA, contributing to
warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA, under the Clean Air Act, has
begun adoptingadopted and
implementingimplemented regulations to restrict emissions of greenhouse gases.
Relatively recently, the EPA adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States on an annual basis, including petroleum refineries, as well as certain onshore oil and natural gas production facilities.Also, on May 12, 2016, EPA issued regulations (effective August 2, 2016) that build on the 40 C.F.R. Part 60, Subpart OOOO (NSPS OOOO) standards by directly regulating methane and VOC emissions from various types of new and modified oil and gas sources. Some of those sources are already regulated under NSPS OOOO, while others, like hydraulically fractured oil wells, pneumatic pumps, and certain equipment and components at compressor stations, are covered for the first time. On March 10, 2016, moreover, the EPA announced that it is moving towards issuing performance standards for methane emissions from existing oil and gas sources. The agency said that it will “begin with a formal process (i.e., an Information Collection Request) to require companies operating existing oil and gas sources to provide information to assist in the development of comprehensive regulations to reduce methane emissions.” On November 10, 2016, the EPA issued the Information Collection Request (“ICR”) and explained that “[r]ecipients of the operator survey (also referred to as Part 1) will have 60 days after receiving the ICR to complete the survey and submit it to EPA….Recipients of the more detailed facility survey (also referred to as Part 2) will have 180 days after receiving the ICR to complete that survey and submit it to the agency.”
In June 2014, the United States Supreme Court’s holding inUtility Air Regulatory Group v. EPAupheld a portion of EPA’s greenhouse gas (“GHG”) stationary source permitting program, but also invalidated a portion of it. The Court held that stationary sources already subject to the Prevention of Significant Deterioration (“PSD”) or Title V permitting programs for non-GHG criteria pollutants remain subject to GHG Best Available Control Technology and major source permitting requirements, but ruled that sources cannot be subject to the PSD or Title V major source permitting programs based solely on GHG emission levels. As a result, on August 12, 2015, the EPA eliminated from its PSD and Title V regulations the provisions that subjected sources to the PSD or Title V programs based solely on GHG emission levels. The EPA likewise said that it will “further revise the PSD and Title V regulations in a separate rulemaking to fully implement” theUtility Air Regulatory Groupjudgment. On October 3, 2016, EPA published a proposed rulemaking for that purpose. TheUtility Air Regulatory Group judgment does not prevent states from considering and adopting state-only major source permitting requirements based solely on GHG emission levels.
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,
NGLs,natural gas and
natural gasNGLs we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our
business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.Federal and state legislativebusiness.
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. The process involves the injection of water, sandformations, and
chemicals under pressure into the formation to fracture the surrounding rock and stimulate production by providing and linking up induced flow paths for the oil and/or gas contained in the rocks. Wewe routinely
useimplement 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.
The Bureau of Land Management (“BLM”), on March 20, 2015, issued its final regulations for hydraulic fracturing on federal and tribal lands. The new regulations require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land. On June 21, 2016, however, the U.S. District Court for the District of Wyoming enjoined BLM from enforcing the regulations, concluding that the agency lacked the authority to issue them. BLM appealed that decision to the U.S. Court of Appeals for the Tenth Circuit. The appeal is pending.
In addition, on June 13, 2016, under the Clean Water Act, the EPA finalized a rule (effective August 29, 2016) that prohibits the discharge of oil and gas wastewaters to publicly-owned treatment works.
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.
For example in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. LocalAdditionally, 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. Nonetheless, 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 the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.While these state and local land use restrictions generally cover areas with little recent or ongoing oil and gas development, they could lead opponents of hydraulic fracturing to push for similar statewide regimes. 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 the pursuit ofour exploration, development, or production activities, and perhaps even be precluded from drilling wells.
A
In addition, a number of federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing.
The EPA, for example, recently completed a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. In June of 2015, the EPA released an “external review draft” of the study and, in it, said that shale development had not led to “widespread, systemic” problems with groundwater. On August 11, 2016, however, the EPA Science Advisory Board issued comments on the external review draft, finding that “the EPA did not support quantitatively its conclusion about lack of evidence for widespread, systemic impacts of hydraulic fracturing on drinking water resources, and did not clearly describe the system(s) of interest (e.g., groundwater, surface water), the scale of impacts (i.e., local or regional), nor the definitions of ‘systemic’ and ‘widespread.’” In December of 2016, the EPA released the final version of the study, finding, among other things, that there are “certain conditions under which impacts from hydraulic fracturing activities can be more frequent or severe,” including “[i]njection of hydraulic fracturing fluids into wells with inadequate mechanical integrity, allowing gases or liquids to move to groundwater resources.” 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.
The EPA also issued an advance notice of proposed rulemaking and undertook a public participation process under the Toxic Substances Control Act to seek comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanisms for obtaining this information. Additionally, on January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that the EPA add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Emergency Planning and Community Right-to-Know Act’s Toxics Release Inventory, or TRI, program. On October 22, 2015, the EPA took action on the Environmental Integrity Project’s October 24, 2012 petition to impose TRI reporting requirements on various oil and gas facilities. The EPA granted the petition in part, by agreeing to propose to add natural gas processing facilities to the scope of the TRI program, but rejected the rest of the petition. On December 15, 2015, in light of that decision, the environmental advocacy groups that had commenced the lawsuit opted to voluntarily dismiss it. On January 6, 2017, EPA issued a proposed rulemaking that would add natural gas processing facilities to the scope of the TRI program.
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
uses large amounts of water. It can require between three to five million gallons of water per horizontal well. We may face regulatory concerns in both the sourcing and the discharge of water used in hydraulic fracturing.
In addition, hydraulic fracturing produces water discharges that must be treated and disposed of in accordance with applicable regulatory requirements.First, as to sourcing water for hydraulic fracturing, we will need to secure water from the local water supply or make alternative arrangements.
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.
Second,
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
gas and oil.Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction.
Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal and state income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations. Additionally, legislation could be enacted that increases the taxes states impose on oil and natural gas extraction.
Moreover, as part of the Budget of the United States Government for Fiscal Year 2017, there was a proposal to impose an “oil fee” of $10.25 on a per barrel equivalent of crude oil. This fee would be collected on domestically produced and imported petroleum products. The fee would be phased in evenly over five years, beginning October 1, 2016. The adoption of this, or similar proposals, could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil. Any of these tax changes could have a material impact on our financial performance.
We are subject to numerous
U.S. 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, and operating safety.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: | · | lease permit restrictions; |
| · | drilling bonds and other financial responsibility requirements, such as plugging and abandonment bonds; |
| · | unitization and pooling of properties; |
| · | operational reporting; and |
Under these laws and regulations, we could be liable for:
| · | property and natural resource damages; |
| · | well reclamation cost; and |
| · | governmental sanctions, such as fines and penalties. |
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.
It is also possible that a portion of our oil and gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated. See “Business—Regulation of the Oil and Natural Gas Industry” for a more detailed description of regulatory laws covering our business.Our operations
We may incur substantial expenses, and potentially resulting liabilities, fromto 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
orand disposal of materials into the
environment or otherwise relating to environmental protection.environment. These laws and
regulations: | · | regulations, among other things, require the acquisition of a permit before drilling or facility mobilization and commissioning, or injection or disposal commences; |
| · | restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production and processing activities, including environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells; |
| · | 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. |
Failure to comply with these lawsbe obtained before drilling or facility mobilization and regulations may result in:
| · | the assessment of administrative, civil and criminal penalties; |
| · | incurrence of investigatory or remedial obligations; and |
| · | the imposition of injunctive relief. |
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. Our permits require that we report any incidents that
The Company may be adversely affected by the recent COVID-19 outbreak.
The spread of COVID-19 has caused severe disruptions in the worldwide economy, including the global demand for oil and natural gas, which has disrupted our business and operations. Moreover, since the beginning of January 2020, the COVID-19 outbreak has caused significant disruption in the financial markets both globally and in the United States. The continued spread of COVID-19 has resulted in a significant decrease in business and/or cause
our oil and natural gas purchasers to be unable to meet existing payment or
other obligations to us, particularly in the event of a spread of COVID-19 in our market areas. The continued spread of COVID-19 could
cause environmental damages. See “Business— Regulationalso negatively impact the availability of
the Oil and Natural Gas Industry” for a more detailed description of the environmental laws coveringour key personnel necessary to conduct our business.
Should we fail Such a spread could also negatively impact the business and operations of third party service providers who perform critical services for our business. If COVID-19 continues to comply with all applicable regulatory agency administered statutes, rules, regulations and orders,spread or the response to contain COVID-19 is unsuccessful, we could continue to experience a material adverse effect on our business, financial condition, and results of operations.
Certain of our assets, including our oil and natural gas interests, may be
or become subject to
substantial penaltiesmechanic’s and
fines.
materialman’s liens if we are unable to pay our oilfield service providers on a timely basis.
We enter into contracts with providers of oilfield services as part of our business. Under
the Domenici-Barton Energy Policy Act of 2005, the FERC has civil penalty authority under the NGAstate laws, liens to
impose penaltiessecure payment for
current violations of upcertain contractors and subcontractors performing certain mineral activities may be attached to
$1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our
otherwise non-FERC jurisdictional facilitiesassets, including our oil and natural gas interests. Due to
FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rulesexisting economic conditions, we have been unable to, and
legislation pertaining to those and other matters may
be considered or adopted by FERC from time to time. Additionally, the Federal Trade Commission has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1 million per day, and the CFTC prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to crude oil swaps and futures contracts as that granted to the CFTC with respect to crude oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future
couldcontinue to be unable to, pay certain of our oilfield service providers on a timely basis. As a result of not making such payments, certain of our assets have become subject
us to
civil penalty liability, as described in “Business-Regulationstatutory mechanic’s and materialman’s liens, and additional statutory mechanic’s and materialman’s liens may be filed. As of the
Oilmost recent date available, statutory mechanic's and
Natural Gas Industry.”materialman’s liens which remain unpaid in the amount of $8.7 million have been filed against the related assets.
Risks Relating to Our Securities
Our common stock may be subject to penny stock rules which limit the market for our common stock.
Our shares of common stock likely qualify as “penny stock” under the SEC rules. Sales and purchases of “penny stock” generally require more disclosures by broker-dealers and satisfaction of other administrative requirements. As a result, broker-dealers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock.
There is a limited public market for our common stock and an active trading market or a specific share price may not be established or maintained.
On May 26, 2016, our common stock was suspended from trading on the Nasdaq and immediately began trading on the OTCQB Venture Marketplace, or the OTCQB. On July 29, 2016, the Nasdaq announced that it will delist our common stock and file a Form 25 with the Securities and Exchange Commission. The Form 25 was subsequently filed on August 1, 2016, and the delisting became effective on August 11, 2016. We have applied for relisting on the Nasdaq and are working to show full compliance with all applicable Nasdaq initial listing criteria.
While our common stock trades on the OTCQB, trading activity in our common stock generally occurs in small volumes each day. The value of our common stock could be affected by:
| · | actual or anticipated variations in our operating results; |
| · | the market price for crude oil; |
| · | changes in the market valuations of other oil and gas companies; |
| · | announcements by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments; |
| · | adoption of new accounting standards affecting our industry; |
| · | additions or departures of key personnel; |
| · | sales of our common stock or other securities in the open market; |
| · | actions taken by our lenders or the holders of our convertible debentures; |
| · | changes in financial estimates by securities analysts; |
| · | conditions or trends in the market in which we operate; |
| · | changes in earnings estimates and recommendations by financial analysts; |
| · | our failure to meet financial analysts’ performance expectations; and |
| · | other events or factors, many of which are beyond our control. |
In a volatile market, you may experience wide fluctuations in the
The market price of our common
stock. These fluctuations may have an extremely negative effect on the market price of our common stock
and may prevent you from obtaining a market price equal to your purchase price when you attempt to sell our common stock in the open market. In these situations, you may be required either to sell at a market price which is lower than your purchase price, or to hold our common stock for a longer period of time than you planned. An inactive market may also impair our ability to raise capital by selling shares of capital stock and may impair our ability to acquire other companies or oil and gas properties by using our common stock as consideration.
If an orderly and active trading market for our securities does not develop or is not sustained, the value and liquidity of your investment in our securities could be adversely affected.
An active or liquid market in our common stock or securities exercisable or convertible for our common stock does not currently exist and might not develop or, if it does develop, it might not be sustainable. The last reported sale price of our common stock on the OTCQB on March 1, 2017 was $4.00 per share. The historic bid and ask quotations for our common stock, however, should not be viewed as an indicator of the current or historical market price for our common stock nor as an indicator of the market price for our common stock if our common stock were to be listed on a national securities exchange. The offering price for our securities as issued by us from time to time is determined through discussions between us and the prospective investor(s), with reference to the most recent closing price of our common stock on the OTCQB, and may vary from the market price of our securities following any offering. Further, our trading volume on the OTCQB has been generally very limited.
If an active public market for our common stock develops, we expect the market price 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.
If an active public market for our common stock develops, we expect the
The market price of our securities
tomay fluctuate substantially for the foreseeable future, primarily due to a number of factors, including:
| · |
our status as a company with a limited operating history and limited revenues to date, which may make risk-averse investors more inclined to sell their shares on the market more quickly and at greater discounts than would be the case with the shares of a seasoned issuer in the event of negative news or lack of progress; |
| · | announcements of technological innovations or new products by us or our existing or future competitors; |
| · | the timing and development of our products; |
| · | general and industry-specific economic conditions; |
| · | actual or anticipated fluctuations in our operating results; |
| · | actions by our stockholders; |
| · | changes in our cash flow from operations or earnings estimates; |
| · | changes in market valuations of similar companies; |
| · | our capital commitments; and |
| · | the loss of any of our key management personnel. |
In addition, market prices of the securities of energy companies, particularly companies like ours without consistent revenues and earnings, have been highly volatile and may continue to be highly volatile in the event of negative news or lack of progress;
announcements of technological innovations or new products by us or our existing or future somecompetitors;
the timing and development of which may be unrelated to the operating performance of particular companies. Further, our common stock is currently quoted on the OTCQB, which is often characterized by low trading volumeproducts;
general and by wideindustry-specific economic conditions;
actual or anticipated fluctuations in trading prices due to many factors that may have little to do with our operating results;
liquidity and loan covenants;
actions by our stockholders;
changes in our cash flow from operations or business prospects. The availabilityearnings estimates;
changes in market valuations of buyers and sellers represented by this volatility could lead to a market price for similar companies;
our common stock that is unrelated to operating performance. Moreover, the OTCQB is not a stock exchange, and trading of securities quoted on the OTCQB is often more sporadic than the trading of securities listed on a national securities exchange like The NASDAQ Stock Market or the New York Stock Exchange. While we are currently seeking to list our securities on a national securities exchange, there is no assurance we will be able to do so, and if we do so, many of these same forces and limitations may still impact our trading volumes and market price in the near term. Additionally, capital commitments;
the sale or attempted sale ofor a large amount of common stock into the market may also have a significant impact on market;
the
trading priceloss of any of our
common stock.key management personnel; and
epidemics, pandemics or other major public health issues, such as COVID-19.
Many of these factors are beyond our control and may decrease the market price of our common stock, regardless of our operating performance.
In the past, securities class action litigation has often been brought against companies that experience high volatility in the market price of their securities. Whether or not meritorious, litigation brought against us could result in substantial costs, divert management’s attention and resources and harm our financial condition and results of operations.
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
shareholders.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
twofour series of preferred stock issued and outstanding,
bothwhich ranks senior to our common stock with respect to dividends and rights on the liquidation, dissolution or winding up of
which provide its holders with a liquidation preference and prohibit the
payment of dividends on junior securities, including our Common Stock,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. For example, the conversiondilution of
the remaining Series B preferred stock in full could result in the issuance of 15,454,545 shares of common stock, and the exercise of outstanding warrants could result in the issuance of 15,915,511 shares ofour common stock. To the extent outstanding restricted stock units, warrants or options to purchase our common stock under our
employee and director stock option plans2016 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 Stockcommon stock will experience dilution. Furthermore,
if we sellthe sale of additional equity or convertible debt securities
such sales 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 Agreement prohibitscredit facilities and preferred stock prohibit us from paying any
dividends and the indenture governing our senior notes restricts our ability to pay dividends. In the future, we may agree to further restrictions. Any return to
shareholdersstockholders 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.Company. If securities analysts do not cover our
company, thisCompany, 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
companyCompany downgrades our shares, the trading price of our shares may decline. If one or more of these analysts ceases to cover our
company,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,Company, which could significantly and adversely affect the trading price of our shares.
Our Series B preferred stock accrues a dividend, and we may be required to issue additional shares of Series B preferred stock upon the occurrence of certain events.
The Series B preferred stock accrues a dividend, payable quarterly in arrears (based on calendar quarters), in the amount of 6% per annum of the original issuance price of the Series B preferred stock. The dividend is payable by an increase to the stated value of the Series B preferred stock or in-kind in Series B preferred stock or in cash, at our election.
We may not have sufficient available cash to pay the dividends as it accrues. The payment of the dividends, or our failure to timely pay the dividends when due, could reduce our available cash on hand, have a material adverse effect on our results of operations and cause the value of our stock to decline in value. Additionally, any increase in stated value, which would result in the issuance of additional shares of Series B preferred stock in lieu of cash dividends (and the subsequent conversion of such Series B preferred stock into common stock pursuant to the terms of such Series B preferred stock) could cause substantial dilution to the then holders of our common stock.
The issuance and sale of common stock upon conversion of the Series B Preferred Stock and the exercise of warrants received in those transactions, may depress the market price of our common stock.
If conversions of the Series B preferred stock and exercises of warrants received in those transactions, sales of such converted securities take place, the price of our common stock may decline. In addition, the common stock issuable upon conversion of such securities may represent overhang that may also adversely affect the market price of our common stock. Overhang occurs when there is a greater supply of a company’s stock in the market than there is demand for that stock. When this happens the price of our company’s stock will decrease, and any additional shares which shareholders attempt to sell in the market will only further decrease the share price. If the share volume of our common stock cannot absorb converted shares sold by the Series B preferred stock holders, then the value of our common stock will likely decrease.
Anti-takeover effects of certain provisions of Nevada state law hinder a potential takeover of our
company.ThoughCompany.
The existence of certain provisions under Nevada law could delay or prevent a change in control of the Company, which could adversely affect the price of our common stock. Additionally, Nevada law imposes certain restrictions on mergers and other business combinations between us and any holder of 10% or more of our outstanding common stock.
We are currently not now,in compliance with the NYSE American listing standards. If our common stock is delisted, the market price and liquidity of our common stock and our ability to raise additional capital would be adversely impacted.
Our common stock is currently listed on the NYSE American. Continued listing of a security on the NYSE American is conditioned upon compliance with various continued listing standards. On November 21, 2019, we received a deficiency letter (the “First Deficiency Letter”) from the NYSE American stating that we were below compliance with the continued listing standards as set forth in Section 1003(a)(i)-(iii) of the NYSE American Company Guide (the “Company Guide”) because we had reported a stockholders’ equity deficiency as of September 30, 2019 and net losses in our five most recent fiscal years ended December 31, 2018. On December 3, 2019 we received another deficiency letter (the “Second Deficiency Letter” and, together with the First Deficiency Letter, the “Deficiency Letters”) from the NYSE American stating we were below compliance with the continued listing standards as set forth in Section 1003(f)(v) of the Company Guide because our common stock had been selling for a low price per share for a substantial period of time. The Second Deficiency Letter stated that we must effect a reverse stock split of our common stock or otherwise demonstrate sustained price improvement no later than June 3, 2020.
The Deficiency Letters had no immediate effect on our listing on the NYSE American and, therefore, our common stock will continue to be listed on the NYSE American, subject to our compliance with other continued listing requirements of the NYSE American. On December 20, 2019, we submitted a plan of compliance to the NYSE American addressing how we intend to regain compliance with Sections 1003(a)(i)-(iii) of the Company Guide by May 21, 2021. On February 7, 2020, the Company received a letter from the NYSE American stating that our compliance plan has been accepted and that we have been granted a plan period through May 21, 2021.
By May 21, 2021, we must either be in compliance or must have made progress that is consistent with the plan during the plan period. In addition, during the plan period, we must provide quarterly updates to the NYSE American concurrent with our interim and annual SEC filings. Failure to meet the requirements to regain compliance could result in the future we may become subject to Nevada’s control share law. A corporation is subject to Nevada’s control share law if it has more than 200 stockholders, at least 100initiation of whom are stockholders of recorddelisting proceedings.
The Deficiency Letters do not affect our business operations or our reporting obligations under the rules and residents of Nevada, and it does business in Nevada or through an affiliated corporation. The law focuses on the acquisition of a “controlling interest” which means the ownership of outstanding voting shares sufficient, but for the control share law, to enable the acquiring person to exercise the following proportionsregulations of the voting powerSEC, nor do the Deficiency Letters conflict with or cause an event of default under any of the corporationCompany’s material agreements.
If we cannot meet the NYSE American continued listing requirements by the end of our compliance period, the NYSE American may delist our common stock resulting in our common stock trading in the electionless liquid over-the-counter market, which could have an adverse impact on us and the liquidity and market price of directors: (i) one-fifth or more but less than one-third, (ii) one-third or more but less than a majority, or (iii) a majority or more.our stock. The delisting of our stock from the NYSE American could result in even further reductions in our stock price, substantially limit the liquidity of our common stock, and materially adversely affect our ability to exercise such voting power may be directraise capital or indirect, as well as individualpursue strategic restructuring, refinancing or in associationother transactions on acceptable
terms, or at all. Delisting from the NYSE American could also have other negative results, including the potential loss of confidence by vendors and employees, the loss of institutional investor interest and fewer business development opportunities. Our management is considering alternatives to ensure continued compliance with
others.The effect of the control share law is that the acquiring person, and those acting in association with it, obtains only such voting rights in the control shares as are conferred by a resolution of the stockholders of the corporation, approved at a special or annual meeting of stockholders. The control share law contemplates that voting rights will be considered only once by the other stockholders. Thus,NYSE American listing standards, but there is no authorityassurance that we will continue to strip voting rights from the control shares of an acquiring person once those rights have been approved. If the stockholders do not grant voting rights to the control shares acquired by an acquiring person, those shares do not become permanent non-voting shares. The acquiring person is free to sell its shares to others. If the buyers of those shares themselves do not acquire a controlling interest, their shares do not become governed by the control share law. If control shares are accorded full voting rights and the acquiring person has acquired control sharesmaintain compliance with a majority or more of the voting power, any stockholder of record, other than an acquiring person, who has not voted in favor of approval of voting rights is entitled to demand fair value for such stockholder’s shares. Nevada’s control share law may have the effect of discouraging takeovers of the corporation.
In addition to the control share law, Nevada has a business combination law which prohibits certain business combinations between Nevada corporations and “interested stockholders” for three years after the “interested stockholder” first becomes an “interested stockholder,” unless the corporation’s board of directors approves the combination in advance. For purposes of Nevada law, an “interested stockholder” is any person who is (i) the beneficial owner, directly or indirectly, of ten percent or more of the voting power of the outstanding voting shares of the corporation, or (ii) an affiliate or associate of the corporation and at any time within the three previous years was the beneficial owner, directly or indirectly, of ten percent or more of the voting power of the then outstanding shares of the corporation. The definition of the term “business combination” is sufficiently broad to cover virtually any kind of transaction that would allow a potential acquirer to use the corporation’s assets to finance the acquisition or otherwise to benefit its own interests rather than the interests of the corporation and its other stockholders. The effect of Nevada’s business combination law is to potentially discourage parties interested in taking control of our company from doing so if it cannot obtain the approval of our Board of Directors.
NYSE American continued listing standards.
Item 1B. Unresolved Staff CommentsNot applicable.
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.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Recent
Market
PricesWe began tradingInformation
Our common stock trades on the
OTCQB Venture Marketplace under the symbol “LLEX” on May 27, 2016. From February 11, 2016 to May 26, 2016, our common stock traded on The Nasdaq Capital Market (“Nasdaq”)NYSE American under the symbol “LLEX.”
Prior February 11, 2016, our common stock traded on the Nasdaq Global Market under the symbol “LLEX.” We have applied for relisting on the Nasdaq and are working to show full compliance with all applicable Nasdaq initial listing criteria.The following table shows the high and low reported sales prices of our common stock for the periods indicated. The prices reported in this table have been adjusted to reflect the 1-for-10 reverse split of our issued and outstanding common stock, which took effect on June 23, 2016.
| | | High | | | Low | |
| | | 2016 | |
| Fourth Quarter | | $ | 3.75 | | | $ | 2.10 | |
| Third Quarter | | $ | 3.51 | | | $ | 1.08 | |
| Second Quarter | | $ | 2.33 | | | $ | 0.50 | |
| First Quarter | | $ | 3.70 | | | $ | 1.00 | |
| | | 2015 | |
| Fourth Quarter | | $ | 7.00 | | | $ | 0.70 | |
| Third Quarter | | $ | 31.50 | | | $ | 4.80 | |
| Second Quarter | | $ | 19.00 | | | $ | 7.40 | |
| First Quarter | | $ | 12.60 | | | $ | 6.00 | |
Holders
As of March 1, 2017,April 30, 2020, there were 135 owners107 holders of record of our common stock. We estimate that there
Dividend Policy
Holders of shares of preferred stock are approximately 1,833 beneficial holders ofentitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears. Dividends on our commonpreferred stockDividend Policy
are payable, at the Company’s option, (i) in cash, (ii) in kind, or (iii) in a combination thereof. In 2019, we did not pay cash dividends on our outstanding preferred stock. For the year ended December 31, 2019, the paid-in-kind dividends is $25.4 million.
See Note 15 - Preferred Stock to our consolidated financial statements included in this Annual Report.
We have never paid
any cash dividends on our common stock and do not anticipate paying
any 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
boardBoard of Directors may deem relevant at that time.
In addition, we are currently restricted from declaring any dividends pursuant to the terms of our Credit Agreement and outstanding preferred stock. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—“Liquidity and Capital Resources.”
Recent Sales of Unregistered Securities
We have previously disclosed by way
None
Equity Compensation Plan Information
The following table summarizes information regarding the number of
Quarterly Reports on Form 10-Q and Current Reports on Form 8-K filed with the SEC all sales by usshares of our
unregistered securities during the year ended December 31, 2016.Equity Compensation Plans
Information regardingcommon stock that are available for issuance under all of our existing equity compensation plans is set forth in Item 12as of this Annual Report on Form 10-KDecember 31, 2019:
|
| | | | | | | | | |
| Plan Category | | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights
(a) | | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights
(b) | | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in column (a))
(c) |
| Equity compensation plans approved by security holders | | 3,588,350 | | 4.05 | | 5,372,127 |
| Equity compensation plans not approved by security holders | | — |
| | — |
| | — |
|
| Total | | 3,588,350 | | 4.05 | | 5,372,127 |
For additional information regarding the Company’s benefit plans and is incorporated herein by reference.share-based compensation expense, see Note 17 - Share Based and Other Compensation to our consolidated financial statements.
Item 6. Selected Financial Data
Not applicable.
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 of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes
included elsewhere in
“Part II, Item 8. Financial Statements and Supplementary Data.”this Annual Report. The following discussion
and analysis containsincludes forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions and resources.
Please see “Cautionary Statement Concerning Forward-Looking Statements”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
“Part I, Item 1A. Risk Factors”elsewhere in this Annual
Report on Form 10-K.General
Report.
Overview
We are
an independent oil and gasa Permian Basin focused company engaged in the
acquisition, drillingexploration, production, development, and
production of oil and natural gas properties and prospects. We were incorporated in August of 2007 in the State of Nevada as Universal Holdings, Inc. In October 2009, we changed our name to Recovery Energy, Inc. and in December 2013, we changed our name to Lilis Energy, Inc.On June 23, 2016, we completed a merger (the “Merger”) with Brushy Resources, Inc. (“Brushy”), which resulted in the acquisition of our properties in the Delaware Basin as well as the majority of our current operating activity.
Additionally, in connection with the Merger on June 23, 2016, we effected a 1-for-10 reverse stock split. As a result of the reverse split, every ten shares of issued and outstanding common stock were automatically converted into one newly issued and outstanding share of common stock, without any change in the par value per share. However, the number of authorized shares of common stock remained unchanged.
Shortly after the Merger, we began to develop a drilling program on our properties using hydraulic fracture stimulation techniques across multiple productive horizons. Our primary focus is drilling horizontal wells in the Delaware Basin of West Texas, which we believe will provide attractive returns on a majority of our acreage position. Our goal is to earn economic returns to our shareholders through cash flow from new production of oil, natural gas, and NGLs, as well as through derisking the development profilewith all of our portfolio of properties in order to add overall value. Our drilling program utilizes the development of new horizontal wells across several potentially productive formationsand operations in the Delaware Basin,Basin. Our focus is on the production of “Liquids”. In each of the past two years, over 90% of our revenues have been generated from the sale of Liquids. We have a largely contiguous acreage position with an initial focussignificant stacked-pay potential, which we believe includes at least five to seven productive zones and more than 1,000 future drilling locations.
As of December 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt to our consolidated financial statements), with $115 million of indebtedness outstanding under our Revolving Credit Agreement. As provided for in the Seventh Amendment to our Revolving Credit Agreement and as a result of a decrease in commodity prices, on targetingJanuary 17, 2020, the Wolfcamp formation.borrowing base was decreased to $90.0 million. The reduction in the borrowing base resulted in a borrowing base deficiency of $25.0 million. We drilledhave made scheduled repayments of $17.3 million and pursuant to the Fourteenth Amendment to our first horizontal wellRevolving Credit Agreement, the remaining $7.8 million is due on June 5, 2020. Refer to Note 11 - Long-Term Debt to our consolidated financial statements for additional information. Our next borrowing base redetermination is scheduled to occur on or around June 5, 2020. If the borrowing base is further reduced by the lenders in late 2016 and completed itconnection with this redetermination, we will be required to repay borrowings in 2017.Overviewexcess of Our Business and Strategy
We are anthe borrowing base as we do not have sufficient additional oil and natural gas company, engaged inproperties to eliminate the acquisition, development and production of unconventionalborrowing base deficiency by pledging additional oil and natural gas properties. Weproperties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have accumulatedthe option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination.
Our liquidity and ability to comply with debt covenants under our Revolving Credit Agreement have been negatively impacted by the recent decrease in commodity prices, which have fallen approximately 6,924 net acres$43.00 a barrel based on WTI from December 31, 2019 to the date of this Annual Report, due in what we believepart to befailed OPEC negotiations as well as concerns about the coreCOVID-19 pandemic, which has significantly decreased worldwide demand for oil and natural gas. Our Revolving Credit Agreement contains financial covenants requires the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the Delaware Basinlast day of each fiscal quarter thereafter. See Note 11 - Long-term Debt to our consolidated financial statements for additional information regarding the financial covenants under our Revolving Credit Agreement. As of December 31, 2019, the Company was not in Winklercompliance with the Leverage Ratio and Loving Counties, TexasCurrent Ratio covenants. Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt to our consolidated financial statements), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Lea County, New Mexico. Our leaseholdCurrent Ratio covenants as of December 31, 2019.
As of March 31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. If we are not able to pay or defer the $7.8 million Borrowing Base Deficiency due on June 5, 2020 or do not maintain compliance with our debt covenants, the obligations of the Company under the Revolving Credit Agreement may be accelerated, which would have a material adverse effect on our business.
In order to improve our liquidity, leverage position is largely contiguous, allowing usand current ratio to maximize development efficiency, manage full cycle findingmeet the financial covenants under the Revolving Credit Agreement, we are currently pursuing or considering a number of actions, which in certain cases may require the consent of current lenders and stockholders. In November 2019, our board of directors formed a Special Committee tasked with reviewing and evaluating strategic alternatives that may enhance the value of the Company, including alternatives that may be available to identify and access further sources of liquidity through financing alternatives or deleveraging transactions. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters.
The Special Committee continues to explore financing alternatives and deleveraging transactions. We are also addressing operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs, and potentially enabling usintend to generate higher returns for our shareholders. In addition, 68%continue to pursue and consider other strategic alternatives.
There can be no assurance that we will be able to implement any of our acreage position is held by production, and we are the named operator on 100% of our acreage. These two characteristics give us control over the pace of development andthese plans successfully, or that such plans, if executed, will result in the ability to designpay borrowing base deficiencies, generate sufficient liquidity or comply with our Revolving Credit Agreement covenants. These factors raise substantial doubt about our ability to continue as a more efficientgoing concern within twelve-month period following the date of issuance of these consolidated financial statements.
2019 Operational and profitable drilling program that maximizes recovery of hydrocarbons. We expect that substantially allFinancial Highlights
Increased our net sales production by 3% to 5,102 BOE/d, for 2019 as compared to 2018, despite planned well shut-ins and temporary suspensions of our estimated 2017 capital expenditure budget will be focused ondrilling and completions program throughout 2019. Net sales production for 2019 of 5,102 BOE/d was consistent with guidance for the developmentyear.
Significantly reduced general and
expansion of our Delaware Basin acreage and operations. We also plan to continue to selectively and opportunistically pursue strategic bolt-on acreage acquisitions inadministrative expenses by completing the
Delaware Basin.We generate the vast majority of our revenues from the sale of oil for our producing wells. The prices of oil and natural gas are critical factors to our success. Volatility in the prices of oil and natural gas could be detrimental to our results of operations. Our business requires substantial capital to acquire producing properties and develop our non-producing properties. As the price of oil declines and causes our revenues to decrease, we generate less cash to acquire new properties or develop our existing properties and the price decline may also make it more difficult for us to obtain any debt or equity financing to supplement our cash on hand.
Our Board has approved a drilling program of up to 10 gross Delaware Basin wells (6 net) that is contingent upon our access to sufficient capital to fully execute. In the first quarter of 2017, we completed two wells, and we have begun drilling a third well. We expect our 2017 horizontal drilling program will be focused almost exclusively on the Wolfcamp zoneclosing of the Delaware Basin, with lateral lengths ranging from approximately 5,000’ laterals to 7,000’ laterals.
Based upon current commodity price expectations for 2017, we believe that our cash flow fromHouston and San Antonio offices, consolidating all operations combined with the proceeds of our recently completed equity offering, proceeds from the conversion of in-the-money warrants to equity, and availability under our Credit Facility, will be sufficient to fund our operations for 2017, including working capital requirements. However, future cash flows are subject to a numbersingle location in Fort Worth, and reducing full-time equivalent employees (corporate, operations and field personnel) by approximately 23%. These efforts contributed to reductions of variables, including uncertainty in forecasted production volumesgeneral and commodity prices. We are the operator for 100% of our 2017 operational capital program and, as a result, the amount and timing of a substantial portion of our capital expenditures is discretionary. Accordingly, we may determine it prudent to curtail drilling and completion operations due to capital constraints or reduced returns on investment as a result of commodity price weakness.
The results of operations of Brushy are included with those of ours from June 23, 2016 through December 31, 2016. As a result, results of operationsadministrative expenses by 15% for the year ended December 31, 2016 are not necessarily comparable to the results of operations for prior periods. Additionally, all discussion related to historical representations of common stock, unless otherwise noted, give retroactive effect to the reverse split for all periods presented.
Results of Operations
Results of operations for the year ended December 31, 20162019 when compared to the year ended December 31, 2015
The2018.
Reduced general and administrative expenses per BOE by 17% for 2019 as compared to 2018
Reduced our crude transportation costs per Bbl by 85% from $5.15 per Bbl in January and February 2019, to $0.75 per Bbl beginning in March 2019 through year-end, resulting in a 2019 weighted average crude transportation cost of $1.49 per Bbl. This resulted in a total annual crude transportation cost savings of $3.0 million in 2019 versus 2018.
Reduced our saltwater disposal costs by 25% to approximately $1.93 per Bbl as of December 2019 through our sales agreements and access to infrastructure.
Increased saltwater disposal capacity through third party access by 380% to 46,600 bbl/d, compared to 2018.
Added seasoned oil and gas professionals to our operations and land departments.
| |
| • | Significantly reduced our cycle times by reducing average drilling days for longer lateral wells (> 1.5 miles) from approximately 45 days (spud to total depth) to approximately 17 days. |
Successfully completed 7 gross wells (5.4 net) during 2019, despite temporary suspensions in the Company’s drilling and completions program.
Reduced average drilling costs per well by 26% compared to wells drilled by previous operations management in 2018.
Secured necessary power commitments to begin full electrification of our Texas field and currently in the process of securing the necessary power commitments for our New Mexico field.
Received 2-year extended flaring permits to mitigate the need for future shut-ins associated with regulatory flaring compliance and have implemented solutions for delivering all produced natural gas to sales by the end of the second quarter of 2020.
Received three drilling permits from the Bureau of Land Management in New Mexico. In addition, the Company has 13 submitted permits in various stages of review.
Completed two significant transactions that brought approximately $56 million of capital into the Company
Sold 513 net undeveloped acres in New Mexico, noncontiguous to the Company’s core operational area, for approximately $33,000 per net acre
Completed an overriding royalty interest and working interest transaction
Realized oil pricing of 91% of WTI for 2019 versus 82% of WTI as compared to 2018.
Achieved commodity volume mix of 73% Liquids, including 61% crude oil, resulting in 95% of revenue attributable to Liquids sales during 2019
2020 Updates
Brought additional capital of $24.1 million into the Company through the sale of certain undeveloped leasehold assets in New Mexico.
Successfully installed gas treating system on certain well locations and are now in the final stages of testing the treated gas that will flow to sales. We anticipate all treated natural gas production to be flowing to sales during the second quarter of 2020.
In 2020, the Company has entered into the Seventh Amendment through the Fourteenth Amendment to the Revolving Credit Agreement which, among other things, amended the following table compares operating data(Refer to Note 11 - Long-Term Debt for additional information):
Reduced our borrowing base to $90.0 million, resulting in a borrowing base deficiency of $25.0 million,
Extended the due date for the years endedfinal borrowing base deficiency payment to June 5, 2020, and
Waived compliance with the Leverage Ratio and Current Ratio covenants as of December 31,
20162019 and
2015 (in thousands):| | | Years Ended December 31, | | | | | | | |
| | | 2016 | | | 2015 | | | Variance | | | % | |
| | | (In Thousands) | | | | | | | |
| Revenue: | | | | | | | | | | | | | | | | |
| Oil | | $ | 2,418 | | | $ | 292 | | | $ | 2,126 | | | | 728 | % |
| Gas | | | 1,012 | | | | 77 | | | | 935 | | | | 1214 | % |
| Other | | | 5 | | | | 27 | | | | (22 | ) | | | -81 | % |
| | | $ | 3,435 | | | $ | 396 | | | $ | 3,039 | | | | 767 | % |
Total Revenue
Total revenueMarch 31, 2020.
In response to recent commodity prices and our efforts to strengthen our capital through reducing operating costs, during April 2020 the Company elected to shut-in 12 wells which were identified as uneconomic as a result of the continued decline in commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate.
The Company has also implemented an employee furlough program to further reduce general and administrative costs. The furloughed employees will not receive compensation from the Company during the furlough period; however, subject to local regulations, these employees will be eligible for unemployment benefits. The furlough period is uncertain at this time and will be reassessed as business conditions dictate.
Access to Infrastructure
We entered into an amendment to our previously negotiated water gathering and disposal agreement and entered into a new crude oil sales contract to support the sales of our production of Liquids and natural gas, including transportation and sales agreements and salt water gathering and disposal agreements. We believe these agreements secure us cost effective movement of our Liquids and natural gas production in Texas and Mexico. Our agreements and relationships with SCM and ARM also provide the company with optionality in production storage capacity and down-stream transportation capacity.
On March 11, 2019, the Company, SCM Water, and ARM Energy Management, LLC (“ARM”), a related company to SCM Water, agreed to amend the terms of the previously negotiated water gathering and disposal agreement and entered into a new crude oil sales contract. Under the terms of such agreements, the Company agreed to an increase in salt water disposal rates in exchange for more favorable pricing differentials on the crude oil sales contract, modification on the minimum quantities of crude oil required under the crude oil sales contract, an upfront payment of $2.5 million and the elimination of the potential bonus for hitting a target of 40,000 barrels of produced water per day.
Market Conditions and Commodity Pricing
Our financial results depend on many factors, including the price of oil, natural gas and NGLs and our ability to market our production on economically attractive terms. We generate the majority of our revenues from sales of Liquids and, to a lesser extent, sales of natural gas. The price of these products are critical factors to our success and volatility in these prices could impact our results of operations. In addition, our business requires substantial capital to acquire properties and develop our non-producing properties. The price of oil, natural gas and NGLs have fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations and to concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil and natural gas. This significant decline and any further declines in the price of oil, natural gas and NGLs have reduced our revenues and result in lower cash inflow which have made it more difficult for us to pursue our plans to acquire new properties and develop our existing properties. Such declines in oil, natural gas, and NGL prices also adversely affect our ability to obtain additional funding on favorable terms.
Commodity prices continued to significantly decrease during first quarter 2020, through the date of filing. As of March 31, 2020, the Company was approximately $3.4 million ($1.8 millionnot in compliance with the Leverage Ratio and Current Ratio covenants and received a waiver from Brushy) forthe requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020.
Results of Operations – For the Years Ended December 31, 2019 and 2018
Current Operations Update
During the year ended December 31, 20162019, seven horizontal wells were placed on production. As of December 31, 2019, we have 41 gross operated wells, of which 30 horizontal wells and 9 legacy vertical wells were producing and flowing to sales. We received three drilling permits from the Bureau of Land Management in New Mexico and are nearing completion on several additional New Mexico permits.
To enhance performance, the Company has installed artificial lift on select wells. Currently, eleven wells have been placed on artificial lift.
In July 2019, we self-elected to temporarily shut-in four of our wells to remain within Texas flaring regulations. By the end of the third quarter, we brought all four of those previously shut-in wells back online and flowing to sales, received extended flaring permits in Texas to mitigate the need for future shut-ins due to regulatory compliance, and continue to advance efforts with the implementation of field treating solutions. The treating systems involve chemical intervention, upgrades to the surface facilities at each tank battery and upgrades to natural gas handling facilities for specific wells that do not meet quality specifications. The facility upgrades necessary for the crude oil treating implementation has been completed and our third-party crude gathering system is currently capable of flowing treated crude to all receipt points. The natural gas treating solution continues to be advanced and began delivering treated natural gas, that was previously being flared, to sales in the first quarter of 2020.
Effective March 1, 2019, the Company began selling its crude oil under a single long-term contract with a term that extends to at least December 31, 2024. The purchaser’s commitment has a quantity-based limit set forth in the contract, measured in barrels per day, with the maximum quantity commitment increasing at periodic intervals over the life of the contract to coincide with the Company’s expected growth in production. Pursuant to the long-term contract, pricing is based on posted indexes for crude oil of similar quality, with a differential based on pipeline delivery to Houston.
In May 2018, we engaged SCM to implement a gathering system to transport our crude oil production. Due to ongoing matters involving construction and use of the gathering system, we have not been able to use the system as expected, which has delayed our realization of efficiencies in getting our production to sales and has increased our transportation costs on sales.
Sales Volumes and Revenues
The following table sets forth selected revenue and sales volume data for the years ended December 31, 2019 and 2018:
|
| | | | | | | | | | | | | | |
| | Years Ended December 31, | | | | |
| | 2019 | | 2018 | | Variance | | % |
| Net sales volume: | | | | | | | |
| Oil (Bbl) | 1,130,855 |
| | 1,089,724 |
| | 41,131 |
| | 4 | % |
| Natural gas (Mcf) | 3,063,927 |
| | 2,855,739 |
| | 208,188 |
| | 7 | % |
| NGL (Bbl) | 220,832 |
| | 246,425 |
| | (25,593 | ) | | (10 | )% |
| Total (BOE) | 1,862,342 |
| | 1,812,106 |
| | 50,236 |
| | 3 | % |
| Average daily sales volume (BOE/d) | 5,102 |
| | 4,965 |
| | 137 |
| | 3 | % |
| Average realized sales price: | | | | | | | |
| Oil ($/Bbl) | $ | 52.19 |
| | $ | 53.26 |
| | $ | (1.08 | ) | | (2 | )% |
| Natural gas ($/Mcf) | 1.04 |
| | 1.84 |
| | (0.80 | ) | | (44 | )% |
| NGL ($/Bbl) | 17.52 |
| | 28.11 |
| | (10.59 | ) | | (38 | )% |
| Total ($/BOE) | $ | 35.47 |
| | $ | 38.75 |
| | $ | (3.28 | ) | | (8 | )% |
Oil, natural gas and NGL revenues (in thousands): | | | | | | | |
| Oil revenue | $ | 59,015 |
| | $ | 58,042 |
| | $ | 973 |
| | 2 | % |
| Natural gas revenue | 3,180 |
| | 5,246 |
| | (2,066 | ) | | (39 | )% |
| NGL revenue | 3,868 |
| | 6,928 |
| | (3,060 | ) | | (44 | )% |
| Total revenue | $ | 66,063 |
| | $ | 70,216 |
| | $ | (4,153 | ) | | (6 | )% |
Total sales volume increased 3% to 1,862,342 BOE during the year ended December 31, 2019, compared to $0.41,812,106 BOE during 2018, an increase of 50,236 BOE. The increase in total sales volume was primarily due to 7 gross (5.4 net) additional wells placed on production since the third quarter of 2018. Total revenue decreased $4.2 million to $66.1 million for the year ended December 31, 2015, representing an increase of approximately $3.0 million or 767%. The increase in revenue was primarily attributable2019, as compared to approximately $1.8 million in revenues from Brushy’s operations during the second half of 2016 and increase of approximately $1.2 million in revenues from the DJ Basin due to increase in production volumes.The following table compares production volumes and average prices for the years ended December 31, 2016 and 2015:
| | | For the Year Ended
December 31, | |
| | | 2016 | | | 2015 | |
| Product | | | | | | | | |
| Oil (Bbl.) | | | 61,088 | | | | 7,067 | |
| Oil (Bbls)-average price | | $ | 39.59 | | | $ | 41.36 | |
| | | | | | | | | |
| Natural Gas (MCFE)-volume | | | 400,775 | | | | 32,291 | |
| Natural Gas (MCFE)-average price | | $ | 2.54 | | | $ | 2.39 | |
| | | | | | | | | |
| Barrels of oil equivalent (BOE) | | | 127,863 | | | | 12,449 | |
| Average daily net production (BOE) | | | 350 | | | | 34 | |
| Average Price per BOE | | $ | 26.87 | | | $ | 29.67 | |
Oil and Gas Production Costs, Production Taxes, Depreciation, Depletion, and Amortization
The following tables compares oil and gas production costs, production taxes, depreciation, depletion, and amortization for the years ended December 31, 2016 and 2015:
| | | For the Year Ended
December 31, | |
| | | 2016 | | | 2015 | |
| Production costs per BOE | | $ | 9.75 | | | $ | 15.70 | |
| Production taxes per BOE | | | (1.30 | ) | | | 2.24 | |
| Depreciation, depletion, and amortization per BOE | | | 12.25 | | | | 46.93 | |
| Total operating costs per BOE | | $ | 20.70 | | | $ | 64.87 | |
| Gross margin per BOE | | $ | 6.17 | | | $ | (35.20 | ) |
| Gross margin percentage | | | 23 | % | | | (119 | )% |
| | | Years Ended December 31, | | | | | | | |
| | | 2016 | | | 2015 | | | Variance | | | % | |
| | | (In Thousands) | | | | | | | |
| Costs and expenses: | | | | | | | | | | | | | | | | |
| Production costs | | $ | 1,247 | | | $ | 195 | | | $ | 1,052 | | | | 539 | % |
| Production taxes | | | (167 | ) | | | 28 | | | | (195 | ) | | | -696 | % |
| General and administrative | | | 14,570 | | | | 7,930 | | | | 6,640 | | | | 84 | % |
| Depreciation, depletion and amortization | | | 1,566 | | | | 574 | | | | 992 | | | | 173 | % |
| Accretion of asset retirement obligations | | | 132 | | | | 10 | | | | 122 | | | | 1220 | % |
| Impairment of evaluated oil and gas properties | | | 4,718 | | | | 24,478 | | | | (19,760 | ) | | | -81 | % |
| Total operating expenses | | | 22,066 | | | | 33,215 | | | | (11,149 | ) | | | -34 | % |
| | | | | | | | | | | | | | | | | |
| Loss from operations | | $ | (18,631 | ) | | $ | (32,819 | ) | | $ | 14,188 | | | | -43 | % |
Production Costs
Production costs were $1.2$70.2 million for the year ended December 31, 2016,2018, representing a 6% decrease. The decrease was primarily attributable to lower realized prices partially offset by increased volumes.
Operating Expenses
The following table shows a comparison of operating expenses for the years ended December 31, 2019 and 2018:
|
| | | | | | | | | | | | | | |
| | Years Ended December 31, | | |
| | 2019 | | 2018 | | Variance | | % |
| Operating Expenses per BOE: | |
| | |
| | |
| | |
|
| Production costs | $ | 8.66 |
| | $ | 7.64 |
| | $ | 1.02 |
| | 13 | % |
| Gathering, processing and transportation | 2.13 |
| | 1.87 |
| | 0.26 |
| | 14 | % |
| Production taxes | 1.77 |
| | 2.05 |
| | (0.28 | ) | | (14 | )% |
| General and administrative | 15.23 |
| | 18.35 |
| | (3.12 | ) | | (17 | )% |
| Depreciation, depletion, amortization and accretion | 17.85 |
| | 14.00 |
| | 3.85 |
| | 28 | % |
| Impairment of oil and natural gas properties | 122.60 |
| | — |
| | 122.60 |
| | 100 | % |
| Total operating expenses per BOE | $ | 168.24 |
| | $ | 43.91 |
| | $ | 124.33 |
| | 283 | % |
| | | | | | | | |
Operating Expenses (in thousands): | |
| | | | | | |
| Production costs | $ | 16,127 |
| | $ | 13,843 |
| | $ | 2,284 |
| | 16 | % |
| Gathering, processing and transportation | 3,960 |
| | 3,392 |
| | 568 |
| | 17 | % |
| Production taxes | 3,302 |
| | 3,709 |
| | (407 | ) | | (11 | )% |
| General and administrative | 28,371 |
| | 33,251 |
| | (4,880 | ) | | (15 | )% |
| Depreciation, depletion, amortization and accretion | 33,252 |
| | 25,367 |
| | 7,885 |
| | 31 | % |
| Impairment of oil and natural gas properties | 228,324 |
| | — |
| | 228,324 |
| | 100 | % |
| Total operating expenses | $ | 313,336 |
| | $ | 79,562 |
| | $ | 233,774 |
| | 294 | % |
Production Costs
Production costs increased by $2.3 million, or 16%, to $16.1 million for the year ended December 31, 2019, compared to $0.2$13.8 million for the year ended December 31, 2018, due, in part, to the 7 gross (5.4 net) increase in producing wells during 2019. Our production costs on a per BOE basis increased by $1.02, or 13%, to $8.66 for the year ended December 31, 2019, as compared to $7.64 per BOE for the year ended December 31, 2018. The increase in production costs per BOE was primarily the result of increased equipment rentals related to artificial lift and workover charges.
Gathering, Processing and Transportation
Gathering, processing and transportation costs increased by $0.6 million to $4.0 million for the year ended December 31, 2019, compared to $3.4 million for the year ended December 31, 2015,2018. This cost increase was primarily the result of higher sales volumes of natural gas. The cost on a per BOE basis increased 14% from $1.87 for the year ended December 31, 2018, to $2.13 for the year ended December 31, 2019, primarily attributable to higher per BOE costs under our long-term natural gas purchase contract as compared to the short-term natural gas contract in the comparative period.
Production Taxes
Production taxes decreased $0.4 million to $3.3 million for the year ended December 31, 2019, compared to $3.7 million for the same period in 2018. On a per BOE basis, production taxes decreased to $1.77 per BOE for the year ended December 31, 2019, a 14% decrease from the $2.05 per BOE for the year ended December 31, 2018, primarily due to lower revenue for 2019 as compared to 2018.
General and Administrative Expenses (“G&A”)
G&A decreased by $4.9 million to $28.4 million for the year ended December 31, 2019, as compared to $33.3 million for the year ended December 31, 2018. The decrease of $4.9 million in G&A was primarily attributable to a decrease in stock-based compensation of $2.5 million, a decrease in personnel costs of $1.0 million including severance costs and directors fees, and a $1.4 million decrease in professional services.
Depreciation, Depletion, Amortization and Accretion (“DD&A”)
DD&A expense was $33.3 million for the year ended December 31, 2019, compared to $25.4 million for the year ended December 31, 2018; resulting in an increase of $1$7.9 million, or 539%31%. Our DD&A rate increased by 28% to $17.85 per BOE during the year ended December 31, 2019 from $14.00 per BOE for the year ended December 31, 2018. To a smaller degree, DD&A expense increased as a result of a 3% increase in sales volumes for the year ended December 31, 2019 as compared to the year ended December 31, 2018. The increase was primarily due to a net increase of proved oil and natural gas net book value, prior to impairment, and a 71% decrease in total proved reserves volumes on a BOE basis.
Impairment of Oil and Natural Gas Properties
The Company recorded charges for impairment of oil and natural gas properties of $228.3 million for the year endedDecember 31, 2019. The increasenet book value of the Company’s oil and natural gas properties exceeded the ceiling limitation calculated as required under the full cost method of accounting at December 31, 2019 and September 30, 2019. December 31, 2019 discounted future net cash flows and proved reserves volumes decreased 63% and 71%, respectively, from our December 31, 2018 proved reserves report. As a result of the uncertainty in our ability to fund future development costs associated with proved undeveloped reserves, all proved undeveloped reserves were reclassified to unproved. The reclassification represented nearly 23%, or $75.3 million, of the decrease in discounted future net cash flows and approximately 50% of the decrease in proved volumes, or 21,487 MBOE. Oil and natural gas pricing, calculated as required by the SEC, decreased approximately 16% from December 31, 2018 as compared to December 31, 2019. Proved reserve volumes reported in the December 31, 2019 proved reserves report were over 20%, or 8,699 MBOE, lower due to the decrease in pricing. Discounted future net cash flows decreased more than 40%, or $131.5 million, as a result of the decrease in pricing used in estimating proved reserves.
Other Income (Expenses)
The following table shows a comparison of other expenses for the years ended December 31, 2019 and 2018:
|
| | | | | | | | | | | | | | |
| | Years Ended December 31, | | | | |
| | 2019 | | 2018 | | Variance | | % |
| | (In Thousands) | | | | |
| Other income (expense): | |
| | |
| | |
| | |
|
| Loss on early extinguishment of debt | $ | (1,299 | ) | | $ | (20,370 | ) | | $ | 19,071 |
| | (94 | )% |
| Gain (Loss) from commodity derivatives, net | (8,985 | ) | | 55 |
| | (9,040 | ) | | (16,436 | )% |
| Change in fair value of financial instruments | (3,573 | ) | | 58,343 |
| | (61,916 | ) | | (106 | )% |
| Interest expense | (11,426 | ) | | (32,827 | ) | | 21,401 |
| | (65 | )% |
| Other income | 435 |
| | 2 |
| | 433 |
| | 21,650 | % |
| Total other income (expenses) | $ | (24,848 | ) | | $ | 5,203 |
| | $ | (30,051 | ) | | (578 | )% |
Loss on Early Extinguishment of Debt
In 2019, the Company repurchased certain overriding royalty interests in the acreage previously sold under the ORRI Agreement (as defined in Note 5 - Acquisitions and Divestitures to our consolidated financial statements), resulting in a $1.3 million loss on extinguishment of a portion of the financing arrangement.
On October 10, 2018, we converted approximately $68.3 million of our Second Lien Credit Agreement into a combination of 39,254 shares of Series D Preferred Stock, stated value of $1,000 per share, and 5,952,763 shares of common stock. As a result, we recorded a loss of approximately $12.3 million on early extinguishment of debt. Concurrently, we executed the Revolving Credit Agreement, from which we received proceeds of $60.0 million that were used to pay off the outstanding balance of the Riverstone First Lien Credit Agreement totaling $57.0 million, including accrued interest and prepayment penalties. As a result
of the prepayment of the Riverstone First Lien Credit Agreement, we recorded a loss of approximately $8.1 million on early extinguishment of debt.
Gain (Loss) from Commodity Derivatives, net
Loss on our commodity derivatives increased by $9.0 million during the year ended December 31, 2019, resulting primarily from changes in underlying commodity prices as compared to the hedged prices within derivative instruments and the monthly settlement of those instruments. Additionally, during the year ended December 31, 2019, our net loss from commodity derivatives consisted primarily of net losses of $3.4 million from settled positions and $5.6 million from mark-to-market adjustments on unsettled positions. During the year ended December 31, 2018, our net loss from commodity derivatives consisted primarily of net losses of $1.9 million from settled positions and $2.0 million from mark-to-market adjustments on unsettled positions.
Change in Fair Value of Financial Instruments
The change in fair value of financial instruments is primarily attributable to Brushy’s operations. Production costs per BOE decreasedembedded derivatives associated with the conversion feature of the Second Lien Term Loan (as defined in Note 11 - Long-Term Debt to $9.75our consolidated financial statements). Changes in our stock price directly affect the fair value of the embedded derivative. During the period from January 1, 2019 to March 5, 2019, we recognized a loss of $0.3 million on the embedded derivative. On March 5, 2019, the embedded derivative was extinguished as part of the 2019 Transaction Agreement (as defined in Note 11 - Long-Term Debt to our consolidated financial statements).
As of December 31, 2019, we recognized an embedded derivative associated the ARM sales agreement as the agreement no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met (see Note 21 - Commitments and Contingencies to our consolidated financial statements). Upon recognition, we recorded a loss of $3.2 million on the embedded derivative.
Interest Expense
Interest expense for the year ended December 31,
2016 from $15.70 in 2015, a decrease of $5.95 per BOE, or 38%, primarily due2019 was $11.4 million compared to
Brushy’s lower production costs. The Company anticipates that its production costs in the near term would be closer to the level of Brushy’s historical production costs.Production Taxes
Production taxes were $(0.2)$32.8 million for the year ended December 31, 2016, compared to $0.03 million for2018. For the year ended December 31, 2015, a decrease2019, interest expense included $6.5 million from the Revolving Credit Agreement, $1.6 million of $(0.2)PIK interest, $0.9 million or -696%. Currently, ad valorem, severancefrom financing arrangements, $1.7 million related to amortization of the debt discount on our Second Lien Term Loan and conservation taxes range from 1% to 13% based on the state and county from which production is derived. Production taxes per BOE decreased to $(1.30) during$0.8 million for amortization debt issuance costs. For the year ended December 31, 2016 from $2.24 in 2015, a decrease of $(3.54) or -158%. Subsequent to the issuance of our consolidated financial statements for the year ended December 31, 2016,2018, we determined that certain ad valorem and severance tax estimates were higher than the actual amount billed, resulting in a tax benefit to us.
General and Administrative Expenses
General and administrative expenses were $14.5 million during the year ended December 31, 2016, compared to $7.9 million during the year ended December 31, 2015, an increase of $6.6 million, or 84%. The increase of $6.6 million in general and administrative expenses was attributable to an increase of $3.9 million to $7.1 million in non-cash stock-based compensation expense, a $0.6 million increase in legal fees associated with the Merger, an increase of $1.5 million in payroll primarily due to the addition of 18 former Brushy employees, bonuses paid to officers at the completion of the Merger and an increase of $0.6 million in other administrative office expenses.
Depreciation, Depletion, and Amortization
Depreciation, depletion, and amortization (“DD&A”) was $1.6 million during the year ended December 31, 2016, compared to $0.6 million during the year ended December 31, 2015, an increase of $1.0 million, or 173%. The increase in DD&A was the result of the increase in production associated with the acquisition of the oil and gas properties in the Delaware Basin, New Mexico and Winkler County, Texas after the Merger. As a result of the Merger, our DD&A rate decreased to $12.25 per BOE in 2016 from $46.93 per BOE in 2015. The DD&A rate decreased primarily due to the volumes increase of 115,414 barrels, or 927% from 12,449 BOE in 2015.
Impairment of Evaluated Oil and Gas Properties
Total impairment charges of $4.7 million were recorded during year ended December 31, 2016 as compared to $24.5 million during the year ended December 31, 2015, a decrease of $19.8 million or 81%. The decrease of $19.8 million was primarily due to full cost limitations recognized in the first and third quarter of 2015. The impairmentincurred interest expense of $24.5$32.8 million, which included $3.0 million for quarterly interest payments on notes payable and term loans, $12.2 million of PIK interest, $14.4 million related to amortization of debt discount on our Second Lien Term Loan and $3.2 million for amortization debt issuance costs. The Second Lien Term Loan was converted to common and preferred stock in 2015 was attributable to the write off of our proved undeveloped oilMarch 2019, and, gas properties in the DJ Basin due to lack of available capital to fund development coupled with significant decrease in oil prices, and to a lesser extent, natural gas prices, that started in late 2014 and continued throughout 2015.
| | | Years Ended December 31, | | | | | | | |
| | | 2016 | | | 2015 | | | Variance | | | % | |
| | | (In Thousands) | | | | | | | |
| Other income (expenses): | | | | | | | | | | | | | | | | |
| Other income | | | 90 | | | | 3 | | | | 87 | | | | 2900 | % |
| Debt conversion inducement expense | | | (8,307 | ) | | | - | | | | (8,307 | ) | | | -% | |
| Gain on extinguishment of debt | | | 250 | | | | - | | | | 250 | | | | -% | |
| Gain (loss) in fair value of derivative instruments | | | (1,222 | ) | | | 1,638 | | | | (2,860 | ) | | | -175 | % |
| Gain (loss) in fair value of conditionally redeemable 6% preferred stock | | | (701 | ) | | | 514 | | | | (1,215 | ) | | | -236 | % |
| Gain on modification of convertible debts | | | 602 | | | | - | | | | 602 | | | | -% | |
| Interest expense | | | (4,924 | ) | | | (1,697 | ) | | | (3,227 | ) | | | 190 | % |
| Total other income (expenses) | | | (14,212 | ) | | | 458 | | | | (14,670 | ) | | | -3203 | % |
| | | | | | | | | | | | | | | | | |
| Net loss | | | (32,843 | ) | | | (32,361 | ) | | | (482 | ) | | | 1 | % |
Inducement Expense
During the year ended December 31, 2016, an inducement expense of approximately $8.3 million was incurred as a result, there was less paid-in-kind interest and amortization of debt and equity restructuring associated with the Merger. The inducement expense resulted from the repricing of our warrants to induce conversion of our convertible debt and our Series A preferred stock into common stock.
Gain on Extinguishment of Debt
During the year ended December 31, 2016, we recognized a gain of approximately $0.3 million attributed to a discount from Heartland Bank to settle the outstanding balance we owed under the Heartland Credit Agreement.
Change in Fair Value in Derivative Instruments
The change in fair values of derivative instruments comprised a loss of approximately $1.2 million during the year ended December 31, 2016, as compared to an approximately $1.6 million gain during the year ended December 31, 2015, is as follows:
| · | Bristol Warrant Liabilities.On September 2, 2014, we entered into a Consulting Agreement with Bristol Capital, LLC (“Bristol”), pursuant to which we issued to Bristol a warrant to purchase up to 100,000 shares of our common stock at an exercise price of $20.00 per share (or, in the alternative, 100,000 options, but in no case both). The agreement has a price protection feature that will automatically reduce the exercise price if we enter into another consulting agreement pursuant to which warrants are issued with a lower exercise price, which triggered in year 2016 and accordingly, the Company agreed to issue additional warrants/options to purchase 541,026 shares of common stock at a revised exercise price of $3.12. The change in fair value of this warrant provision was a loss of $1.2 million and a gain of $0.4 million for the years ended December 31, 2016 and 2015, respectively. |
| · | Heartland Warrant Liability.On January 8, 2015, we entered into the Heartland Credit Agreement. In connection with the Heartland Credit Agreement, we issued to Heartland a warrant to purchase up to 22,500 shares of our common stock at an exercise price of $25.00. The warrant contains a price protection feature that will automatically reduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price. The change in fair value valuation from issuance was $0.03 million and $0.01 million for the year ended December 31, 2016 and 2015, respectively. |
| · | SOSV Investments LLC Warrant Liability. On June 23, 2016, in conjunction with the Merger, we issued to SOSV Investments LLC (“SOS”) a warrant to purchase up to 200,000 shares of our common stock at an exercise price of $25.00. The warrant contains a price protection feature that will automatically reduce the exercise price if we enter into another agreement pursuant to which warrants are issued with a lower exercise price. For the year ended December 31, 2016, we incurred a change in the fair value of the derivative liability related to the warrant of approximately $0.1 million. |
Interest Expense
For the years ended December 31, 2016
Going Concern and
2015, we incurred an interest expense of approximately $4.9 million and $1.7 million, respectively, of which approximately $4.2 million and $1.3 million was classified as non-cash interest expense in 2016 and 2015, respectively. The details of the non-cash interest expense for the year ended December 31, 2016 are as follows: (i) accretion of $3.9 million of discount associated with bridge loans, convertible notes, the credit facility and term loan and (ii) amortization of the deferred financing costs of $0.3 million. The non-cash interest expense for the year ended December 31, 2015 was primarily attributable to the amortization of the deferred financing costs of approximately $0.1 million.At the current levels of net oil and gas production, cash balances, interest rates, and oil and gas prices, our revenue is unlikely to exceed our expenses. Unless and until we invest a substantial portion of our cash balances in interests in producing oil and gas wells or in one or more other ventures that produce revenue and net income, we are likely to experience net losses. With the exception of unanticipated environmental expenses and possible changes in interest rates and oil and gas prices, we are not aware of any other trends, events, or uncertainties that have had or that are reasonably expected to have a material impact on net sales or revenues or income from continuing operations.
Liquidity and Capital Resources
Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and investors, the sale of equity
and equity derivative securities and
targeted asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments.
In 2016, we entered into a newOur ability to fund planned capital expenditures and to make acquisitions depends upon commodity prices, our future operating performance, availability of borrowings under our Revolving Credit Agreement, and
completed a preferred stock offering to raise additional capital. We regularly evaluate alternative sourcesmore broadly, on the availability of
capital to complementequity and debt financing, which is affected by prevailing economic conditions in our
cash flow from operationsindustry and financial, business and other
sourcesfactors, some of
which are beyond our control. The Company has negative working capital,
as we pursue our long-term growth plans in the Delaware Basin. In order to fully fund our 2017 capital budget, we may be required to access to new capital through one or more offeringsa history of
equity.We have reported net operating losses and cash flows used in operations. We cannot predict whether additional liquidity from equity or debt financings or borrowings under our Revolving Credit Agreement will be available on acceptable terms, or at all, in the foreseeable future.
From time to time, we raise capital through the sale of oil and natural gas properties that are not in our current drilling plans. In August 2019, we sold approximately 513 noncontiguous net acres in New Mexico for net cash proceeds of $16.6 million. The Company repurchased certain overriding royalty interests in the acreage previously sold under the ORRI Agreement for $2.6 million, resulting in net proceeds of approximately $14 million that were used for general corporate purposes and to restart drilling and completion activity during the third quarter. We may continue to enter into such sales in the future.
During the year ended December 31, 20162019, we exchanged and converted our outstanding Second Lien Term Loan with a face value of approximately $133.6 million for a combination of preferred stock and common stock, of which $60.0 million was converted into Series E Preferred Stock, $55.0 million was converted into Series F Preferred Stock, and $18.6 million was converted
into common stock based on a $1.88 per share issuance price. Additionally, the conversion features and voting rights on the existing Series C Preferred Stock and Series D Preferred Stock were eliminated in exchange for the issuance of 7.8 million shares of our common stock. The net dilution to our common stockholders was decreased by approximately 12 million shares as the result of the conversion of the Second Lien Term Loan and the elimination of the conversion features on the Series C Preferred Stock and the Series D Preferred Stock.
In 2019, we relied significantly on borrowings under our Revolving Credit Agreement to provide drilling and completion capital and for
the past five years. As a result, we fundedother general corporate purposes. Our ability to maintain or increase our
operations in 2016borrowing base under our Revolving Credit Agreement is dependent on numerous factors, including our ability to add proved reserves and production, commodity prices and the
merger with Brushy Resources, Inc. through additional debtlending policies of our lenders. We currently have four wells drilled and
equity financing. On September 29, 2016, we entered into a new Creditawaiting completion (referred to as “DUC” wells) that, when and
Guaranty Agreement (the “Credit Agreement”) that provides for a three-year, senior, secured term loan with initial aggregate principal commitments of $31 million and a maximum facility size of $50 million. The initial commitment on the term loan was funded with $25 million collected as of September 30, 2016 and the additional $6 million collected as of November 11, 2016.if completed, would add to our current production cash flows in 2020.
As of December 31, 2016,2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt to our Consolidated Financial Statements), with $115 million of indebtedness outstanding under our Revolving Credit Agreement. As provided for in the Seventh Amendment to our Revolving Credit Agreement and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million.
As a result of the January 17, 2020 redetermination of the borrowing base, a borrowing base deficiency in the amount of $25 million (the “Borrowing Base Deficiency”) was created under the Revolving Credit Agreement. The Borrowing Base Deficiency constitutes the difference between the principal amount of borrowings currently outstanding under the Revolving Credit Agreement, $115 million, and the borrowing base as so redetermined, $90 million. On February 28, 2020, we paid $17.25 million towards the Borrowing Base Deficiency. Pursuant to the Fourteenth Amendment to the Revolving Credit Agreement, the remaining payment of $7.8 million is due June 5, 2020.
The Company is seeking additional funding and considering certain strategic transactions to enable it to pay the remaining Borrowing Base Deficiency amount of $7.8 million. There is no assurance, however, that funding or additional transactions will be completed or that the bank group will agree to further deficiency payment extensions. If the Company hadis unable to repay the remaining borrowing base deficiency as and when required under the Revolving Credit Agreement, an event of default would occur under the Revolving Credit Agreement.
Our next borrowing base redetermination is scheduled to occur on or about June 5, 2020. If the borrowing base is further reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base as we do not have sufficient additional oil and natural gas properties to eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a working capital balancesix-month period after the redetermination.
Our liquidity and ability to comply with debt covenants under our Revolving Credit Agreement have been negatively impacted by the recent decrease in commodity prices, which have fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil and natural gas. Our Revolving Credit Agreement contains financial covenants that require the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a cash balanceratio of approximately $5.7 millionCurrent Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter thereafter. See Note 11-Long-term Debt to our consolidated financial statements for additional information regarding the financial covenants under our Revolving Credit Agreement. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and $11.5 million, respectively. Current Ratio covenants under the Revolving Credit Agreement. Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt to our consolidated financial statements), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of December 31, 2019.
As of March 1, 2017, after giving effect31, 2020, the Company was not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a drawdownwaiver from the requisite lenders of $7.1its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. If we are not able to pay or defer the $7.8 million in additional term loan debtBorrowing Base Deficiency due on June 5, 2020 or do not maintain compliance with the covenants, the obligations of the Company under the Revolving Credit Agreement may be accelerated, which would have a material adverse effect on February 7, 2017, but excluding,our business.
Fluctuations in oil and natural gas prices have a material impact on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. Historically, oil and natural gas
prices have been volatile, and may be subject to wide fluctuations in the commitments entered intofuture. Furthermore, the Company has negative working capital, a history of net operating losses and cash flows use in connectionoperations. If continued depressed prices persist, the Company will continue to experience operating losses, negative cash flows from operating activities, and negative working capital.
In order to improve our leverage position and current ratio to meet the financial covenants under the Revolving Credit Agreement, we are currently pursuing or considering a number of actions, which in certain cases may require the consent of current lenders and stockholders. In November 2019, our board of directors formed a Special Committee tasked with reviewing and evaluating strategic alternatives that may enhance the March 2017 Private Placement (defined below)value of the Company, including alternatives that may be available to identify and access further sources of liquidity. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters.
The Special Committee continues to explore financing alternatives and deleveraging transactions. We are also addressing operational matters such as adjusting our capital budget and improving cash balance was approximately $9.0 million. We believeflows from operations by continuing to reduce costs and intend to continue to pursue and consider other strategic alternatives.
There can be no assurance that we will havebe able to implement any of these plans successfully, or that such plans, if executed, will result in the ability to pay borrowing base deficiencies, generate sufficient liquidity to continue as a going concern or comply with our Revolving Credit Agreement covenants. These factors raise substantial doubt about our ability to continue as a going concern within twelve-month period following the date of issuance of these consolidated financial statements.
Our ability to fund our future operations, including drilling and completion capital
to operate over the next 12 months. However, it is possible that weexpenditures, will
seek to raise additional debt and equity capital depending on the pacelargely be dependent upon our active management of our drilling and
leasing activity.completion budget, and, if necessary, the continued suspension of our drilling plans until we are able to identify and access further sources of liquidity. We are currently considering alternative secured financing to replace the current revolving credit facility under our Revolving Credit Agreement. We are the operator of 100% of our 2020 operational capital program and we expect to operate a substantial majority of wells we may drill in the near future, and, as a result, we have had, and expect to continue to have, the discretion to control the amount and timing of a substantial portion of our capital expenditures. The Company has recently elected to temporarily suspend current drilling operations, until necessary funding is obtained, to focus on production and facilities optimization while the results and performance of the new wells are evaluated. In response to our efforts to strengthen our capital through reducing operating costs, during April 2020 the Company elected to shut-in 12 wells which were identified as uneconomic as a result of the continued decline in commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate. We may in the future, however, determine it prudent to extend the current suspension or temporarily suspend further drilling and completion operations due to capital constraints, shortage of liquidity, or reduced returns on investment as a result of commodity price weakness. Information about our year-end cash flows for the years ended December 31, 2019 and 2018, are presented in the following table (in(in thousands):| | | Year ended
December 31, | |
| | | 2016 | | | 2015 | |
| Cash provided by (used in): | | | | | | | | |
| Operating activities | | $ | (6,309 | ) | | $ | (3,951 | ) |
| Investing activities | | | (19,130 | ) | | | (1,703 | ) |
| Financing activities | | | 37,067 | | | | 5,254 | |
| Net change in cash | | $ | 11,628 | | | $ | (400 | ) |
|
| | | | | | | |
| | Years Ended December 31, |
| | 2019 | | 2018 |
| Cash provided by (used in): | |
| | |
|
| Operating activities | $ | (25,824 | ) | | $ | 92,132 |
|
| Investing activities | (65,527 | ) | | (242,935 | ) |
| Financing activities | 73,967 |
| | 154,478 |
|
| Net change in cash and cash equivalents | $ | (17,384 | ) | | $ | 3,675 |
|
Operating activities.Activities
For the year ended December 31, 2016,2019, net cash used in operating activities was $6.3$25.8 million, compared to $4.0net cash provided by operating activities of $92.1 million for the same period in 2015.year ended December 31, 2018. The increase of $2.3$25.8 million cash used in operating activities was primarily attributablemade up of net loss of $272.1 million, non cash adjustments to the increase in operating costsnet income of $282.5 million, and changescash used by change in working capital.capital of $36.2 million, primarily the result of payments of accounts payable outstanding at December 31, 2018.
Investing activities. Activities
For the year ended December 31, 2016,2019, net cash used in investing activities was $19.1$65.5 million, compared to $1.7$242.9 million for the same period in 2015.2018. The $17.4$65.5 million increase in cash used infor investing activities during the year ended December 31, 2019, was primarily attributable to the following: | · | a $7.5 million increase in drilling and completion costs on the Grizzly and Bison wells; |
| · | a $4.2 million increase in oil and gas lease extension fees; |
| · | a $2.3 million cash consideration for the Merger, net of cash acquired; and |
| · | a $3.4 million increase on other capital expenditures relating to the DJ Basin and the Delaware Basin properties. |
cash payments of approximately $82.4 million for capital expenditures on oil and gas properties; partially offset by
approximately $16.9 million in proceeds from the sale of assets.
Capital Expenditure Breakdown
During the year ended December 31, 2019, drilling and completion capital cost incurred was $93.1 million, comprised of $36.7 million on 2018 DUC wells and $40.3 million related to the 2019 drilling program, plus an additional $3.7 million related to the 2018 drilling program and $10.8 million for facility and water supply and disposal projects. Of the capital cost incurred on 2018 DUC wells, adjustments to Lilis’ working interests due to non-consent elections increased capital costs by $7.5 million while reducing accounts receivable from other working interest partners by that amount.
At December 31, 2019, we had four DUC wells compared to six DUC wells at December 31, 2018. Although additional costs were incurred on all six DUC wells during 2019, four wells were placed on production during 2019. Those four wells included the Oso #1H, Haley #1H, Haley #2H, and NE Axis #2H. In addition, three wells were drilled, completed and placed on production during the fourth quarter of 2019, those being the Kudu A#2H, Kudu B#2H and Grizzly A#2H.
During the second half of 2019, under the direction of the Company’s new operations team, significant reductions in drilling days and drilling costs have been achieved. Reduced drilling cycle times were realized by incorporating oil-based drilling mud, utilizing a higher quality rig and better down hole tools/configurations. This has reduced the number of bit trips by 44% and increased the rate of penetration by 110% over prior wells drilled in early 2019. The identification of optimal drilling zones within drilling targets has also reduced time spent slide drilling by 5%. The Company has also improved in-zone precision from approximately 89% in 2018 to approximately 100% in recent wells. In addition to these changes, continuous drilling optimization is being evaluated and implemented with different hole sizes and configurations to further reduce cycle times. If and when the Company obtains the capital required to do so, the Company expects to incorporate these improved techniques on all future wells with the goal of achieving similar cost savings.
|
| | | | | | | |
| | Year Ended
December 31, |
| | 2019 | | 2018 |
| Leasehold Acquisitions | | | |
| Proved | $ | — |
| | $ | 20,040 |
|
| Unproved | 1,643 |
| | 98,193 |
|
| 2017 Drilling & Completion Program | — |
| | 12,440 |
|
| 2018 Drilling & Completion Program | 3,658 |
| | 119,350 |
|
| 2018 Drilling & Completion Program-DUCs | 36,738 |
| | 24,887 |
|
| 2018 Working Interest Acquisitions | — |
| | 1,293 |
|
| 2019 Drilling & Completion Program | 40,263 |
| | — |
|
| Facilities & Other Projects | 10,824 |
| | 9,484 |
|
| Total Capital Spending | $ | 93,126 |
| | $ | 285,687 |
|
Financing activities.Activities
For the year ended December 31, 2016,2019, net cash provided by financing activities was $37.1$74.0 million compared to cash provided by financing activities of $5.3$154.5 million during the same period of 2015.in 2018. The increase of $31.8$74.0 million in net cash provided by financing activities was primarily attributable included $56.9 million in net proceeds from drawdowns on the Revolving Credit Agreement and $38.2 million in net proceeds from the ORRI Agreement and WI Agreement (as defined in Note 5 - Acquisitions and Divestitures to our consolidated financial statements), offset by repayment of $18.0 million on the following: | · | an $18.2 million increase in net proceeds from the issuance of the Series B preferred stock; |
| · | a $30.0 million increase in net proceeds from the term loan facility executed during the third quarter of 2016; |
| · | a $0.3 million increase in proceeds received from the exercise of stock warrants; |
| · | offset by a $3.1 million decrease in net proceeds from the Bridge Loans; and |
| · | offset by an increase of $13.6 million in repayment of principal balances due to the Heartland Bank and Independent Bank. |
Merger with Brushy
We paid deposits and operating expenses of Brushy toward completion of the Merger of approximately $3.0 million, net of $0.7 million cash acquired, which is recorded as additional consideration.
In connection with the closing of the Merger, we entered into the following financing transactions:
Series A Preferred Stock Conversion
Revolving Credit Agreement.
Capital Structure
Revolving Credit Agreement
On
June 23, 2016, after receiving the requisite shareholder approval and upon consummation of the Merger, each outstanding share of our Series A preferred stock automatically converted into common stock at a conversion price of $5.00 resulting in the issuance of 1,500,000 shares of common stock. In exchange for the reduction in price to convert into our common stock, all accrued, but unpaid dividends were forfeited.Series B 6% Preferred Stock
On June 15, 2016,October 10, 2018, we entered into a private placement to sell 20,000 shares of our Series B 6% convertible preferred stockfive-year, $500 million senior secured revolving credit agreement (the “Series B Preferred Stock”“Revolving Credit Agreement”) with a conversion price of $1.10by and warrants to purchase up to 9,090,926 shares of common stock at an exercise price of $2.50, exercisable immediately for a period of two years underamong the Company, as borrower, certain circumstances, for gross proceeds of $20 million. For a more detailed descriptionsubsidiaries of the terms of the Series B Preferred Stock see Note 13-Shareholders Equity.
In connection with the Series B Preferred Stock offering, we also paid a fee of $350,000 and $900,000 to T.R. Winston & Company, LLC (“TRW”) and KES 7 Capital Inc. (“KES 7”as guarantors (the “Guarantors”), respectively, who acted as co-placement agents with TRW also acting as administrative agent. Each of TRW and KES 7 also received fee warrants to purchase up to 452,724 and 820,000 shares of common stock, respectively, at an exercise price of $1.30, exercisable on or after September 17, 2016, for a period of two years. In addition, TRW received 150 shares of Series B Preferred Stock and the related warrants to purchase 68,182 shares of common stock at an exercise price of $2.50.
Debentures
On June 23, 2016, pursuant to the terms of the Debenture Conversion Agreement, dated as of December 29, 2015, our remaining outstanding 8% Convertible Debentures converted automatically upon consummation of the Merger at $5.00 per share, resulting in the issuance of 1,369,293 shares of common stock. In exchange for the lowering the conversion price, all accrued but unpaid interest was forfeited. The modification of such conversion rate resulted in an immaterial gain. The Convertible Debentures and associated derivative liability was then reclassified to additional paid-in capital.
HeartlandBMO Harris Bank,
On January 8, 2015, we entered into the Credit Agreement with Heartland Bank (the “Heartland Credit Agreement”) N.A., as administrative agent, and the Lenderslenders party thereto. The HeartlandRevolving Credit Agreement providedprovides for a three-year senior secured term loan inreserves based revolving credit facility with an initial aggregate principal amountborrowing base of $3,000,000 (the “Heartland Term Loan”).
In connection with the consummation of the Merger, on June 22, 2016, we repaid the balance of our outstanding indebtedness with Heartland at a discount of $250,000, resulting in the elimination of $2.75$95 million in senior secured debt and the extinguishment of Heartland’s security interest in our assets.
Independent Bank and Promissory Note
On June 22, 2016, in connection with the completion of the Merger, we entered into an amendment with Brushy and its senior secured lender, Independent Bank (the “Lender”), to Brushy’s Forbearance Agreement with the Lender (the “Fourth Amendment”), which, among other things, providedalso provides for a pay-down of $6.0 million of the principal amount outstanding on the loan (the “Loan”), plus fees and other expenses incurred in connection with the Loan, in exchange for an extension of the maturity date through December 15, 2016, at an interest rate of 6.5%, payable monthly. Additionally, we agreed to (i) guaranty the approximately $5.4 million aggregate principal amount of the Loan, (ii) grant a lien in favor of the Lender on all of our real and personal property, (iii) restrict the incurrence of additional debt and (iv) maintain certain deposit accounts with various restrictions with the Lender.
As a condition of the Fourth Amendment and pursuant to the Merger Agreement, Brushy also completed the divestiture of certain of its assets in South Texas to its subordinated lender, SOS Ventures (“SOS”), in exchange for the extinguishment of $20.5 million of subordinated debt, a cash payment of $500,000, the issuance of the SOS Note, and the issuanceletters of the SOS Warrant.
On September 29, 2016, we repaid the Independent Bank debt in full, resulting in the extinguishment of Independent Bank’s security interest.
Convertible Notes
In a series of transactions from December 29, 2015 to May 6, 2016, we issued an aggregate of approximately $5.8 million Convertible Notes maturing on June 30, 2016 and April 1, 2017, at a conversion price of $5.00. In connection with the December 2015 and March 2016 financing transactions, we issued warrants to purchase an aggregate of approximately 1.7 million shares of common stock with an exercise price of $2.50 per share and in connection with the May 2016 transaction, we issued warrants to purchase an aggregate of approximately 625,000 shares of common stock with an exercise price of $0.10 per share. Subsequently, as an inducement to participate in the May Convertible Notes offering, warrants to purchase up to 620,000 shares of common stock issued between December 2015 and March 2016 were amended and restated to reduce the exercise price to $0.10. As such, we recorded in other expense an inducement expense of $1.72 million. The proceeds of $5.8 million from these financing transactions were used to pay a $2.0 million refundable deposit in connection with the Merger, to fund certain operating expenses of Brushycredit in an aggregate amount up to $5 million. The borrowing base is subject to semiannual redetermination in May and November of $508,000,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
fund approximately $1.3 millionpay a commitment fee of
interest payments to Heartland0.5% 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
to fund approximately $2.0 million in working capitalthe Guarantors’ assets and
accounts payables.are unconditionally guaranteed by each of the Guarantors. In connection with
The Revolving Credit Agreement matures on the earlier of the fifth anniversary of the closing
ofdate and the
Merger, on June 23, 2016, we entered into a Conversion Agreement with certain holders of Convertible Notes in an aggregate principal amount of approximately $4.0 million (the “Note Conversion Agreement”). The terms of the Note Conversion Agreement provideddate that
the Convertible Notes were automatically converted into common stock upon the closing of the Merger. Pursuantis 180 days prior to
the terms of the Note Conversion Agreement, in exchange for immediate conversion upon closing, the conversion price of the Convertible Notes was reduced to $1.10, which resulted in the issuance of 3,636,366 shares of common stock. The modification of such conversion rate resulted in a $3.4 million inducement charge recorded in other expense. Holders of these Convertible Notes waived and forfeited approximately $198,000 rights to receive accrued but unpaid interest.��
On August 3, 2016, we entered into the first amendment to the Convertible Notes with the remaining holders of approximately $1.8 million of Convertible Notes. Pursuant to the first amendment: (i) the maturity date was changedof the Second Lien Credit Agreement (as defined below). Borrowings under the Revolving Credit Agreement are subject to January 2, 2017, (ii)mandatory repayment with the conversion price was adjustednet 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 $1.10time and, (iii) the coupon rate was increased to 15% per annum. All accrued and unpaid interest on the Convertible Notes would have also been convertible in certain circumstances at the conversion price. Additionally, if the aggregate principal amount outstanding on the Convertible Notes was not either converted by the holder or repaid in full on or before the maturity date, we agreed to pay a 25% premium on the maturity date. We accounted for the reduction in the conversion price of remaining outstanding convertible notes as an inducement expense and recognized approximately $1.6 million in other income (expense). In exchange for the holders’ willingness to enter into the first amendment, we issuedsubject to the holders of additional warrants to purchase up to approximately 1.65 million shares of common stock. The warrants issued were valued using the following variables: (a) stock price of $1.15, (b) exercise price of $2.50, (c) contractual life of 3 years, (d) volatility of 203%, and (e) risk free rate of 0.76% for a total value of approximately $1.63 million. This amount was recorded as an inducement expense and an offset to additional paid-in capital.
On September 29, 2016, in connection with our entry into the Credit Agreement, the remaining holders of the Convertible Notes converted the outstanding principal amount of approximately $1.8 million and accrued and unpaid interest in an amount of approximately $138,000 into 1,772,456 shares of common stock.
Credit Agreement and Warrant Repricing
Credit Agreement
On September 29, 2016, we entered into the Credit Agreement which provides for a three-year senior secured term loan with initial commitments of $31 million in aggregate principal amount, of which $25 million was collected as of September 30, 2016 and the additional $6 million was collected as of November 11, 2016. The initial aggregate principal amount may be increased to a maximum principal amount of $50,000,000 at our request, but at the discretion of the Lenders, pursuant to an accordion advance provision in the Credit Agreement (the “Term Loan”).
As discussed above, in connection with our entry into the Credit Agreement, on September 29, 2016, we used part of the proceeds of the Term Loan to repay the balance of Brushy’s outstanding indebtedness with Independent Bank, resulting in the elimination of approximately $5.4 million in senior secured debt, including accrued interest, fees and expenses, and the extinguishment of Independent Bank’s security interest in the assets of the Initial Guarantors and of our guaranty to Independent Bank in full.
Funds borrowed under the Credit Agreement may be used by us to (i) fund drilling and development projects, (ii) purchase oil and gas assetsborrowing base limitation and other acquisition targets, (iii) pay all costs and expenses arising in connection with the negotiation and execution of the Credit Agreement, and (iv) fund our general working capital needs.
In connection with our entry into the Credit Agreement, we paid advisory fees to KES 7 and TRW in an amount of $420,000 and $200,000, respectively and a commitment fee to each of the Lenders equal to 2.0% of their respective initial loan advances. As partial consideration given to the lenders, we also amended certain warrants issued in the Series B preferred stock offering held by the lenders during the third and fourth quarters of the year ended December 31, 2016, to purchase up to an aggregate amount of approximately 2,840,000 and 681,822 shares of common stock, respectively, suchcustomary conditions, may re-borrow amounts that the exercise price per share was lowered from $2.50 to $0.01 on such warrants. are voluntarily repaid.
The
portion repriced in the fourth quarter was due to certain delayed funding that occurred after the initial commitment. The number of warrants amended for each Lender was based on the amount of each Lender’s respective participation in the initial Term Loan relative to the amount invested in the June 2016 Series B Preferred Stock private placement. All of the amended warrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions. We accounted for the reduction in the conversion price as a deferred financing cost of $714,000 and will be amortized over the length of the loan.The Term Loan bears interest at a rate of 6.0% per annum and matures on September 30, 2019. We have the right to prepay the Term Loan, in whole or in part, at any time at a prepayment premium equal to 6.0% of the amount repaid. Such prepayment premium must also be paid if the Term Loan is repaid prior to maturity as a result of a change in control. In certain situations, the Credit Agreement requires mandatory prepayments of the Term Loans at the request of the Lenders, including in the event of certain non-ordinary course asset sales, the incurrence of certain debt and our receipt of proceeds in connection with insurance claims.
TheRevolving Credit Agreement contains certain customary representations and warranties and affirmative and negative covenants, including covenants relating toto: maintenance of books and records, financial reporting and notification, compliance with laws, maintenance of properties and insurance,insurance; and limitations on guaranties,incurrence of indebtedness, liens, fundamental changes, international operations, asset sales, certain debt payments and amendments, restrictive agreements, investments, issuancedividends and other restricted payments and hedging. It also requires the Company to maintain a ratio of debt, lease obligationsTotal Debt to EBITDAX of not more than 4.00 to 1.00 and capital expenditures.a ratio of current assets to current liabilities of not less than 1.00 to 1.00 (each as defined in the Revolving Credit Agreement).
As of December 31, 2019, the Company was not in compliance with the Current Ratio covenant or Leverage Ratio covenant under the Revolving Credit Agreement (as defined and described in Note 11 - Long-Term Debt to our consolidated financial statements). Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt to our consolidated financial statements), the Company obtained a waiver from the requisite lenders of its compliance with the Current Ratio and Leverage Ratio covenant, among other waivers, as of December 31, 2019.
Seventh Amendment to Revolving Credit Agreement
On January 17, 2020, the Company entered into a Seventh Amendment (the “Seventh Amendment”) to the Revolving Credit Agreement. The Seventh Amendment provided for the January 14, 2020 redetermination of the borrowing base under the Revolving Credit Agreement (the “Scheduled Redetermination”). As so redetermined, the borrowing base was set at $90 million. As a result of the Scheduled Redetermination, a borrowing base deficiency in the amount of $25 million existed under the Revolving Credit Agreement (the “Borrowing Base Deficiency”). The Seventh Amendment required repayment of the Borrowing Base Deficiency in four equal monthly installments, with the first payment of $6.25 million scheduled to occur on January 24, 2020.
Eighth Amendment to Revolving Credit Agreement
On January 23, 2020, the Company entered into an Eighth Amendment (the “Eighth Amendment”) to the Revolving Credit Agreement. The Eighth Amendment, among other things, amended the Revolving Credit Agreement to provide that the due date for the first Installment Payment was extended from January 24, 2020 to February 7, 2020 and that the due dates for the subsequent Installment Payments were February 14, 2020, March 16, 2020 and April 14, 2020.
Ninth Amendment to Revolving Credit Agreement
On February 6, 2020, the Company entered into an Ninth Amendment (the “Ninth Amendment”) to the Revolving Credit Agreement. The Ninth Amendment amended the Revolving Credit Agreement to provide that the due date for the first Installment Payment was extended from February 7, 2020 to February 18, 2020 and the due date for the second Installment Payment was extended from February 14, 2020 to February 18, 2020. The due dates for the two subsequent Installment Payments remained March 16, 2020 and April 14, 2020.
Tenth Amendment to Revolving Credit Agreement
On February 14, 2020, the Company entered into an Tenth Amendment (the “Tenth Amendment”) to the Revolving Credit Agreement. The Tenth Amendment amended the Revolving Credit Agreement to provide that the due date for the first two Installment Payments was extended from February 18, 2020 to February 28, 2020 and the due dates for the two subsequent Installment Payments remained March 16, 2020 and April 14, 2020.
Eleventh Amendment to Revolving Credit Agreement
On March 13, 2020, the Company entered into an Eleventh Amendment (the “Eleventh Amendment”) to the Revolving Credit Agreement. The Eleventh Amendment amended the Revolving Credit Agreement to extend the due date for the $1.50 million installment of the Borrowing Base Deficiency from March 16, 2020 to March 30, 2020. The due date for the final installment of the Borrowing Base Deficiency remained April 14, 2020.
Twelfth Amendment to Revolving Credit Agreement
On March 30, 2020, the Company entered into an Twelfth Amendment (the “Twelfth Amendment”) to the Revolving Credit Agreement. The Twelfth Amendment amended the Revolving Credit Agreement to, among other things extend the due date for the $1.50 million installment of the Borrowing Base Deficiency from March 30, 2020 to April 14, 2020. The due date for the final installment of the Borrowing Base Deficiency remains April 14, 2020. The lenders under the Revolving Credit Agreement also provides for eventswaived the requirement under the Revolving Credit Agreement that the Company comply with a leverage ratio and a current ratio, in each case, as of default,December 31, 2019, and granted certain other waivers, including failure to pay any principal or interest when due, failure to perform or observe covenants, cross-default on certain outstanding debt obligations, the failure of a Guarantorrequirement to comply with certain hedging obligations set forth in the provisionsRevolving Credit Agreement until June 30, 2020. Additionally, the lenders consented to an extension of an additional 45 days for the Company to provide its Guaranty,audited annual financial statements for the fiscal year ended December 31, 2019, and bankruptcywaived the requirement that such financial statements be delivered without a “going concern” or insolvency events.like qualification or exception.
Thirteenth Amendment to Revolving Credit Agreement
On April 14, 2020, the Company entered into a Thirteenth Amendment (the “Thirteenth Amendment”) to the Revolving Credit Agreement. The amountsThirteenth Amendment amended the Revolving Credit Agreement to extend the due date for the final $7.75 million installment of the Borrowing Base Deficiency from April 14, 2020 to April 21, 2020.
Fourteenth Amendment to Revolving Credit Agreement
On April 21, 2020, the Company entered into a Fourteenth Amendment (the “Fourteenth Amendment”) to the Revolving Credit Agreement. The Fourteenth Amendment, among other things, amended the Revolving Credit Agreement to extend the due date for the final $7.75 million installment of the Borrowing Base Deficiency from April 21, 2020 to June 5, 2020. The lenders under the Revolving Credit Agreement could be accelerated and be due and payable upon an event of default.Subsequent Events
also waived the requirement under the Revolving Credit Agreement Drawdown
that the Company comply with a leverage ratio and a current ratio, in each case, as of March 31, 2020. Additionally, the lenders consented to defer the timing of the scheduled spring redetermination of the borrowing base under the Revolving Credit Agreement from on or about May 1, 2020 to on or about June 5, 2020.
Second Lien Credit Agreement
On February 7,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”). The Second Lien Term Loan was subsequently converted into common stock and preferred stock in two separate transactions on October 2018 and March 2019 as described below.
Exchange and Conversion of Second Lien Term Loan and Issuance of Preferred Stock
On October 10, 2018, as consideration for the reduction by approximately $56.3 million of the outstanding principal amount of the Second Lien Term Loan under the Second Lien Credit Agreement, together with accrued and unpaid interest and the make-whole amount thereon totaling approximately $11.9 million, the Company entered into a transaction by and among the Company and certain private funds affiliated with the Värde Parties, pursuant to
which the
termsCompany agreed to issue to the Värde Parties an aggregate of 5,952,763 shares of the
Credit Agreement, we exercised the accordion advance feature, increasing the aggregate principal amount outstanding under the term loan from $31 million to $38.1 million. The total availability for borrowing remaining under the Credit Agreement is $11.9 million. We intend to use the proceeds to fund its drilling and development program, for working capital and for general corporate purposes.As partial consideration, we also amended certain warrants issued in the June 2016 private placement held by the Lenders to purchase up to an aggregate amount of approximately 738,638Company’s common stock, par value $0.0001 per share, which includes 5,802,763 shares of common stock such that the exerciseat an exchange price of $5.00 per share was lowered from $2.50 to $0.01 on such warrants The number of warrants amended for each Lender was based on the amount of each Lender’s respective participation in the initial Term Loan relative to the amount invested in the June 2016 private placement. All of the amended warrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions.
March 2017 Private Placement
On February 28, 2017, we entered into a Securities Subscription Agreement (the “Subscription Agreement”) with certain institutional and accredited investors in connection with a private placement (the “March 2017 Private Placement”) to sell 5.2 million units, consisting of approximately 5.2 millioncommon stock plus an additional 150,000 shares of common stock, and warrants39,254 shares of a newly created series of preferred stock of the Company, designated as “Series D 8.25% Convertible Participating Preferred Stock” (the “Series D Preferred Stock”);
On March 5, 2019, in exchange for satisfaction of the outstanding principal amount of the Second Lien Term Loan, accrued and unpaid interest thereon and the make-whole premium totaling approximately $133.6 million, the Company issued to purchase approximatelythe Värde Parties an additional 2.6aggregate of 60,000 shares of a newly created series of preferred stock of the Company, designated as “Series E 8.25% Convertible Participating Preferred Stock”, corresponding to $60 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value of the shares of Series E Preferred Stock; 55,000 shares of a newly created series of preferred stock of the Company, designated as “Series F 9.00% Participating Preferred Stock”, corresponding to $55 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value of the shares of Series F Preferred Stock; and 9,891,638 shares of common stock, forcorresponding to approximately $18.6 million of the Second Lien Exchange Amount, based on the $1.88 closing price of the common stock on the NYSE American on March 4, 2019.
In connection with the transaction, the Company also issued to the Värde Parties an aggregate purchase price of approximately $20] million. Each unit consists7,750,000 shares of one sharecommon stock as consideration for the Värde Parties’ consent to the amendment of the terms of the Series C Preferred Stock and the Series D Preferred Stock to, among other things, eliminate the convertibility of the Series C Preferred Stock and Series D Preferred Stock into shares of common stock and a warrant the voting rights of the Series C Preferred Stock and the Series D Preferred Stock.
See Note 13 - Related Party Transactions and Note 15 - Preferred Stock to purchase 0.50our consolidated financial statements for additional information about Related Party Transactions and the Company’s Preferred Stock.
Related Party Transactions
On March 5, 2019, pursuant to the 2019 Transaction Agreement and the related payoff letter, the Company agreed to issue to the Värde Parties shares of two new series of its preferred stock and shares of its common stock, (each,as consideration for the termination of the Second Lien Credit Agreement with the Värde Parties and the satisfaction in full, in lieu of repayment in cash, of the Second Lien Term Loan under the Second Lien Credit Agreement. See Note 11 - Long-Term Debt and Note 15 - Preferred Stock to our consolidated financial statements for additional information.
On July 31, 2019, the Company entered into two agreements with affiliates of Värde for the sale of an overriding royalty interest and a “Unit”)non-operated working interest in undeveloped assets. WLR’s (as defined in Note 5 - Acquisitions and Divestitures to our consolidated financial statements) proportionate share of revenue of $0.4 million for the year ended December 31, 2019 is included in interest expense on the Company’s consolidated statements of operations. Three of the properties included in the WI Agreement were producing as of December 31, 2019 and net revenue (revenue less production costs) of $0.5 million is included in interest expense on the Company’s consolidated statements of operations. See Note 5 - Acquisitions and Divestitures to our consolidated financial statements for additional information.
On August 16, 2019, the Company entered into an agreement with an affiliate of Värde to repurchase the overriding royalty interest for the New Mexico acreage sold. See Note 5 - Acquisitions and Divestitures to our consolidated financial statements for additional information.
On April 21, 2020, Värde Investment Partners, L.P., atan affiliate of Värde Partners, Inc., became a price per unitlender under our Revolving Credit Agreement by acquiring, from a prior lender, loans and commitments under the Revolving Credit Agreement in the principal amount of $3.85. Each warrant has an exercise price of $4.50approximately $25.7 million. The loans and may becommitments acquired by Värde Investment Partners, L.P. are subject to redemptioncertain subordination provisions set forth in the Revolving Credit Agreement, as amended by the Fourteenth Amendment thereto dated April 21, 2020. For additional information regarding our Revolving Credit Agreement, as amended, see Note 11 - Long-Term Debt to our consolidated financial statements included in this Annual Report and “Item 7 - Management’s
Discussion and Analysis of Financial Condition and Results of Operations - Revolving Credit Agreement” in Part II of this Annual Report.
Subsequent Events
Sale of Certain Undeveloped Acreage in New Mexico
On February 28, 2020, the Company
upon prior written notice, ifclosed the
sale of approximately 1,185 undeveloped net acres in Lea County, New Mexico, for net cash proceeds of approximately $24.1 million, subject to customary purchase price
adjustments. The proceeds were used to fund a substantial portion of the
Company’s common stock closes at or above $6.30 for twenty trading days during a consecutive thirty trading day period. The closing ofBorrowing Base Deficiency with the
Offering is subjectbalance to
the satisfaction of customary closing conditions.We expect to use the net proceeds from the Offering to support our planned 2017 capital budget, andbe used for general corporate purposes including working capital.
purposes.
COVID-19
On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency due to the COVID-19 outbreak, which originated in Wuhan, China, and the risks to the international community as the virus spreads globally beyond its point of origin. In March 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally.
In addition, in March 2020, members of OPEC failed to agree on production levels which has caused an increased supply and has led to a substantial decrease in oil prices and an increasingly volatile market. The securitiesoil price war ended with a deal to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand. There has been an increase in supply which has pushed prices down further since March. If the depressed pricing continues for an extended period it will lead to i) further reductions in the borrowing base under our credit facility which would require us to make additional borrowing base deficiency payments, ii) reductions in reserves, and iii) additional impairment of proved and unproved oil and gas properties. We also expect disclosures of supplemental oil and gas information to be soldimpacted by price declines.
In response to recent commodity prices and our efforts to strengthen our capital through reducing operating costs,during April 2020 the Company elected to shut-in 12 wells which were identified as uneconomic as a result of the continued decline in commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate. The Company has also implemented an employee furlough program to further reduce general and administrative costs. The furloughed employees will not receive compensation from the private placementCompany during the furlough period; however, subject to local regulations, these employees will be eligible for unemployment benefits. The furlough period is uncertain at this time and will be reassessed as business conditions dictate.
The full impact of the COVID-19 outbreak and the decline in oil prices continues to evolve as of the date of this Annual Report. As such, it is uncertain as to the full magnitude that these events will have on the Company’s financial condition, liquidity, and future results of operations.
Management is actively monitoring the global situation on its financial condition, liquidity, operations, suppliers, industry, and workforce. Given the daily evolution of the COVID-19 outbreak and the global responses to curb its spread, the Company is not been registered underable to estimate the Securitieseffects of the COVID-19 outbreak on its results of operations, financial condition, or liquidity for fiscal year 2020.
These matters could have a continued material adverse impact on economic and market conditions and trigger a period of global economic slowdown, which may impair the Company’s asset values, including reserve estimates. Further, consumer demand has decreased since the spread of the outbreak and new travel restrictions placed by governments in an effort to curtail the spread of the coronavirus. Although the Company cannot estimate the length or gravity of the impacts of these events at this time, if the pandemic and/or decreased oil prices continue, they will have a material adverse effect on the Company’s results of future operations, financial position, and liquidity in fiscal year 2020.
Coronavirus Aid, Relief, and Economic Security Act
On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations, increased limitations on qualified charitable contributions, and technical corrections to tax depreciation methods for qualified improvement property.
It also appropriated funds for the SBA Paycheck Protection Program loans that are forgivable in certain situations to promote continued employment, as well as Economic Injury Disaster Loans to provide liquidity to small businesses harmed by COVID-19. There is no assurance we are eligible for these funds or any state securities lawswill be able to obtain them.
We continue to examine the impact that the CARES Act may have on our business. Currently, we are unable to determine the impact that the CARES Act will have on our financial condition, results of operations, or liquidity.
Effects of Inflation and may not be offered or sold inPricing
The oil and gas industry is very cyclical and the
United States absent registration or an applicable exemption from registration. However, in conjunctiondemand for goods and services of oil field companies, suppliers and others associated with the
closingindustry 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
the March 2017 Private Placement, we have also entered into a registration rights agreement whereby we agreed to use our reasonable best efforts to register, on behalffuture reserves, borrowing base calculations of
the investors, the shares of common stock underlying the Unitsbank loans and the
sharesvalue of
common stock underlyingproperties in purchase and sale transactions. Material changes in prices, such as those experienced to date in 2020, can impact the
warrants no later than April 1, 2017.Our 2017value of oil and natural gas companies and their ability to raise capital, budget may require additional financing aboveborrow money and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the level of cash generated by our operationsassociated increase or decrease in demand for services related to production and proceeds from recent financing activities. We can provide no assurance that additional financing would be available to us on acceptable terms, if at all.
Off-Balance Sheet Arrangements
We do not have any
material off-balance sheet arrangements.
Commitments and Contractual Obligations
On August 2, 2018, the Company executed a five-year agreement with SCM Crude, LLC, an affiliate of SCM, to secure firm takeaway pipeline capacity and pricing on a long-haul pipeline to the Gulf Coast region commencing July 1, 2019. On March 11, 2019, the agreement was replaced with a five-year agreement between the Company and ARM, a related company to SCM. The new agreement accelerated the start date to March 2019 and guarantees firm takeaway capacity on a long-haul pipeline to Corpus Christi, Texas, once completed, at a specified price. Under the terms of the new contract, the Company received pricing differentials on the crude oil sales contract subject to minimum quantities of crude oil to be delivered as follows:
|
| |
| Date | Quantity (Barrels per Day) |
| March 2019 - June 2019 | 5,000 |
| July 2019 - December 2019 | 4,000 |
| January 2020 - June 2020 | 5,000 |
| July 2020 - June 2021 | 6,000 |
July 2021 - December 2024 (1) | 7,500 |
(1) Extending to the later of December 2024 or 5 years from the EPIC Crude Oil pipeline in-service date (February 2025).
Further, ARM has agreed to purchase crude from the Company based upon Magellan East Houston pricing with a fixed “differential basis”. As of December 31, 2019, the agreement no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met. See Note 9 - Derivatives to our consolidated financial statements for information regarding the recognition of the net settlement mechanism as an embedded derivative over the remainder of the contract.
Critical Accounting Policies and Estimates
The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States (“
US 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.
The
preparation ofaccompanying consolidated financial statements
are prepared in conformity with
US GAAP
which requires
usthe Company to make a number of estimates and assumptions relating to the reported amounts of assets and
liabilities and theliabilities; disclosure of contingent assets and liabilities at the date of the financial
statements andstatements; the reported amounts of revenues and expenses during the reporting
period.period; and the quantities and values of proved oil, natural gas and natural gas liquid (“NGL”) reserves used in calculating depletion and assessing impairment of its oil and natural gas properties. The most significant estimates pertain to the evaluation of unproved properties for impairment, proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties; the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool; the fair value of embedded derivatives and commodity derivative contracts, accrued oil and natural gas revenues and expenses, valuation of options and warrants, and common stock; and the allocation of general and administrative expenses. Actual results could differ significantly from
thosethese 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 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 Common Stock, 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
applicable SEC rules, we prepared our oil and
natural gas
reservereserves estimates as of December 31,
2016,2019, using the average, first-day-of-the-month price during the 12-month period ended December 31,
2016.2019.
Estimating accumulations of
gasoil and
oilnatural 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
gasoil and
oilnatural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a
reservereserves estimate is a function of the quality and quantity of available data; the interpretation of that
data,data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate.
We believe estimated
reservereserves 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,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
natural gas liquidsNGLs 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
reservereserves estimates will be used. For example, the standardized measure calculation requires us to apply a 10% discount rate. Although
reservereserves 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
reservereserves estimates will change in the future as additional information becomes available or as oil and natural gas prices and operating and capital costs change. We evaluate and estimate our oil and natural gas reserves as of December 31, and quarterly throughout the year. For purposes of depletion, depreciation, and impairment, we adjust
reservereserves quantities at all quarterly periods for the estimated impact of acquisitions and dispositions. Changes in depletion, depreciation or impairment calculations caused by changes in
reservereserves 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
full cost poolamortization base and becomes subject to
the depletion
calculations.calculation.
Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless the sale would alter the rate of depletion by more than 25%. Royalties paid, net of any tax credits received, are netted against oil and natural gas sales.
Under the full cost method of accounting, capitalized oil and natural gas property costs, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value
using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, we would recognize impairment.
Subsequent to December 31, 2019, commodity prices declined significantly, which we expect to significantly reduce the undiscounted expected cash flows from our proved reserves. Declines in commodity prices used for our full cost ceiling test will result in additional impairments of our proved properties during 2020. If there are significant delays in the completion of our drilling program due to capital constraints resulting from current market conditions, we will lose a portion of our acreage through lease expirations that will result in impairments recorded throughout 2020 related to those expirations.
Derivative Instruments
All derivative instruments are recorded on the consolidated balance sheet at fair value as either an asset or a liability with changes in fair value recognized currently in earnings. Although commodity based derivative instruments are used by the Company to manage the price risk attributable to its expected oil and natural gas production, those derivative instruments have not been designated as accounting hedges under the accounting guidance. All of our derivatives are accounted for as mark-to-market activities. Under ASC Topic 815, “Derivatives and Hedging,” these instruments are recorded on the consolidated balance sheets at fair value as either short term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Changes in the derivatives’ fair values are recognized in current earnings since the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes.
The Company has recognized certain conversion features within its Second Lien Term Loan as embedded derivatives that have been bifurcated from the Second Lien Term Loan, as defined in Note 11 - Long-Term Debt to our consolidated financial statements in Item 16 of this Annual Report on Form 10-K and accounted for separately from the debt.
The Company has recognized our crude oil sales agreement with ARM no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met. As a result, an embedded derivative exists as it is no longer probable the contract will only result in physical deliveries of crude oil and may not settle. See Note 9 - Derivatives to our consolidated financial statements in Item 16 of this Annual Report on Form 10-K.
Revenue 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
whenin the amount that reflects the consideration it
is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidenceexpects to receive in exchange for transferring control of
an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's pricethose goods to the
buyercustomer. The contract consideration in the Company’s variable price contracts is
fixedtypically allocated to specific performance obligations in the contract according to the price stated in the contract. Payment is generally received one or
determinable and (iv) collectability is reasonably assured.two months after the sale has occurred.
Income Taxes
The Company uses the entitlementsasset and liability method ofin accounting for oil, NGLsincome taxes. Deferred tax assets and gas revenues. Sales proceeds in excessliabilities are recognized for temporary differences between financial statement carrying amounts and the tax bases of the Company's entitlement are included in otherassets and liabilities and are measured using the Company's sharetax rates expected to be in effect when the differences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assets and liabilities of sales taken by othersa change in tax rates is included in other assetsrecognized in the accompanying consolidated balance sheets. results of operations in the period that includes the enactment date. A valuation allowance is used to reduce deferred tax assets when uncertainty exists regarding their realization.
The Company had no material oil, NGL or gas entitlement assets or liabilitiesrecognizes its tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed that do not meet these recognition and measurement standards. As of December 31, 20162019 and 2018, the Company has determined that no liability is required to be recognized.
The Company’s policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. No interest or 2015.
penalties were required to be accrued at December 31, 2019 and
2018. Further, the Company does not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months.
Recently Issued Accounting Pronouncements
For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note
1 –3 - Basis of Presentation and Summary of Significant Accounting Policies” to our
consolidated financial statementsConsolidated Financial Statements in Item
816 of this Annual
Report on Form 10-K.Report.
Item 7A. | Item 7A. Quantitative and Qualitative Disclosures About Market Risk |
Not applicable.
We are exposed to various market risks, including risks relating to changes in commodity prices, interest rate risk, customer credit risk and currency exchange rate risk, as discussed below.
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Market risk refers to the risk of loss from adverse changes in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices applicable to the region in which we produce natural gas. Historically, prices received for oil and natural gas production have been volatile and unpredictable. We expect pricing volatility to continue. The prices that we receive depend on external factors beyond our control.
During the year ended December 31, 2019, our realized prices for liquids (crude oil and NGLs) continued to show significant improvement over the lows realized in January 2019, due largely to the rise in market index prices since then. Our realized oil price also continued to benefit from sales under the Company’s Crude Oil Gathering Agreement with SCM, which commenced March 1, 2019. Conversely, our realized natural gas prices saw a sharp decline beginning in April 2019 due primarily to the oversupply in the market combined with industry-wide infrastructure constraints in our operating region.
During the year ended December 31, 2019, the oil prices we received ranged from a low of $37.33 per barrel to a high of $61.66 per barrel. The NGL prices we received in the period ranged from a low of $0.24 per gallon to a high of $0.56 per gallon. Natural gas prices during the period ranged from a low of $0.36 per MCF to a high of $1.97 per MCF.
A significant decline in the prices of oil or natural gas could have a material adverse effect on our financial condition and results of operations. In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we may enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production.
The price of oil and natural gas has fallen significantly since the beginning of 2020, due in part to OPEC negotiations as well as concerns about the COVID-19 pandemic and its impact on the worldwide economy and global demand for oil and gas. The resulting precipitous decline in oil and gas pricing experienced during March 2020 and through the date of this Annual Report, if prolonged, or a further deterioration of the market price for oil and natural gas will further negatively impact our ability to continue to operate as a going concern.
We have an active hedging program to mitigate risk regarding our cash flow and to protect returns from our development activity in the event of decreases in the prices received for our production; however, hedging arrangements may expose us to risk of significant financial loss in some circumstances and may limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs.
The derivative contracts may include fixed-for-floating price swaps (whereby, on the settlement date, the Company will receive or pay an amount based on the difference between a pre-determined fixed price and a variable market price for a notional quantity of production), put options (whereby the Company pays a cash premium in order to establish a fixed floor price for a notional quantity of production and, on the settlement date, receives the excess, if any, of the fixed price floor over a variable market price), and costless collars (whereby, on the settlement date, the Company receives the excess, if any, of a variable market price over a fixed floor price up to a fixed ceiling price for a notional quantity of production). We do not enter into derivatives for trading or other speculative purposes. We believe that our use of derivatives and related hedging activities reduces our exposure to commodity price rate risk and does not expose us to material credit risk or any other material market risk.
Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. We currently sell all of our oil and natural gas production under price sensitive or market price contracts.
Interest Rate Risk
As of December 31, 2019, we had $115.0 million outstanding under our Revolving Credit Agreement with an applicable margin that varies from 2.75% to 3.25%. In addition, holders of our shares of Preferred Stock are entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears at an average annual rate of 9.07% of the Stated Value until maturity.
Currently, we do not have any interest rate derivative contracts in place. If we incur significant debt with a risk of fluctuating interest rates in the future, we may enter into interest rate derivative contracts on a portion of our then outstanding debt to mitigate the risk of fluctuating interest rates.
Customer Credit Risk
Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production of approximately $9.1 million at December 31, 2019, and through actual and accrued receivables from our joint interest partners of approximately $9.5 million at December 31, 2019. We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the year ended December 31, 2019, sales to three customers, ARM Energy Management, LLC, Texican Crude & Hydrocarbon, LLC, and Lucid Energy Delaware, LLC, accounted for approximately, 68%, 19% and 12% of our revenue, respectively.
Currency Exchange Rate Risk
We do not have any foreign sales and we accept payment for our commodity sales only in U.S. dollars. We are, therefore, not exposed to foreign currency exchange rate risk on these sales.
Item 8. | Financial Statements and Supplementary Data |
Item 8. Financial Statements and Supplementary Data
Our financial statements appear immediately after the signature page of this Annual Report
on Form 10-K, whichand are incorporated herein by reference. See “Index to Financial Statements” included in this Annual
Report on Form 10-K.Report.
Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
Not applicable
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. | Controls and Procedures |
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), at the end of the period we carried out an evaluation, under the supervision and
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
effectivenesstime periods specified in the rules and forms of the
design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act).SEC. Based upon thattheir evaluation, our Chief Executive Officer and Chief Financial Officer concluded that ourthe Company’s disclosure controls and procedures were effective as of December 31, 2016 at the reasonable assurance level.Changes in Internal Control over Financial Reporting
Management implemented internal audit activities to improve the Company’s governance and risk management based on assessment of systems and business processes. Management has conducted an assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2016. The assessment was based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 COSO Framework).
Management’s assessment sufficiently addresses the risks of misstatements in financial reporting including risk of fraud identified within key business processes. As a result, management has concluded that, as of December 31, 2016, the Company's internal control over financial reporting was effective and that the previously identified material weakness in the Company’s Form 10-K filed for the year ended December 31, 2015 has been fully remediated.
Remediation of Material Weakness in Internal Control
Continuing into the fourth quarter of 2016, a number of remedial actions were taken to address the previously existing material weaknesses. Management’s efforts included performing a top-down risk assessment to identify risk of financial misstatement and fraud risks related to key processes and activities, including identification of relevant assertions for each significant account and disclosure. Additional measures included:
| 1) | Management identified the risk of fraud for significant accounts and disclosures. |
| 2) | Management identified key risks within each business process and implemented controls to address each risk. |
| 3) | Management conducted walkthroughs for key processes. |
| 4) | Management assessed operating effectiveness by performing test procedures on samples of transactions. |
In addition, starting in 2016, management augmented and high-graded key staff with more experience and expertise, supplemented with outside consultants, to put into place an effective mechanism for monitoring our system of internal control.
2019.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting.reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act). Our internal control over financial reportingstructure is a process designed by or under the supervision of our Chief Executive Officer and Chief Financial Officer and effected by our Board of Directors, management and other personnel 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 statements for external purposesstatement 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, 2016,2019, based on the criteria for effective internal control over financial reporting established in “Internal Control - Integrated Framework (2013)” which is issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment and those criteria, our management determined that we maintained effectiveour internal control over financial reporting was effective as of December 31, 2016.2019.
Changes in Internal Control Over Financial Reporting
There was no change in our internal control over financial reporting during the year ended December 31, 2019, that materially affected or is reasonably likely to materially affect our internal control over financial reporting.
Item 9B. Other Information
None.
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The following table sets forth the names, ages and positions of the persons who are our directors and executive officers as of
March 1, 2016:April 30, 2020: |
| | | | | |
| Name | | Age | | Position |
Abraham “Avi” MirmanMichael G. Long | | 4767 |
| | Chief Executive Officer, Director |
Ronald D. Ormand | | 58 | | Executive Chairman of the Board of Directors |
| Nuno Brandolini | | 6366 |
| | Director |
R. Glenn DawsonJohn Johanning | | 6034 |
| | Director |
General Merrill McPeakMarkus Specks | | 8135 |
| | Director |
Peter BenzNicholas Steinsberger | | 56 |
| | Director |
| Joseph C. Daches | | 5053 | | Executive Vice President, Chief Financial Officer and Treasurer |
Brennan Short | | 42
| | Chief OperatingExecutive Officer, President and Chief Financial Officer |
Ariella Fuchs | | 35 | | Executive Vice President, General Counsel and Secretary |
Seth Blackwell | | 29 | | Executive Vice President |
Directors hold office for a period of one year from their election at the annual meeting of stockholders and until a particular director’s successor is duly elected and qualified. Officers are elected by, and serve at the discretion of,
Land and Business Development Abraham Mirman: Chief Executive Officer, Director. Mr. Mirman joined our Board of Directors (the “Board” or the “Board of Directors”). None of the above individuals has any family relationship with any other individual listed above.
Below are summaries of the background and business experience, attributes, qualifications and skills of the current directors and executive officers of the Company:
Michael G. Long: Chairman of the Board of Directors. Mr. Long joined our Board on September 12, 2014. He currently serves as our Chief Executive OfficerApril 10, 2018 and has held that position since April 21, 2014. Prior to being appointed to his current position of Chief Executive Officer, Mr. Mirman served as our President beginning in September 2013. During that same time, from April 2013 until September 2014, Mr. Mirman served as the Managing Director, Investment Banking at T.R. Winston & Company, LLC (“TRW”). Between 2012 and February 2013, Mr. Mirman served as Head of Investment Banking at John Thomas Financial. From 2011 to 2012, Mr. Mirman served as Head of Investment Banking at BMA Securities. Lastly, from 2006 to 2011, Mr. Mirman served as Chairman of the Board of Cresta Capital Strategies LLC. Duringsince March 2020. Mr. Mirman’s service as Chief Executive Officer, we have completed several significant capital raising transactions and negotiated a final settlementLong is an experienced financial executive with its senior secured lender.Director Qualifications:
| · | Leadership Experience - Chief Executive Officer of Lilis Energy, Inc.; Chairman of the Board of Cresta Capital Strategies LLC; Head of Investment Banking at BMA Securities; Head of Investment Banking at John Thomas Financial; Managing Director, Investment Banking at TRW. |
| · | Industry Experience - Personal investment in oil and gas industry, and experience as executive officer of our company. |
Ronald D. Ormand: Executive Chairman of the Board of Directors. Mr. Ormand joined Lilis’s Board of Directors in February, 2015, bringing with him more than 33over 35 years of experience as a senior executive and investment banker in energy, including extensive financing and mergers and acquisitions expertise in the oil and gas industry. During his career, he has completed more than $25 billion ofrelated management, corporate finance, capital markets, risk management and financial advisory transactions,strategic planning activities for both as a principalprivate and as a banker. Prior to joining Lilis,public oil and gas companies. Mr. OrmandLong previously served as the Chairman and Head of the Investment Banking Group at MLV & Co. (“MLV”), which is now owned by FBR & Co., after it acquired MLV in September of 2015. After the acquisition, Mr. Ormand served as Senior Managing Director and Senior Advisor at FBR & Co. until May 2016, where he focused on investment banking and principal investments in the energy sector. Prior to joining MLV in November 2013, from 2009 to 2013, Mr. Ormand was a senior executive at Magnum Hunter Resources Corporation, or MHR (NYSE:MHR), an exploration and production company engaged in unconventional resource plays, as well as midstream and oilfield services operations. He was part of the management team that took over prior management and grew MHR from approximately $35 million enterprise value to over $2.5 billion enterprise value at the time he left in 2013. Mr. Ormand served on the Board of Directors and in several senior management positions for MHR, including Executive Vice President and Chief Financial Officer for Sanchez Energy Corporation and privately held Sanchez Oil and Gas Corporation and its affiliates. Mr. Long also held the positions of EVP and CFO of Edge Petroleum Corporation and Vice President of Finance for W&T Offshore.
Director Qualifications:
Leadership Experience - Served as Executive Vice President of Capital Markets. On March 10, 2016, in connection with his prior position asand Chief Financial Officer of MHR, Mr. Ormand, without admitting or denying any of the allegations, settled with the SEC in connection with an investigation of MHR’s books and records and internal controls for financial reporting. Specifically, Mr. Ormand agreed to cease and desist from violating Sections 13(a) and 13(b)(2)(A) and (B) of the Exchange Act and Rules 13a-1, 13a-13 and 13-15(a) thereunder. He has also paid a penalty of $25,000. The SEC did not allege any anti-fraud violations, intentional misrepresentations or willful conduct on the part of Mr. Ormand. Mr. Ormand’s career includes serving as Managing Director and Group Head of U.S. Oil and Gas Investment Banking at CIBC World Markets and Oppenheimer (1988-2004); Head Of North American Oil and Gas Investment Banking at West LB A.G. (2005-2007), andSanchez Energy Corporation, Executive Vice President and CFOChief Financial Officer of Tremisis Energy Acquisition Corp. II, an energy special purpose acquisition company from 2007-2009. Mr. Ormand has previously served as a DirectorEdge Petroleum Corporation, and Vice President of Greenhunter Resources, Inc. (2011-2013), Tremisis (2007-2009),Finance for W&T Offshore.
Industry Experience - Extensive experience in corporate finance, capital markets, risk management and
Eureka Hunter Holdings, Inc., a private midstream company (2010-2013). Mr. Ormand holds a B.A. in Economics, an M.B.A. in Finance and Accounting from UCLA and studied Economics at Cambridge University, England.strategic planning activities. Director Qualifications:
| · | Leadership Experience - Senior executive at Magnum Hunter Resources Corporation, Chairman and Head of Investment Banking at MLV and Head of US Oil and Gas for CIBC and investment banker. |
| · | Industry Experience - Extensive experience in oil and gas development and services industries at the entities and in the capacities described above |
Nuno Brandolini: Director. Mr. Brandolini joined our Board of Directors in February 2014 and becameserved as Chairman inof the Board from April 2014. On2014 until January 13, 2016 when Mr. BrandoliniOrmand was replacedappointed as Chairman of our Board of Directors by Ronald D. Ormand.Board. Mr. Brandolini served as a member of the general partner of Scorpion Capital Partners, L.P., a private equity firm organized as a small business investment company, until June 2014. Prior to forming Scorpion Capital and its predecessor firm, Scorpion Holding, Inc., in 1995, Mr. Brandolini served as managing director of Rosecliff, Inc., a leveraged buyout fund co-founded by Mr. Brandolini in 1993. Mr. Brandolini served previously as a vice president in the investment banking department of Salomon Brothers, Inc., and a principal with the Batheus Group and Logic Capital, two venture capital firms. Mr. Brandolini began his career as an investment banker with Lazard Freres & Co. Mr. Brandolini is a director of Cheniere Energy, Inc. (NYSE MKT:American: LNG), a Houston-based company primarily engaged in LNG related businesses. Mr. Brandolini received a law degree from the University of Paris and an M.B.A. from the Wharton School.
Director
Qualifications: | · | Leadership Experience - Executive positions with several private equity firms, and Board position with Cheniere Energy, Inc. |
| · | Industry Experience - Service on the Board of Cheniere Energy, Inc., as well as personal investments in the oil and gas industry. |
R. Glenn Dawson:Qualifications:
Leadership Experience - Executive positions with several private equity firms, and Board position with Cheniere Energy, Inc.
Industry Experience - Serves on the Board of Cheniere Energy, Inc., as well as has personal investments in the oil and gas industry.
John Johanning: Director. Mr. DawsonJohanning joined our Board in March 2018. Mr. Johanning was designated as a director by the Värde Parties pursuant to a Securities Purchase Agreement dated January 30, 2018, and he was appointed to our Board in March 2018. Mr. Johanning is the Technical Director of DirectorsVärde Partners, Inc.’s (“Värde”) energy business. Mr. Johanning joined Värde in May 2017 and presides over the Petroleum Engineering and Geoscience aspects of Värde’s investments in energy. Mr. Johanning is involved in the performance of current Värde investments across active onshore US basins as well as new business decisions in both opportunity screening and asset and company valuations. Prior to joining Värde, from January 2014 until May 2017, Mr. Johanning was a Vice President at Evercore Partners (“Evercore”) in Houston, Texas, where he was influential in numerous transactions totaling over $10 billion in transaction value. While at Evercore, Mr. Johanning advised numerous energy companies and financial sponsors on January 13, 2016.value-maximizing transactions. Mr. Dawson hasJohanning’s advisory mandates ranged over 30 yearsa variety of different transaction types including acquisitions and divestitures of assets, corporate mergers, and capital raises. Mr. Johanning also worked across all oilfield sectors, gaining transactional experience in the upstream, midstream, downstream and oilfield service sectors of the business. Mr. Johanning began his career as a Reservoir Engineer at BP from 2008 to 2014. Based in Houston, he developed oil and gas explorationassets across several US Basins, including the Permian of West Texas and Southeast New Mexico and the Texas Gulf Coast Basin, among others. While on the South Texas Reservoir Management team, Mr. Johanning was responsible for the resource appraisal of a 400,000+ gross acre Eagle Ford Shale position that was deeply rooted in North Americageological and is currently President and Chief Executive Officerwell completion data. While at BP, Mr. Johanning gained a detailed technical understanding of Cuda Energy, Inc., a private Canadian-based exploration and production company. Mr. Dawson’s career includes serving as President of Bakken Hunter, a division of MHR, where he managed operations and development of Bakken assets in the United States and Canada, from 2011 to 2014. His principal responsibilities have involved the generation and evaluation of drilling prospects and production acquisition opportunities. In the early stages of his career, Mr. Dawson was employed as an exploration geologist by Sundance Oil and Gas, Inc., a public company located in Denver, Colorado, concentrating on their Canadian operations. From December 1985 to September 1998, Mr. Dawson held a variety of managerial and technical positions with Summit Resources, a then-public Canadian oil and gas explorationassets through the various facets of the business, including Production Engineering, Reservoir Engineering, Drilling and production company, including Vice PresidentCompletions, Geology and Geophysics, as well as Land, Legal and Finance functions. Mr. Johanning graduated from The University of Exploration, Exploration Manager and Chief Geologist. He servedTexas in at Austin in 2008 with a B.S. in Petroleum Engineering.
Director Qualifications:
Leadership Experience - Served as Vice President at Evercore Partners and currently presides over the Petroleum Engineering and Geoscience aspects of Exploration with PanAtlas EnergyVärde Partners, Inc., a then-public Canadian oil and gas exploration and production company, from 1999 until its acquisition by Velvet Exploration Ltd. in July 2000. Mr. Dawson was a co-founder and Vice President of Exploration of TriLoch Resources Inc., a then-public Canadian oil and gas exploration company, from 2001 to 2005, until it was acquired by Enerplus Resources Fund. As a result of as the sale of TriLoch Resources Inc. to Enerplus Resources Fund, Mr. Dawson founded NuLoch Resources, Inc. in 2005. Mr. Dawson graduated in 1980 from Weber State University of Utah with a Bachelor’s degree in Geology and attended the University of Calgary from 1980 to 1982 in the Masters Program for Geology. As a result of these professional experiences, Mr. Dawson possessesTechnical Director.
Industry Experience - Possesses particular knowledge and experience in the operations of oil and gas companies
that strengthenand has transactional experience in the
Board’s collective qualifications, skills,upstream, midstream, downstream and
experience.oil field service sectors of the business, including acquisitions and divestitures of assets, corporate mergers, and capital raises.
Markus Specks: Director Qualifications:
| · | Leadership Experience - President and Chief Executive Officer of Cuda Energy, Inc.; former President of Bakken Hunter. |
| · | Industry Experience - Extensive experience in oil and gas exploration industry; co-founded numerous oil and gas exploration companies. |
General Merrill McPeak: Director
. General McPeakMr. Specks joined our Board of Directors in January 2015. He served as the fourteenth chief of staff of the U.S. Air Force and flew 269 combat missions in Vietnam during his distinguished 37-year military career. Following retirement from active service in 1994, General McPeak launched a second career in business. HeMarch 2018. Mr. Specks was a founding investor and chairman of Ethics Point, an ethics and compliance software and services company, which was subsequently restyled as industry leader Navex Global, and acquired in 2011 by a private equity firm. General McPeak co-invested and remained a board member of Nava Global, which was sold again in 2014. From 2012 to 2014, General McPeak was Chairman of Coast Plating, Inc., a Los Angeles-based, privately held provider of metal processing and finishing services, primarily to the aerospace industry, which was also acquired in a private equity buyout. He remains a director of that company, now called Valence Surface Technologies. He also currently servesdesignated as a director of Aerojet Rocketdyne, Lion Biotechnologiesby the Värde Parties pursuant to a Securities Purchase Agreement dated January 30, 2018, and Research Solutions, Inc. Formerly, he was appointed to our Board in March 2018. Mr. Specks is a directorManaging Director of Tektronix, TWAVärde Partners, Inc. and ECC International, a defense subcontractor, where he served for many years as chairmanHead of the Board. Since 2010, General McPeakfirm’s Houston office. Mr. Specks leads Värde’s energy business and has been Chairmanexperience managing credit, equity, and structured asset-level investments across the energy sector. He serves on Värde’s Investment Committee as well as several boards of the American Battle Monuments Commission, an agency of the executive branch of the federal government, responsible for operating and maintaining American cemeteries in foreign countries holding the remains of 125,000 US servicemen. General McPeak has a B.A. degree in Economics from San Diego State College and an M.S. in International Relations from George Washington University. He is a graduate of the National War College and of the Executive Development Program of the University of Michigan Graduate School of Business. He spent an academic year as Military Fellow at the Council on Foreign Relations
Director Qualifications:
| · | Leadership Experience - Chief of Staff of the U.S. Air Force; Founding investor and chairman of Ethicspoint (subsequently Navex Global). |
| · | Industry Experience - Personal investments in the oil and gas industry. |
Peter Benz: Director. Mr. Benz joined our Board of Directors on June 23, 2016 in connection with the completion of the merger with Brushy.private energy companies. Prior to that,joining Värde in 2008, Mr. Benz had served on Brushy’s Board of Directors since January 20, 2012. Mr. Benz serves as the Chairman and Chief Executive Officer of Viking Asset Management, LLC and is a member of its Investment Committee. He has been affiliated with Viking Asset Management, LLC since 2001. His responsibilities include assuring a steady flow of candidate deals, making asset allocation and risk management decisions and overseeing all business and investment operations. He has more than 25 years of experience specializingSpecks worked in investment banking at Lazard, focusing on middle-market M&A advisory. Mr. Specks holds a B.A. in Government from Lawrence University in Wisconsin.
Director Qualifications:
Leadership Experience - Managing Director of Värde Partners, Inc. and corporate advisory services for small growth companies inHead of the areas of financing, merger/acquisition, funding strategy and general corporate development. Prior to founding Viking in 2001, Mr. Benz founded Bi Coastal Consulting Company where he advised hundreds of companies regarding private placements, initial public offerings, secondary public offerings and acquisitions. He has founded three public companies and served as a director for four other public companies. Prior to founding Bi Coastal Consulting, Mr. Benz was responsible for private placements and investment banking activities at Gilford Securities in New York, NY. Mr. Benz became a director of usell.com, Inc. on May 15, 2014. Mr. Benz is a graduate of Notre Dame University. As a result of these professional experiences, Mr. Benz possessesfirm’s Houston office.
Industry Experience - Possesses particular knowledge and experience in developing companies and capital markets, that strengthenparticularly with oil and gas companies.
Nicholas Steinsberger: Director. Mr. Steinsberger joined our Board on May 3, 2018. He is currently COO and Managing Director of ValPoint Operating, a small private equity backed company working in western Oklahoma. Mr. Steinsberger is a highly experienced petroleum engineer and global expert in shale drilling and completions who pioneered the boarduse of director’s collective qualifications, skills,slick water fracing. He began his career with Mitchell Energy and experience.served as the Completion Manager for Mitchell from 1995 to 2002, where he piloted the Company’s fracking technique and developed the slick water frac, pioneering the current oil and gas shale boom. Mr. Steinsberger then served as the Completion Manager for Devon Energy after Devon’s acquisition of Mitchell Energy. In 2005, he founded Steinsberger Tight Gas Consulting, where he has drilled and completed wells in the Barnett, Fayetteville, Woodford, Wolfcamp, Utica, Bakken and Marcellus Shales. Mr. Steinsberger is regarded as an expert in the field of unconventional well completion and is responsible for the drilling and completion of over 1,000 wells in his career. He holds a B.S. in Petroleum Engineering from the University of Texas.
Director Qualifications:
| · | Leadership Experience –Chairman and CEO of Viking Asset Management; founded three public companies. |
| · | Industry Experience –Extensive experience in the investment banking and corporate advisory services industries; founded Bi Coastal Consulting, a consulting company advising companies regarding private placements, initial public offerings, secondary public offerings and acquisitions. |
Leadership Experience - COO and Managing Director of ValPoint Operating; Founder, President and CEO of Steinsberger Tight Gas Consulting.
Industry Experience - Possesses significant knowledge regarding technical aspects of drilling and completions and is also very active in the oil and gas industry.
Joseph C. Daches: Chief Executive Vice President,Officer. Mr. Daches was appointed Chief Executive Officer of the Company on November 13, 2019. He was Chief Financial Officer and Treasurer. On of Lilis since January 23, 2017, our Board appointed Josephand President of Lilis since August 16, 2018. Mr. Daches has more than 25 years’ experience in management and working with boards of directors, banks and attorneys, primarily within the energy industry. Mr. Daches has helped guide several oil and gas companies through financial strategy activities, capital raises, and both public and private offerings. Mr. Daches possesses significant business experience and knowledge related to the position of Executive Vice President, Chief Financial Officeroil and Treasurer, effective immediately.gas industry, including A&D transactions, oil and gas reporting, SEC reporting, corporate governance and compliance, budgeting and business valuations. Prior to joining our company,the Company, Mr. Daches most recently held the position of Chief Financial Officer and Senior Vice President of Magnum Hunter Resources Corp. (“MHR”) from July 2013 to June 2016,CFO at MHR, where he finishedconcluded his tenure by successfully guiding MHR through a restructuring and upon emergence was appointed Co-CEO by MHR’sthe new board of directors until his departure. Mr. Daches has over 20 years of experience and expertise in directing strategy, accounting and finance in primarily small and mid-size oil and gas companies and has helped guide several of those companies through financial strategy, capital raises and private and public offerings.directors. Prior to joining MHR, Mr. Daches served as Executive Vice President and Chief Accounting Officer and Treasurer of Energy & Exploration Partners, Inc. fromsince September 2012 until June 2013 and as a director of that company fromsince April 2013 through June 2013. He previously served as a partner and Managing Director of the Willis Consulting Group, LLC, from January 2012 to September 2012. From October 2003 to December 2011, Mr. Daches served as the Director of E&P Advisory Services at Sirius Solutions, LLC, where he was primarily responsible for financial reporting, technical and oil and gas accounting, and the overall management of the E&P Advisory Servicesadvisory services practice. Mr. Daches earned a Bachelor of Science in Accounting from Wilkes University in Pennsylvania, and he is a certified public accountant in good standing with the Texas State Board of Public Accountancy.Brennan Short: Chief Operating Officer. On January 27, 2017,
Corporate Governance
The Board of Directors and Committees
Our Board conducts its business through meetings and through its committees. Our Board held eight meetings in 2019 and took action by unanimous written consent on six occasions. Each director attended at least 75% of (i) the meetings of the Board held after such director’s appointment and (ii) the meetings of the committees on which such director served, after being appointed to such committee. Our policy regarding directors’ attendance at the annual meetings of stockholders is that all directors are expected to attend, absent extenuating circumstances. In 2019, we had two directors attend our Annual Meeting.
Board appointed Brennan ShortLeadership Structure
The Board selected Mr. Long to hold the position of Chief Operating Officer, effective immediately.Chairman of the Board on March 12, 2020. Mr. Short most recently heldLong’s experience in the positionindustry and various executive leadership roles has afforded him intimate knowledge of President at MMZ Consulting Inc. from May 2012the issues, challenges and opportunities facing the Company.
The Board’s Role in Risk Oversight
It is management’s responsibility to January 2017, where he provided full cycle drilling & completions engineeringassess and operational supportmanage risk and bring to multiple clients. Mr. Shortthe Board’s attention any material risks to our Company. While our management team is responsible for assessing and managing material risks, our Board and Board committees generally oversee risk management. The Board also has over 20 yearsoversight responsibility for our risk policies and processes relating to the financial statements and financial reporting processes and the guidelines, policies and processes for mitigating those risks.
Corporate Governance Guidelines
Our Board has developed and adopted Corporate Governance Guidelines to establish a common set of proven expertiseexpectations to assist our Board and its committees in domestic oil & gas explorationperforming their duties. The Corporate Governance Guidelines provide guidance to our directors on various subjects, including our directors’ responsibilities, director qualification standards, director compensation, and production operations, field supervision,access to management and petroleum engineering consulting. Prior to forming MMZ Consulting Inc., Mr. Short held the positionindependent advisors. A copy of Drilling Engineering Specialistour Corporate Governance Guidelines is available on our website at EOG Resources, Inc. from March 2010 to May 2012, where he was a drilling engineer in the infancywww.lilisenergy.com under “Investor Relations - Corporate Governance.”
Committees of the Eagleford Shale Play in South Texas. PreviousBoard of Directors
Pursuant to his role EOG Resources, Inc., Mr. Short was a Drilling Engineer at SM Energyour bylaws, our Board is permitted to establish committees from November 2007time to March 2010time as it deems appropriate. To facilitate independent director review and to make the most effective use of our directors’ time and capabilities, our Board has
established an Audit Committee and a Drilling Engineer at Samson Investment Company from March 2005 to November 2007.Special Committee. The membership and principal functions of these committees are described below.
In connection with the resignation of certain directors, effective as of April 15, 2020, our Board does not have a standing Nominating and Corporate Governance Committee or a standing Compensation Committee.
Audit Committee
Currently, our Audit Committee consists of Mr.
Short earned his Bachelor’s degree in Petroleum Engineering from Texas A&M University.Ariella Fuchs: Executive Vice President, General Counsel and Secretary. Ariella Fuchs joined our company in March 2015. Prior to that, Ms. Fuchs was an associate with Baker Botts L.L.P. from April 2013 to February 2015, specializing in securities transactions and corporate governance. Prior to joining Baker Botts L.L.P, she served as an associate at White & Case LLP and Dewey and LeBoeuf LLP from January 2010 to March 2013 in their mergers and acquisitions groups. Ms. Fuchs received a J.D. from New York Law School and a B.A. in Political Science from Tufts University.
Seth Blackwell: Executive Vice President of Land and Business Development. Seth Blackwell joined our company in December 2016. Mr. BlackwellLong, who is a Professional Landman with extensive knowledge and experience in all facets of land management. Prior to joining our company, Mr. Blackwell held the position of Vice President of Land for XOG Resources where he managed all land and business development efforts for the company. Mr. Blackwell also gained extensive experience in a wide variety of major US oil and gas plays while working for Occidental Petroleum. Mr. Blackwell started his career blocking together large acreage positions in excess of 30,000 acres throughout Central and East Texas. Mr. Blackwell is an active memberchairman of the American Association of Professional Landman, North Houston Association of Professional LandmanAudit Committee, and the Houston Association of Professional Landman. Mr. Blackwell holds a bachelor’s degree in Business Management from Fort Hays State University and is currently pursuing his MBA in Energy from the University of Tulsa.
Directors hold office for a period of one year from their election at the annual meeting of stockholders and until a particular director’s successor is duly elected and qualified. Officers are elected by, and serve at the discretion of, ourBrandolini. Our Board of Directors. NoneDirectors determined that each of the above individuals has any family relationship with any other. It is expected thatMr. Long and Mr. Brandolini are independent as required by NYSE American for audit committee members. In addition, our Board of Directors determined that Mr. Long meets the requisite SEC criteria to qualify as an audit committee financial expert. The Audit Committee met five times during the year ended December 31, 2019, and acted by written consent once.
The Audit Committee selects, compensates and evaluates an independent public accounting firm to act as the Company’s independent auditors, as well as any other necessary registered public accounting firms. In addition, the Audit Committee reviews all critical accounting policies and practices to be used in the Company’s audit and reviews all alternative treatments of financial information within generally accepted accounting principles. The Audit Committee also reviews with management and our independent auditors any major issues regarding accounting principles and financial statement presentation and any significant financial reporting issues and judgments. Under its charter, the Audit Committee monitors compliance with our Code of Business Conduct.
The Audit Committee is governed by a written charter that is reviewed, and amended if necessary, on an annual basis. A copy of the charter is available on our website at www.lilisenergy.com under “Investor Relations - Corporate Governance.”
Consideration and Determination of Executive and Director Compensation
Our Board does not currently have a standing Compensation Committee. Due to the reduced size of the Board following the resignations of three directors, effective as of April 15, 2020, the Board determined that it would be appropriate for the Compensation Committee to be dissolved and for the responsibilities of the Board’s former Compensation Committee to be assigned to its directors that meet the independence standards of the NYSE American LLC. As such, Mr. Long, Mr. Brandolini, Mr. Johanning and Mr. Specks, as the four independent members of the Board, participate in the consideration of officer and director compensation.
The independent members of the Board review, approve and modify our executive compensation program, plans and awards provided to our directors, executive officers and key employees. The independent members of the Board also review and approve short-term and long-term incentive plans and other stock or stock-based incentive plans. In addition, the independent members of the Board review our compensation and benefit philosophy, plans and programs on an as-needed basis. In reviewing our compensation and benefits policies, the independent members of the Board may consider the recruitment, development, promotion, retention and compensation of our executive and senior officers; trends in management compensation; and any other factors that it deems appropriate.
The independent members of the Board, at least annually, review and approve the corporate goals and objectives applicable to the compensation of the Company’s CEO, evaluates the CEO’s performance in light of those goals and objectives, and determine and approve the CEO’s compensation level based on the evaluation. The CEO is not permitted to be present during any Board deliberations or voting with respect to his compensation. The independent members of the Board also, at least annually, review and approve the annual base salaries and incentive opportunities of the executive officers (other than the CEO) and review and approve all other incentive awards and opportunities, including both cash-based and equity based awards and opportunities.
Consideration of Director Nominees
Our Board does not currently have a standing Nominating and Corporate Governance Committee. Due to the reduced size of the Board following the resignations of three directors, effective as of April 15, 2020, the Board determined that it would be appropriate for the Nominating and Corporate Governance Committee to be dissolved and for the responsibilities of the Board’s former Nominating and Corporate Governance Committee to be assigned to its directors that meet the independence standards of the NYSE American LLC. As such, Mr. Long, Mr. Brandolini, Mr. Johanning and Mr. Specks, as the four independent members of the Board, participate in the consideration of director nominations.
The primary responsibilities of the independent members of the Board with respect to director nominations include identifying, evaluating and recommending, for the approval of the entire Board, potential candidates to become members of the Board, recommending membership on standing committees of the Board, developing and recommending to the entire Board corporate governance principles and practices for our company and assisting in the implementation of such policies.
Special Committee
In November 2019, our board of directors formed a committee of independent directors (the “Special Committee”) tasked with reviewing and evaluating strategic alternatives that may enhance the value of the Company, including alternatives that may be available to identify and access further sources of liquidity.
Communications with the Board of Directors
Stockholders may communicate with our Board or any of the Company’s directors by sending written communications addressed to the Board or any of the directors, at Lilis Energy, Inc., 201 Main Street, Suite 700, Fort Worth, TX 76102, Attention: General Counsel. All communications are compiled by the General Counsel and forwarded to the Board or the individual director(s) accordingly.
Code of Ethics and Corporate Governance Guidelines
Our Board has adopted a Code of Business Conduct that applies to all of our officers and employees, including our chief executive officer, chief financial officer or controller, and persons performing similar functions. Our Code of Business Conduct codifies the business and ethical principles that govern all aspects of our business.
Our Board has developed and adopted Corporate Governance Guidelines to establish a common set of expectations to assist the Board, and its committees in performing their duties. The Corporate Governance Guidelines provide guidance to our directors on various subjects, including our director’s responsibilities, director qualification standards, director compensation, and access to management and independent advisors.
A copy of our Code of Business Conduct and Corporate Governance Guidelines are available on our website at www.lilisenergy.com under “Investor Relations - Corporate Governance.” We will elect officers annually following each annual meetingundertake to provide a copy of stockholders.our Code of Business Conduct and Corporate Governance Guidelines to any person, at no charge, upon a written request. All written requests should be directed to: Lilis Energy, Inc., 201 Main Street, Suite 700, Fort Worth, TX 76102, Attention: General Counsel. If any substantive amendments are made to our Code of Business Conduct, or if any waiver (including any implicit waiver) is granted from any provision of the Code of Business Conduct to our chief executive officer, chief financial officer or controller, we will disclose the nature of such amendment or waiver on our website at www.lilisenergy.com under “Investor Relations - Corporate Governance” or, if required, in a Current Report on Form 8-K. Delinquent Section 16(a)
Beneficial Ownership Reporting ComplianceReports
Our executive officers and directors and persons who own more than 10% of our common stock are required to file reports with the SEC, disclosing the amount and nature of their beneficial ownership in our common stock, as well as changes in that ownership. Based solely on our review of reports and written representations that we have received, we believe that all required reports were timely filed during
2016 and through2019, except for the
date of this report, except as follows: | · | Kevin Nanke filed one Form 4, reporting one transaction late. |
| · | R. Glenn Dawson filed one Form 4 reporting one transaction late. After the reporting period, Mr. Dawson filed one Form 4 reporting one transaction late. |
| · | Sean O-Sullivan Revocable Living Trust (the “SOS Trust”) filed one Form 3 late, as well as an amendment to such Form 3 reporting his initial beneficial ownership late. The SOS Trust filed three Form 4s reporting eight transactions late, as well as an amendment to one of the late Form 4s, reporting an additional two transactions late. |
| · | SOSVentures LLC filed one Form 3 late. |
| · | Ronald D. Ormand filed one Form 4 amendment reporting two transactions late. |
| · | Peter Benz filed one Form 4 amendment reporting one transaction late. |
| · | Joseph C. Daches filed one Form 3 reporting his initial beneficial ownership late. |
The Board of Directors and Committees Thereof
Our Board of Directors conducts its business through meetings and through its committees. Our Board of Directors held ten meetings in 2016 and took actionfollowing:
Mark Christensen filed one Form 4, reporting one transaction, subsequent to the time prescribed by unanimous written consent on nine occasions. Each director attended at least 75% of (i) the meetingsSection 16(a) of the Board held after such director’s appointment and (ii)Exchange Act.
Joseph C. Daches filed one Form 4, reporting three transactions, subsequent to the
meetingstime prescribed by Section 16(a) of the
committees on which such director served, after being appointed to such committee. Our policy regarding directors’ attendance at the annual meetings of stockholders is that all directors are expected to attend, absent extenuating circumstances.Affirmative Determinations Regarding Director Independence and Other Matters
Our Board of Directors follows the standards of independence established under the rules of the Nasdaq Stock Market, or the Nasdaq, as well as our Corporate Governance Guidelines on Director Independence, which was amended on December 10, 2015, a copy of which is available on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights” in determining if directors are independent. The Board has determined that four of our current directors, Mr. Brandolini, General McPeak, Mr. Benz and Mr. Dawson are “independent directors” under the Nasdaq rules referenced above.
No independent director receives, or has received, any fees or compensation directly as an individual from us other than compensation received in his or her capacity as a director or indirectly through their respective companies, except as described below. See “Certain Relationships and Related Transactions, and Director Independence”. There were no transactions, relationships or arrangements not otherwise disclosed that were considered by the Board of Directors in determining whether any of the directors were independent.
Committees of the Board of Directors
Pursuant to our amended and restated bylaws, our Board of Directors is permitted to establish committees from time to time as it deems appropriate. To facilitate independent director review and to make the most effective use of our directors’ time and capabilities, our Board of Directors has established an audit committee, a compensation committee and a nominating and corporate governance committee. The membership and function of these committees are described below.
Audit Committee
During the year ended December 31, 2016, each of Mr. Brandolini, General McPeak, Mr. Dawson and Mr. Benz served on the audit committee. Currently, the audit committee consists of Mr. Benz, Mr. Brandolini and General McPeak. Mr. Benz is the acting as chairman of the audit committee and meets the definition of an audit committee financial expert. Our Board of Directors determined that each of Mr. Brandolini, General McPeak, Mr. Dawson and Mr. Benz were independent as required by Nasdaq for audit committee members.
The audit committee met four times during the year ended December 31, 2016, but met separately on several occasions in connection with a meeting of the full Board of Directors. The audit committee is governed by a written charter that is reviewed, and amended if necessary, on an annual basis. A copy of the charter is available on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.”
Compensation Committee
Our compensation committee currently consists of Mr. Brandolini, General McPeak and Mr. Dawson. Mr. Ormand had also served on the compensation committee, but resigned following a determination that he should not be considered independent and eligible for compensation committee service based on the above-described compensation paid to his investment bank. General McPeak is the chairman of the compensation committee.
The compensation committee met six times during the year ended December 31, 2016, and acted by written consent twice. The compensation committee has also met separately on several occasions in connection with a meeting of the full Board. The Board determined that each of Mr. Brandolini, General McPeak and Mr. Dawson were independent as required by Nasdaq for compensation committee members.
The compensation committee reviews, approves and modifies our executive compensation programs, plans and awards provided to our directors, executive officers and key associates. The compensation committee also reviews and approves short-term and long-term incentive plans and other stock or stock-based incentive plans. In addition, the committee reviews our compensation and benefit philosophy, plans and programs on an as-needed basis. In reviewing our compensation and benefits policies, the compensation committee may consider the recruitment, development, promotion, retention, compensation of our executive and senior officers, trends in management compensation and any other factors that it deems appropriate. Under its charter, the compensation committee may create and delegate such tasks to such standing or ad hoc subcommittees as it may determine to be necessary or appropriate for the discharge of its responsibilities, as long as the subcommittee has at least the minimum number of directors necessary to meet any regulatory requirements. The compensation committee may engage consultants in determining or recommending the amount of compensation paid to our directors and executive officers. The compensation committee is governed by a written charter that is reviewed, and amended if necessary, on an annual basis. A copy of the charter is available on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.”
Nominating and Corporate Governance Committee
Our nominating and corporate governance committee currently consists of Mr. Benz, General McPeak and Mr. Brandolini, who is the chairman of the nominating and corporate governance committee. The nominating and corporate governance committee met once during the year ended December 31, 2016, but met separately on several occasions in connection with a meeting of the full Board.
The primary responsibilities of the nominating and corporate governance committee include identifying, evaluating and recommending, for the approval of the entire Board of Directors, potential candidates to become members of the Board of Directors, recommending membership on standing committees of the Board of Directors, developing and recommending to the entire Board of Directors corporate governance principles and practices for our company and assisting in the implementation of such policies, and assisting in the identification, evaluation and recommendation of potential candidates to become officers of our company. The nominating and corporate governance committee will review our code of business conduct and ethics and its enforcement, and reviews and recommends to our Board of Directors whether waivers should be made with respect to such code. A copy of the nominating and corporate governance committee charter may be found on our website at www.lilisenergy.com under “Investor Relations-Corporate Governance-Highlights.” During fiscal year 2016, there have been no material changes to the procedures by which security holders may recommend nominees to our Board of Directors.
Communications with the Board of Directors
Stockholders may communicate with our Board of Directors or any of the directors by sending written communications addressed to the Board of Directors or any of the directors, Lilis Energy, Inc., 300 E. Sonterra Blvd., Suite No. 1220, San Antonio, Texas 78258, Attention: General Counsel. All communications are compiled by the general counsel and forwarded to the Board of Directors or the individual director(s) accordingly.
Code of Ethics
Our Board of Directors has adopted a code of business conduct and ethics, which we refer to as the Code, that applies to all of our officers and employees, including our chief executive officer, chief financial officer or controller, and persons performing similar functions. Our code of business conduct and ethics codifies the business and ethical principles that govern all aspects of our business. A copy of our code of business conduct and ethics is available on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.” We undertake to provide a copy of our code of business conduct and ethics to any person, at no charge, upon a written request. All written requests should be directed to: Lilis Energy, Inc., 300 E. Sonterra Blvd., Suite No. 1220, San Antonio, Texas 78258, Attention: General Counsel. If any substantive amendments are made to our code of business conduct and ethics, or if any waiver (including any implicit waiver) is granted from any provision of the code of business conduct and ethics to our chief executive officer, chief financial officer or controller, we will disclose the nature of such amendment or waiver on our website at www.lilisenergy.com under “Investors-Corporate Governance-Highlights.” or, if required, in a Current Report on Form 8-K.
Item 11. Executive Compensation
Executive Compensation for Fiscal Year
20162019
We are currently considered a “smaller reporting company” for purposes of the SEC’s executive compensation and other disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures.
The compensation earned by our executive officers for the year
endingended December 31,
20162019, consisted of base salary, short-term incentive compensation consisting of cash
bonus payments and long-term incentive compensation consisting of awards of stock grants.
All share and per share amounts, fair values per share and exercise prices that appear in this section have been adjusted to reflect the 1-for-10 reverse stock split of our outstanding common stock effected on June 23, 2016.
Summary Compensation Table
The table below sets forth compensation paid to our
chief executive officer, chief financial officer and our other most highly compensated executive officer during the fiscal years ended December 31, 2019 and 2018, which we refer to as our named executive officers
(NEOs)(“NEOs”) for the years
endingended December 31,
20162019 and
2015.Name and Principal
Position | | Year | | Salary
($) | | | Bonus
($) | | | Stock
Awards
($)(1) | | | Option
Awards
($)(2) | | | All Other
Compensation
($)(3) | | | Total
($) | |
| Abraham “Avi” Mirman | | 2016 | | | 350,000 | | | | 175,000 | (4) | | | ─ | | | | 4,295,894 | | | | 22,484 | | | | 4,843,378 | |
| (Chief Executive Officer) | | 2015 | | | 325,466 | | | | 100,000 | (5) | | | 90,000 | | | | 1,397,721 | | | | 31,504 | | | | 1,944,691 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ronald D. Ormand(6) | | 2016 | | | 150,000 | | | | ─ | | | | 1,875,000 | | | | 533,092 | | | | 69,502 | | | | 2,627,594 | |
| (Chairman of the Board of Directors) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ariella Fuchs | | 2016 | | | 240,000 | | | | 112,500 | (4) | | | ─ | | | | 1,288,768 | | | | 8,417 | | | | 1,649,685 | |
| (General Counsel and Secretary) | | 2015 | | | 182,083 | | | | ─ | | | | 48,000 | | | | 234,887 | | | | 10,538 | | | | 475,508 | |
|
| | | | | | | | | | | | | |
| Name and Principal Position | Year | Salary
($)(1) | Bonus
($)(2) | Stock
Awards
($)(3) | Option
Awards
($) | All Other
Compensation
($)(4) | Total
($) |
Joseph C. Daches(5) | 2019 | 450,000 |
| 800,000 |
| 1,194,000 |
| — |
| 38,387 |
| 2,482,387 |
|
| (Chief Executive Officer, President and Chief Financial Officer) | 2018 | 420,513 |
| 600,000 |
| — |
| — |
| 43,883 |
| 1,064,396 |
|
Ronald D. Ormand(6) | 2019 | 239,743 |
| 800,000 |
| 1,592,000 |
| — |
| 1,034,730 |
| 3,666,473 |
|
| (Former Chief Executive Officer) | 2018 | 500,000 |
| 1,250,000 |
| — |
| — |
| 24,326 |
| 1,750,000 |
|
James W. Denny, III(7) | 2019 | 199,993 |
| 200,000 |
| 298,500 |
| | 227,515 |
| 926,008 |
|
| (Executive Vice President, Operations) | 2018 | 255,458 |
| 100,000 |
| 876,000 |
| — |
| 23,271 |
| 1,254,729 |
|
| |
(1) | Represents restrictedThe base salary amounts in this column represent actual base compensation paid or earned through the end of the applicable year. |
| |
(2) | The amounts in this column include annual bonuses paid for the applicable year. |
| |
(3) | The amounts in this column represent the aggregate grant date fair value of stock awards.awards granted during the applicable year. The grant date fair values for restricted stock awards were computed in accordance with FASB ASC Topic 718. The amounts reported in this column reflect the accounting cost for the stock awards and do not necessarily correspond to the actual economic value that may be received for the stock awards. |
| (2) | Awards in this column are reported at grant date fair value, if awarded in the period, and any incremental fair value, if modified in the period, in each case in accordance with FASB ASC Topic 718. Mr. Mirman was granted 1,250,000 options on each of June 24, 2016 and December 15, 2016; Mr. Ormand was granted 250,000 options on December 15, 2016; and Ms. Fuchs was granted 375,000 options on each of June 24, 2016 and December 15, 2016. The grant date fair values for options granted on June 24, 2016 and December 15, 2016 were $1.30 (rounded) and $2.13 (rounded), respectively. For both Mr. Mirman and Ms. Fuchs, their options granted June 24, 2016 were modified December 15, 2016 to provide for accelerated exercisability upon an involuntary employment termination and upon a change in control, and for extension of the post-termination exercise period upon an employment termination other than for cause. However, there was no incremental fair value for those modified options. The amounts reported in this column reflect the accounting cost for the options and do not correspond to the actual economic value that may be received for the options. The assumptions used to calculate the fair value of options are set forth in the notes to our consolidated financial statements included in this Annual Report on Form 10-K. |
| (3)(4) | For 2016, reflects2019, this amount includes $8,682 and $25,738 paid for reimbursement of health insurance premiums for all of the NEOs. Forto Mr. Ormand and Mr. Daches, respectively. The amount also includes $1,026,048 for severance and COBRA for Mr. Ormand. This also includes 401K matching for Mr. Daches in the amount also reflects $55,000of $10,153 for 2018 and $10,375 in director fees paid to him for his Board service2019, and Mr. Denny in 2016 prior to the time he became an officer.amount of $5,305 in 2018 and $5,221 in 2019. |
| (4) |
(5) | Reflects a bonus payable under the officer’s employment agreement for the successful completion of the Brushy merger.On November 13, 2019, Mr. Daches was appointed Chief Executive Officer. He has been Chief Financial Officer since January 23, 2017, and President since August 16, 2018. |
| (5) |
(6) | Reflects a sign-on bonus. |
| (6) | Effective July 11, 2016,On June 6, 2019, Mr. Ormand began to serveresigned as Chief Executive Officer and as Executive Chairman of the Board, which is an officer position. Prior to July 11, 2016,Board. |
| |
(7) | On June 28, 2019, Mr. Ormand was a nonemployee director ofDenny ceased serving as the Board and his compensation from January 1 to July 10, 2016 is reflected under All Other Compensation.Executive Vice President, Operations. |
Outstanding Equity Awards at Fiscal Year-End
| | | Option Awards | | Stock Awards | |
| Name | | Number of
Securities
Underlying
Unexercised
Options
(#)
Exercisable | | | Number of
Securities
Underlying
Unexercised
Options
(#)
Unexercisable | | | Option
Exercise
Price ($) | | | Option
Expiration
Date | | Number of
Shares or
Units of
Stock That
Have Not
Vested
(#) | | | Market
Value of
Shares or
Units of
Stock That
Have Not
Vested
($) | |
| | | | | | | | | | | | | | | | | | |
| Abraham “Avi” Mirman | | | 170,000 | | | | 330,000 | (1) | | | 2.98 | | | 12/15/2026 | | | ─ | | | | ─ | |
| | | | 425,000 | | | | 825,000 | (2) | | | 1.34 | | | 6/24/2026 | | | ─ | | | | ─ | |
| | | | 60,000 | | | | ─ | | | | 21.10 | | | 9/16/2023 | | | ─ | | | | ─ | |
| Ronald D. Ormand | | | 85,000 | | | | 165,000 | (1) | | | 2.98 | | | 12/15/2026 | | | 833,333 | (3) | | | 2,583,332 | |
| | | | 31,666 | | | | 13,334 | (4) | | | 16.50 | | | 4/20/2025 | | | ─ | | | | ─ | |
| Ariella Fuchs | | | 127,500 | | | | 247,500 | (1) | | | 2.98 | | | 12/15/2026 | | | ─ | | | | ─ | |
| | | | 127,500 | | | | 247,500 | (2) | | | 1.34 | | | 6/24/2026 | | | ─ | | | | ─ | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| Name | | Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable | | Number of
Securities
Underlying
Unexercised
Options (#)
Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) | | Option
Exercise
Price
($) | | Option
Expiration
Date | | Number of
Shares or
Units of
Stock That
Have Not
Vested
(#) | | Market Value
of Shares or
Units of Stock
That Have Not
Vested
($)(1) | | Market or Payout Value of Unearned Shares, Units or Other Rights That have Not Vested |
| | | | | | | | | | | | | | | | | |
| Joseph C. Daches | | 750,000 |
| | — |
| | — |
| | 2.98 |
| | 12/15/2026 |
| | 396,000 |
| | 150,480 |
| | — |
|
Ronald D. Ormand(2) | | 250,000 |
| | — |
| | — |
| | 2.98 |
| | 12/15/2026 |
| | — |
| | — |
| | — |
|
James W. Denny, III(3) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Vesting of options and stock awards reflected in this table is subject to continuous service with our Company, except that unvested awards may vest upon termination by us without cause, termination by the officer for good reason, or termination due to the officer’s disability or death (in each case as set forth in the applicable award agreement or employment agreement).
| |
(1) | Options vest in equal installmentsThe market value of the stock awards is based on eachthe closing price per share of our common stock on the NYSE American on December 15, 2017 and 2018, subject to acceleration provisions and continued service31, 2019, which was $0.38. |
| |
(2) | Options vest in equal installmentsMr. Ormand held 693,000 shares of unvested restricted stock as of his retirement, which vesting was accelerated upon his retirement on each of June 24, 2017 and 2018, subject to acceleration provisions and continued service.5, 2019. |
| |
(3) | RestrictedMr. Denny forfeited 165,000 unvested shares vest in equal installmentsof restricted common stock upon his separation from the Company on each of July 7, 2017 and July 7, 2018, subject to acceleration provisions and continued service.June 28, 2019. |
| (4) | Options vest in equal installments on each of April 20, 2017 and 2018, subject to acceleration provisions and continued service. |
Employment Agreements and Other Compensation Arrangements
2012 Equity Incentive Plan (“2012 EIP”) (formerly the Recovery Energy, Inc. 2012 Equity Incentive Plan)
Our Board and stockholders approved our 2012 EIP in August 2012. The 2012 EIP provided for grants of equity incentives to: attract, motivate and retain the best available personnel for positions of substantial responsibility; provide additional incentives to our employees, directors and consultants; and promote the success and growth of our business. Equity incentives that were available for grant under our 2012 EIP included stock options, stock appreciation rights (SARs), restricted stock awards, restricted stock units (RSUs), and unrestricted stock awards.
Our 2012 EIP is administered by
the independent members of our
compensation committee,Board, subject to the ultimate authority of our Board, which has full power and authority to take all actions and to make all determinations required or provided for under the 2012 EIP.
Under our 2012 EIP, 1,000,000 shares of our common stock were available for issuance. As a result of the adoption of our 2016
Omnibus Incentive Plan
(“2016 Plan”), awards are no longer made under the 2012 EIP, as discussed below.
2016 Omnibus Incentive Plan
(“2016 Plan”)
Our 2016 Plan was approved by our Board effective April 20, 2016 and approved by our stockholders at
theirthe Company’s 2016 annual meeting on May 23, 2016. Our 2016 Plan replaced our 2012 EIP.
The purposes of our 2016 Plan are to create incentives that are designed to motivate eligible directors, officers, employees and consultants to put forth maximum effort toward our success and growth, and to enable us to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to our success.
On a go forward basis, the Company intends to base compensation on certain performance matrices relating to employees positions or roles and standards utilized by its peers in the industry. By using measurable goals, the Company can more easily validate award increases based on employee and Company performance combined and assure that the Company remains competitive.
Awards may be granted under our 2016 Plan to
our officers, employees, directors, consultants and advisors
of the Company and its affiliates. Tax-qualified incentive stock options may be granted only to
employees of the Company or its subsidiaries.
our employees.
Our 2016 Plan may be administered by our Board or
its compensation committee. Oura compensation committee
of the Board. The independent members of our Board, in
itstheir discretion, generally
selectsselect the individuals to whom awards may be granted, the time or times at which awards are granted and the terms and conditions of awards.
Number of Authorized Shares
When initially approved by our stockholders, 50,000,000 shares of our common stock were made available for issuance under our 2016 Plan. As a result of our 1-for-10 reverse stock split, which took effect on June 23, 2016, the number of shares available for issuance under our 2016 Plan was automatically reduced to 5,000,000. On August 25, 2016, our Board approved an amendment to our 2016 Plan to increase the maximum number of shares that may be issued from 5,000,000 to 10,000,000, and our stockholders approved that amendment at a special meeting on November 3, 2016.
In addition, as On May 15, 2017, our Board approved a second amendment to the 2016 Plan to increase the maximum number of May 23, 2016, any awards then outstanding undershares of our 2012 EIP remain subject to and willcommon stock that may be paidissued under the 2012 EIP2016 Plan from 10,000,000 to 13,000,000, and anyour stockholders approved that amendment at the 2017 Annual Meeting. In 2018, our Board and our stockholders approved a third amendment to the 2016 Plan to increase the maximum number of shares then subject to outstanding awardsof our common stock that may be issued under the 2012 EIP that subsequently expire, terminate or are surrendered or forfeited for any reason without issuance of shares will automatically become available for issuance under our 2016 Plan. Plan from 13,000,000 to 18,000,000.
Up to
5,000,00018,000,000 shares may be granted as tax-qualified incentive stock options under our 2016 Plan. The shares issuable under our 2016 Plan
will consist of authorized and unissued shares, treasury shares or shares purchased on the open market or otherwise.
If any award is canceled, terminates, expires or lapses for any reason prior to the issuance of shares or if shares are issued under our 2016 Plan and thereafter are forfeited to
the Company,us, the shares subject to those awards and the forfeited shares will not count against the aggregate number of shares available for grant under the plan. In addition, the following items will not count against the aggregate number of shares available for grant under our 2016 Plan: (1) the payment in cash of dividends or dividend equivalents under any outstanding award, (2) any award that is settled in cash rather than by issuance of shares, (3) shares surrendered or tendered in payment of the option price or purchase price of an award or any taxes required to be withheld in respect of an award or (4) awards granted in assumption of or in substitution for awards previously granted by an acquired company.
Limits on Awards to Nonemployee Directors
The maximum number of shares subject to awards under our 2016 Plan granted during any calendar year to any nonemployee member of our Board, taken together with any cash fees paid to the director during the fiscal year, may not exceed $500,000 in total value (calculating the value of any such awards based on the grant date fair value of such awards for financial reporting purposes).
Our 2016 Plan permits the granting of any or all of the following types of awards: stock options, which entitle the holder to purchase a specified number of shares at a specified price; SARs, which, upon exercise, entitle the holder to receive payment per share in stock or cash equal to the excess of the share’s fair market value on the date of exercise over the grant price of the SAR; restricted stock, which are shares of common stock subject to specified restrictions; RSUs, which represent the right to receive shares of our common stock in the future; other types of equity or equity-based awards; and performance awards, which entitle participants to receive a payment from
the Company,us, the amount of which is based on the attainment of performance goals established by the
compensation committeeindependent members of our Board over a specified award period.
Without
shareholderstockholder approval,
the independent members of our
compensation committee isBoard are not authorized to (1) lower the exercise or grant price of a stock option or SAR after it is granted, except in connection with certain adjustments to our corporate or capital structure permitted by our 2016 Plan, such as stock splits, (2) take any other action that is treated as a repricing under generally accepted accounting principles or (3) cancel a stock option or SAR at a time when its exercise or grant price exceeds the fair market value of the underlying stock, in exchange for cash, another stock option or SAR, restricted stock, RSUs or other equity award, unless the cancellation and exchange occur in connection with a change in capitalization or other similar change.
All awards granted under our 2016 Plan will be subject to all applicable laws regarding the recovery of erroneously awarded compensation, any implementing rules and regulations under such laws, any policies we adopt to implement such requirements and any other compensation recovery policies as we may adopt from time to time.
2016 Plan awards are not transferable other than by will or the laws of descent and distribution, except that in certain instances transfers may be made to or for the benefit of designated family members of the participant for no value.
Effect of Change in Control
Under our 2016 Plan, in the event of a change in control, outstanding awards will be treated in accordance with the applicable transaction agreement. If no treatment is provided for in the transaction agreement, each award holder will be entitled to receive the same consideration that stockholders receive in the change in control for each share of stock subject to the award holder’s awards, upon the exercise, payment or transfer of the awards, but the awards will remain subject to the same terms, conditions and performance criteria applicable to the awards before the change in control, unless otherwise determined by
the independent members of our
compensation committee.Board. In connection with a change in control, outstanding stock options and SARs can be
cancelledcanceled in exchange for the excess of the per share consideration paid to stockholders in the transaction, minus the applicable exercise price.
Subject to the terms and conditions of the applicable award agreement, awards granted to nonemployee directors will fully vest upon a change in control.
Subject to the terms and conditions of the applicable award agreement, for awards granted to all other service providers, vesting of awards will depend on whether the awards are assumed, converted or replaced by the resulting entity.
| · | For awards that are not assumed, converted or replaced, the awards will vest upon the change in control. For performance awards, the amount vesting will be based on the greater of (1) achievement of all performance goals at the “target” level or (2) the actual level of achievement of performance goals as of our fiscal quarter end preceding the change in control, and will be prorated based on the portion of the performance period that had been completed through the date of the change in control. |
| · | For awards that are assumed, converted or replaced by the resulting entity, no automatic vesting will occur upon the change in control. Instead, the awards, as adjusted in connection with the transaction, will continue to vest in accordance with their terms and conditions. In addition, the awards will vest if the award recipient has a separation from service within two years after a change in control other than for cause or by the award recipient for good reason. For performance awards, the amount vesting will be based on the greater of (1) achievement of all performance goals at the “target” level or (2) the actual level of achievement of performance goals as of fiscal quarter end preceding the change in control, and will be prorated based on the portion of the performance period that had been completed through the date of the separation from service. |
For awards that are not assumed, converted or replaced, the awards will vest upon the change in control. For performance awards, the amount vesting will be based on the greater of (1) the achievement of all performance goals at the “target” level or (2) the actual level of achievement of performance goals as of our fiscal quarter end preceding the change in control and will be prorated based on the portion of the performance period that had been completed through the date of the change in control.
For awards that are assumed, converted or replaced by the resulting entity, no automatic vesting will occur upon the change in control. Instead, the awards, as adjusted in connection with the transaction, will continue to vest in accordance with their terms and conditions. In addition, the awards will vest if the award recipient has a separation from service within two years after a change in control other than for cause or by the award recipient for good reason. For performance awards, the amount vesting will be based on the greater of (1) achievement of all performance goals at the “target” level or (2) the actual level of achievement of performance goals as of fiscal quarter end preceding the change in control, and will be prorated based on the portion of the performance period that had been completed through the date of the separation from service.
Term, Termination and Amendment of 2016 Plan
Unless earlier terminated by our Board, our 2016 Plan will terminate, and no further awards may be granted, 10 years after the date on which it
iswas initially approved by stockholders. Our Board may amend, suspend or terminate our 2016 Plan at any time, except that, if required by applicable law, regulation or stock exchange rule, stockholder approval will be required for any amendment. The amendment, suspension or termination of our 2016 Plan or the amendment of an outstanding award generally may not, without a participant’s consent, materially impair the participant’s rights under an outstanding award.
Equity Grants for Fiscal Year
20162019
During
ourthe year ended December 31,
2016,2019, we granted
1,780,0523,684,372 shares of restricted common stock and
5,683,500135,000 options to purchase shares of common stock to
our employees and directors. Also, during
the year ended December 31, 2016, our employees forfeited and we cancelled 335,0002019, 1,650 stock options
and 257,730 shares of restricted stock previously issued
and unvested were forfeited or canceled in connection with the termination of certain employees,
and directors. As a result, asthe departure of
December 31, 2016, the Company had 1,068,305certain directors and/or shares canceled to cover tax withholding on vested restricted
shares of common stock and 5,956,833 options to purchase shares of common stock outstanding to employees and directors.shares. Options issued to employees and directors generally vest in equal installments over specified time periods during the service period or upon achievement of certain
performance basedperformance-based operating thresholds.
Employment Agreements
On February 14, 2019, Mr.
MirmanEffective as of March 30, 2015, we entered into an amended and restated employment agreement with Mr. Mirman, which replaced his prior employment agreement. The agreement had a three-year term and provided for a $100,000 cash bonus due upon signing, base compensation of $350,000 per year, and 200,000 stock options, where one-third of the options vested immediately and two-thirds were scheduled to vest in two annual installments on each of the next two anniversaries of the grant date. The agreement also provided for additional bonuses due based on our achievement of certain performance measures.
On July 5, 2016, we entered into a new employment agreement with Mr. Mirman under which he will serve as our CEO. This agreement became effective June 24, 2016 upon the closing of our merger with Brushy. The initial term of the agreement is scheduled to end on December 31, 2017, and the agreement will renew automatically for additional one-year periods beginning on December 31, 2017, unless either party gives notice of non-renewal at least 180 days before the end of the then-current term. The agreement replaces in its entirety Mr. Mirman’s prior employment agreement with the Company.
Mr. Mirman’s base salary (which will be reviewed by the Board for adjustments) is $350,000 for the first year of the agreement, $375,000 for the second year of the agreement, and $425,000 for the third year of the agreement. Mr. Mirman was entitled to a bonus under the agreement equal to $175,000, payable in cash on the first regular payroll date of the Company following June 24, 2016 (the closing date of the merger with Brushy). Mr. Mirman will also be eligible to receive a cash bonus equal to a percentage of his base salary (ranging from 0% to 400%) depending on the level of achievement of certain BOE per day, EBITDAX and cash on hand performance measures. Mr. Mirman will also be eligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentive plans, in each case as determined by our Board in its discretion. On June 24, 2016, Mr. Mirman received a grant of 1,250,000 stock options under our 2016 Plan, with an exercise price of $1.34. This grant is scheduled to vest over two years, with 34% vesting on the grant date, 33% vesting on the first anniversary of the grant date and 33% vesting on the second anniversary of the grant date, subject to continued service through each vesting date.
Under his employment agreement, Mr. Mirman will be entitled to a lump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums upon a termination by us without cause or a termination by him for good reason. Upon a termination by us without cause or a termination by Mr. Mirman for good reason within 12 months following a change in control, he will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Mirman will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Mirman’s employment agreement are subject to his execution and non-revocation of a release of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Mr. Mirman receiving a greater net after tax benefit as a result of the reduction.
All payments to Mr. Mirman under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr. Mirman is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under his employment agreement.
Mr. Ormand
On July 5, 2016, we entered into an employment agreement with Ronald D. Ormand, effective as of July 11, 2016, under which he will serve as our Executive Chairman. The initial term of the agreement is scheduled to end on December 31, 2017, and the agreement will renew automatically for additional one-year periods beginning on December 31, 2017, unless either party gives notice of non-renewal at least 180 days before the end of the then-current term.
Mr. Ormand’s base salary (which will be reviewed by the Board for adjustments) is $300,000 for the first year of the agreement, $350,000 for the second year of the agreement, and $400,000 for the third year of the agreement. Mr. Ormand will be eligible to receive a cash bonus equal to a percentage of his base salary (ranging from 0% to 400%) depending on the level of achievement of certain BOE per day, EBITDAX and cash on hand performance measures. Mr. Ormand will also be eligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentive plans, in each case as determined by our Board in its discretion. On July 7, 2016, Mr. OrmandDaches received a grant of restricted stock under our 2016 Plan for 1.25 millioncovering 600,000 shares of our common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary of the date of the grant, and 33% vesting on the second anniversary of the date of the grant, subject to continued service through each vesting date.
Under his employment agreement,service.
On February 14, 2019, Mr. Ormand will be entitledreceived a grant of restricted stock under our 2016 Plan covering 800,000 shares of our common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary of the date of the grant, and 33% vesting on the second anniversary of the date of the grant, subject to a lump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums upon a termination by us without cause or a termination by him for good reason. Upon a termination by us without cause or a termination bycontinued service. Mr. Ormand for good reason within 12 months followingheld 693,000 shares of unvested restricted stock as of his retirement, which vesting was accelerated upon his retirement on June 5, 2019.
On February 14, 2019, Mr. Denny received a change in control, he will be entitled to a lump sum severance payment equal to 24 monthsgrant of base salaryrestricted stock under our 2016 Plan covering 150,000 shares of our common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary of the date of the grant, and 24 months33% vesting on the second anniversary of COBRA premiums. Upon a termination due to disability, Mr. Ormand will be entitled to a lump sum severance payment equal to six monthsthe date of COBRA premiums. All severance payments under Mr. Ormand’s employment agreement arethe grant, subject to continued service. Mr. Denny forfeited 99,000 unvested shares of restricted common stock upon his executionseparation from the Company on June 28, 2019.
Equity Grants for Fiscal Year 2018
During the year ended December 31, 2018, we granted 1,194,944 shares of restricted common stock and
non-revocation352,500 options to purchase shares of
a releasecommon stock to our employees and directors. Also, during 2018, 1,601,045 stock options and 1,280,480 shares of
claims against us. The severance payments are also subject to reductionrestricted stock previously issued and unvested were forfeited or canceled in
order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Mr. Ormand receiving a greater net after tax benefit as a result of the reduction.All payments to Mr. Ormand under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr. Ormand is subject to non-competition, non-solicitation, anti-raiding, and confidentiality provisions under his employment agreement.
Ms. Fuchs
In connection with the appointmenttermination of Ms. Fuchs ascertain employees, the departure of certain directors and/or shares canceled to cover tax withholding on vested restricted shares. Options issued to employees and directors generally vest in equal installments over specified time periods during the service period or upon achievement of certain performance-based operating thresholds.
On May 3, 2018, Mr. Denny received a grant of restricted stock under our General Counsel,2016 Plan covering 200,000 shares of our common stock. The restricted stock vests over two years, with 34% vesting on the date of the grant, 33% vesting on the first anniversary of the date of the grant, and 33% vesting on the second anniversary of the date of the grant, subject to continued service. Mr. Denny forfeited 66,000 unvested shares of restricted common stock upon his separation from the Company on June 28, 2019.
Employment Agreements
Mr. Daches
On December 17, 2019, we entered into an employment agreement with
her dated March 16, 2015. The agreement provided, among other things, that Ms. Fuchs would receive an annual salary of $230,000. Additionally,Mr. Daches, effective as of
the effective date of the agreement, Ms. Fuchs was granted (i) 5,000 shares of restricted stock and (ii) 30,000 stock options, which were scheduled to vestJanuary 1, 2020, in
equal installments on the first three anniversaries of the effective date of the agreement. Ms. Fuchs was also eligible receive a cash incentive bonus if we achieved certain production thresholds.On July 5, 2016, we entered into a new employment agreementconnection with Ms. Fuchs under which she will continue to servehis appointment as our General Counsel. This agreement became effective June 24, 2016 upon the closing of our merger with Brushy.Chief Executive Officer. The initial term of the agreement is scheduled to end on December 31, 2017,January 1, 2022, and the agreement will renew automatically for additional one-year periods beginning on December 31, 2017,January 1, 2022, unless either party gives notice of non-renewal at least 180 days before the end of the then-current term. TheThis agreement replaces in its entirety Ms. Fuchs’Mr. Daches’ prior employment agreement with us.
Ms. Fuchs’ initialthe Company.
Mr. Daches’ annual base salary under thethis agreement (which will be reviewed periodically by the Board for adjustments) is $250,000. Ms. Fuchs was entitledwill not be less than $515,000. Mr. Daches will also be eligible to a bonus underreceive bonuses and awards of equity and non-equity compensation and to participate in the agreement equal to $112,500, payable in cash on the first regular payroll dateannual and long-term compensation plans of the Company, following June 24,in each case as determined by our Board. The target annual bonus for Mr. Daches set forth in his agreement is no less than 100% of base salary and restricted shares equal to 200% of base salary. In 2019, Mr. Daches received a $200,000 cash bonus for his appointment as Interim Chief Executive Officer. Under Mr. Daches’ prior employment agreement, he received an annual salary of $480,000 during 2019.
Mr. Ormand
On July 5, 2016, (the closing datewe entered into an employment agreement with Ronald D. Ormand, effective as of July 11, 2016. The initial term of the merger with Brushy). Ms. Fuchs is alsoagreement was scheduled to end on December 31, 2017, and the agreement renewed automatically for additional one-year periods beginning on December 31, 2017, unless either party gave notice of non-renewal at least 180 days before the end of the then-current term.
Mr. Ormand’s base salary under his agreement (which was reviewed by the Board for adjustments) was $300,000 for the first year of the agreement, $350,000 for the second year of the agreement, and $400,000 for the third year of the agreement. Mr. Ormand was eligible to receive a cash bonus equal to a percentage of herhis base salary (ranging from 0% to 400%) depending on the level of achievement of certain BOE per day, EBITDAX and cash on hand performance measures. Ms. Fuchs isMr. Ormand was also eligible to receive awards of equity and non-equity compensation and to participate in our annual and long-term incentive plans, in each case as determined by our Board in its discretion.
On June
24, 2016, Ms. Fuchs received a grant of 375,000 stock options under our 2016 Plan, with an exercise price of $1.34. This grant is scheduled to vest over two years, with 34% vesting on the grant date, 33% vesting on the first anniversary6, 2019, Mr. Ormand retired as Chief Executive Officer and Executive Chairman of the
grant date and 33% vesting onBoard. In connection with his retirement, Mr. Ormand entered into a separation agreement with the
second anniversary of the grant date, subjectCompany, pursuant to
continued service through each vesting date.which he received $1,026,048 as separation payment. Potential Payments Upon Termination or Change-In-Control
Mr. Daches
Under
herhis employment agreement,
Ms. Fuchs’ will be entitled to a lump sum severance payment equal to six months of base salary and six months of COBRA premiums upon a termination by the Company without cause or a termination by
her for good reason. Upon a termination by the Company without cause or a termination by Ms. Fuchshim for good reason,
within 12 months following a change in control, she will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Ms. Fuchs will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Ms. Fuchs employment agreement are subject to her execution and non-revocation of a release of claims against the Company. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Ms. Fuchs receiving a greater net after tax benefit as a result of the reduction.All payments to Ms. Fuchs under her employment agreement will be subject to clawback in the event required by applicable law. Further, Ms. Fuchs is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under her employment agreement.
Potential Payments Upon Termination or Change-In-Control
Mr. Mirman
Under his employment agreement, Mr. MirmanDaches will be entitled to a lump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums upon a termination by us without cause or a termination by him for good reason.premiums. Upon a termination by the Company without cause or a termination by Mr. MirmanDaches for good reason within 1218 months followingafter a change in control, he will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Mirman will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Mirman’sDaches’ employment agreement are subject to his execution and non-revocation of a release of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Mr. Mirman receiving a greater net after tax benefit as a result of the reduction. All payments to Mr. Mirman under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr. Mirman is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under his employment agreement.
Mr. Ormand
Under his employment agreement, Mr. Ormand will be entitled to a lump sum severance payment equal to 12 months of base salary and 12 months of COBRA premiums upon a termination by us without cause or a termination by him for good reason. Upon a termination by us without cause or a termination by Mr. Ormand for good reason within 12 months following a change in control, he will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Mr. Ormand will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Mr. Ormand’s employment agreement are subject to his execution and non-revocation of a release of claims against the Company. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Mr. Ormand receiving a greater net after tax benefit as a result of the reduction. All payments to Mr. Ormand under his employment agreement will be subject to clawback in the event required by applicable law. Further, Mr. Ormand is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under his employment agreement.
Ms. Fuchs
Under her employment agreement, Ms. Fuchs’ will be entitled to a lump sum severance payment equal to six months of base salary and six months of COBRA premiums upon a termination by us without cause or a termination by her for good reason. Upon a termination by us without cause or a termination by Ms. Fuchs for good reason within 12 months following a change in control, she will be entitled to a lump sum severance payment equal to 24 months of base salary and 24 months of COBRA premiums. Upon a termination due to disability, Ms. Fuchs will be entitled to a lump sum severance payment equal to six months of COBRA premiums. All severance payments under Ms. Fuchs employment agreement are subject to her execution and non-revocation of a release of claims against us. The severance payments are also subject to reduction in order to avoid an excise tax associated with Section 280G of the Internal Revenue Code, but only if that reduction would result in Ms. Fuchs receiving a greater net after tax benefit as a result of the reduction. All payments to Ms. Fuchs under her employment agreement will be subject to clawback in the event required by applicable law. Further, Ms. Fuchs is subject to non-competition, non-solicitation, anti-raiding and confidentiality provisions under her employment agreement.
Mr.
Mirman, Mr. Ormand and Ms. Fuchs holdDaches holds unvested options under our 2016 Plan, all of which become fully exercisable (1) immediately upon the officer’s separation from service other than for cause or for good reason, and (2) immediately prior to, and contingent upon, a change in control prior to the officer’s separation from service.
Retirement and Other Benefits
All employees, including our
NEOs,named executive officers, may participate in our 401(k) retirement savings plan (“401(k) Plan”). Each employee may make before tax contributions in accordance with Internal Revenue Service limits. We provide this 401(k) Plan to help our employees save a portion of their cash compensation for retirement in a tax efficient manner. In prior years, we have made a matching contribution in an amount equal to 100% of the employee’s elective deferral contribution
below 3%up to 4% of the employee’s
compensation and 50% of the employee’s elective deferral that exceeds 3% of the employee’s compensation but does not exceed 5% of the employee’sannual compensation.
Compensation of Nonemployee Directors
| Name | | Fees Earned
or Paid in
Cash
Compensation
($) | | | Stock Awards
($)(1) | | | Option
Awards
($)(2) | | | All Other
Compensation ($) | | | Total ($) | |
| | | | | | | | | | | | | | | | |
| G. Tyler Runnels(3) | | | ─ | | | | ─ | | | | ─ | | | | ─ | | | | ─ | |
| Nuno Brandolini(4) | | | 72,500 | | | | 135,000 | | | | ─ | | | | ─ | | | | 207,500 | |
| General Merrill McPeak(5) | | | 85,000 | | | | 135,000 | | | | ─ | | | | ─ | | | | 220,000 | |
| R. Glenn Dawson(6) | | | 70,522 | | | | 255,750 | | | | 81,000 | | | | ─ | | | | 407,272 | |
| Peter Benz(7) | | | 43,901 | | | | 135,000 | | | | 67,500 | | | | ─ | | | | 246,401 | |
| (1) | Represents restricted stock awards. The grant date fair values for restricted stock awards were determined in accordance with FASB ASC Topic 718. The amounts reported reflect the accounting cost for the awards and do not correspond to the actual economic value that may be received for the awards. |
| (2) | Awards in this column are reported at grant date fair value in accordance with FASB ASC Topic 718. The amounts reported reflect the accounting cost for the options and do not correspond to the actual economic value that may be received for the options. The assumptions used to calculate the fair value of options are set forth in the notes to our consolidated financial statements included in this Annual Report on Form 10-K. As of December 31, 2016, our nonemployee directors held the following equity awards: Mr. Brandolini - 45,000 options, 50,000 restricted shares and 41,666 restricted stock units; General McPeak - 45,000 options, 33,333 restricted shares and 66,666 restricted stock units; Mr. Dawson - 45,000 options and 113,667 restricted shares; and Mr. Benz - 45,000 options and 33,333 restricted shares. |
| (3) | Mr. Runnels served as a director from November 21, 2014, through January 13, 2016. |
| (4) | Mr. Brandolini has served as a director since February 13, 2014. |
| (5) | General McPeak was appointed to the board on January 29, 2015. |
| (6) | Mr. Dawson was appointed to the Board on January 13, 2016. |
| (7) | Mr. Benz was appointed to the Board on June 23, 2016. |
On April 16, 2015,
The compensation of our
Board adopted an amended nonemployeenon-employee directors is reviewed and approved by the Board. We use a combination of cash and stock-based incentive compensation to attract and retain qualified candidates to serve on our Board. In determining director compensation,
program (the “Prior Program”). The Prior Program was comprisedwe consider the significant amount of
time the
following components: | · | Initial Grant: Each nonemployee director would receive 100,000 restricted shares of common stock on the first anniversary of the date of the director’s appointment, which would vest in three equal installments over a three-year period, (subject to the continued service of the director and certain accelerated vesting provisions); |
| · | Annual Stock Award: Each nonemployee director would receive an annual stock award equal to $60,000 divided by the most recent per share closing price of the common stock prior to the date of each annual grant, payable on each anniversary of the date an independent director was initially appointed to our Board, and subject to certain accelerated vesting provisions; |
| · | Option Award: Each nonemployee director would receive a one-time initial grant of 25,000 stock options, which would vest immediately, and 20,000 options that would vest in equal installments over a three-year period beginning on the first anniversary of the grant date; and |
| · | Committee Fees: On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to Chairman of the Board, Chairman of the Audit Committee or Chairman of the Compensation Committee, the director would receive $12,500, $6,250 and $6,250, respectively, in cash compensation, which at the election of the director would be payable in cash or stock (calculated by dividing the value of cash compensation (or a portion thereof), by the most recent per share closing price of the common stock prior to the date of the grant). |
directors spend fulfilling their duties, as well as the competitive market for skilled directors.
Beginning January 1, 2017, our Board adopted an amended nonemployee director compensation program (the
“New“Director Compensation Program”).
The New Program is substantially similar to the Prior Program. However, the NewOur Director Compensation Program sets forth an annual equity date (which will be the first business day on or after January 31 of each year) pursuant to which each nonemployee director will receive an
Annual Stock Award,annual stock award, subject to substantially the same terms and conditions set forth above. In addition, the
NewDirector Compensation Program establishes annual limits on the number of shares subject to our equity compensation plan awards that may be granted during any calendar year to any director, which, taken together with any cash fees paid to the director during the year, cannot exceed $500,000 in total value.
Our Director Compensation Program is comprised of the following components:
Initial Grant: Each nonemployee director receives 10,000 restricted shares of common stock on the first anniversary of the date of the director’s appointment, which would vest in three equal installments over a three-year period, (subject to the continued service of the director and certain accelerated vesting provisions);
Initial Option Award: Each nonemployee director receives a one-time initial grant of 25,000 stock options, which would vest immediately, and 20,000 options that would vest in equal installments over a three-year period beginning on the first anniversary of the grant date;
Annual Stock Award: Each nonemployee director would receive an annual stock award equal to $150,000 divided by the most recent per share closing price of the common stock prior to the date of each annual grant, payable on each anniversary of the date an independent director was initially appointed to our Board, and subject to certain accelerated vesting provisions;
Annual Fees:On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to the Board, each director receives $15,000 in cash compensation;
Chairman and Committee Chairman Fees: On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to Chairman of the Board, Chairman of the Audit Committee, Chairman of the Compensation Committee, Chairman of the Reserves Committee, and Chairman of the Nominating and Governance Committee, the director receives $12,500, $6,250, $6,250, $6,250, and $2,500 respectively, in cash compensation; and
Committee Fees: On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to the Audit Committee, the Compensation Committee, the Reserves Committee, and the Nominating and Governance Committee, the director receives $3,125, $2,500, $2,500, and $1,875, respectively, in cash compensation.
Our Board evaluates the fees and compensation paid to the directors for their service on our Board on an annual basis.
Effective as of April 15, 2020, the Board dissolved its Reserves Committee, Compensation Committee and Nominating and Corporate Governance Committee. With respect to such committees, we do not expect to pay any additional committee chairman fees or committee fees during 2020.
As previously disclosed, the Company has formed a Special Committee. On a quarterly basis, beginning at the end of the first full quarter following the appointment of the nonemployee director to Chairman of the Special Committee or member of the Special Committee, the director receives $6,250 and $3,125, respectively, in cash compensation.
2019 Director Compensation
In 2019, each non-employee director received compensation consistent with our Director Compensation Program, consisting of an annual stock award, with additional fees being paid to the chairman of the Audit Committee, the chairman of the Compensation Committee, the chairman of the Reserves Committee, and the chairman of the Nominating and Governance Committee. Each member who served on a committee received an additional fee in connection for service on such committee. The fees received by our directors are pro-rated based on the time of their service with the Company. Each non-employee director is reimbursed for reasonable out-of-pocket costs incurred to attend Board meetings.
|
| | | | | | | | | | | | | | | |
| Name | | Fees Earned
or Paid in
Cash
Compensation
($) | | Stock
Awards
($)(1) | | Option
Awards
($) | | All Other
Compensation
($) | | Total
($) |
Michael G. Long(2) | | 95,000 |
| | 121,700 |
| | 97,650 |
| | — |
| | 314,350 |
|
Nuno Brandolini(3) | | 80,000 |
| | 150,000 |
| | — |
| | — |
| | 230,000 |
|
Mark Christensen(4) | | 60,000 |
| | 150,000 |
| | — |
| | — |
| | 210,000 |
|
R. Glenn Dawson(5) | | 103,750 |
| | 150,000 |
| | — |
| | 276,875 |
| | 530,625 |
|
John Johanning(6) | | 182,500 |
| | — |
| | — |
| | — |
| | 182,500 |
|
Ronald D. Ormand(7) | | 30,000 |
| | — |
| | — |
| | — |
| | 30,000 |
|
Markus Specks(8) | | 181,875 |
| | — |
| | — |
| | — |
| | 181,875 |
|
Nicholas Steinsberger(9) | | 55,000 |
| | 124,200 |
| | 97,650 |
| | 185,000 |
| | 461,850 |
|
David M. Wood(10) | | 81,875 |
| | 163,310 |
| | 97,650 |
| | — |
| | 342,835 |
|
| |
(1) | Represents restricted stock awards. Awards in this column are reported at grant date fair value in accordance with FASB ASC Topic 718. The amounts reported reflect the accounting cost for the awards and do not correspond to the actual economic value that may be received for the awards. On January 31, 2019, Mr. Brandolini, Mr. Christensen and Mr. Dawson were each granted 69,124 shares of restricted stock, Mr. Steinsberger was awarded 47,235 shares of restricted stock, Mr. Long was awarded 46,083 shares of restricted stock and Mr. Wood was awarded 161,681 shares of restricted stock. These awards all vested in full immediately. Mr. Long and Mr. Steinsberger also each received 10,000 shares of restricted stock that have a 3-year vesting, with the first vesting date being the first anniversary of the award. |
| |
(2) | Mr. Long was appointed to the Board on April 10, 2018. In 2019, Mr. Long received a fee of $15,000 per quarter for his service as a Director, $6,250 per quarter for his service as Chairman of the Audit Committee, and $2,500 per quarter for his service as a member of the Compensation Committee. Mr. Long also received an annual stock award grant of $100,000, which at the grant date stock price of $2.17 per share resulted in 46,083 shares of the Company’s common stock. Mr. Long also received a non-qualified incentive stock award for 45,000 of the Company’s common stock that vests over three years. |
| |
(3) | Mr. Brandolini was appointed to the Board on February 13, 2014. In 2019, Mr. Brandolini received a fee of $15,000 per quarter for his service as a Director, $2,500 per quarter for his service as Chairman of the Nominating and Corporate Governance Committee, and $2,500 per quarter for his service as a member of the Compensation Committee. Mr. Brandolini also received an annual stock award grant of $150,000, which at the grant date stock price of $2.17 per share resulted in 69,124 shares of the Company’s common stock. |
| |
(4) | Mr. Christensen was appointed to the Board on September 6, 2017. In 2019, Mr. Christensen received a fee of $15,000 per quarter for his service as a Director. Mr. Christensen also received an annual stock award grant of $150,000, which at the grant date stock price of $2.17 per share resulted in 69,124 shares of the Company’s common stock. Effective as of April 15, 2020, Mr. Christensen resigned from the Board. |
| |
(5) | Mr. Dawson was appointed to the Board on January 13, 2016. In 2019, Mr. Dawson received a fee of $15,000 per quarter for his service as a Director, $6,250 for his service as Chairman of the Compensation Committee, and $3,125 per quarter for his service as member of the Audit Committee. In 2019, Mr. Dawson received a quarterly fee of $60,000 per quarter on an interim basis for his service as Chairman of the Reserves Committee due to additional oversight responsibility requested by the Board (as described in the Amended and Restated Reserves Committee Charter) to be performed until requisite Company personnel is available to handle such responsibilities, which such fee for service as the Chairman of the Reserves Committee was approved by all members of the Board. Mr. Dawson also received an annual stock award grant of $150,000, which at the |
grant date stock price of $2.17 per share resulted in 69,124 shares of the Company’s common stock. Effective as of April 15, 2020, Mr. Dawson resigned from the Board.
| |
(6) | Mr. Johanning was appointed to the Board on March 1, 2018. In 2019, Mr. Johanning received a fee of $15,000 per quarter for service as a Director and $2,500 per quarter for his service as a member of the Reserves Committee. In lieu of the prorated annual stock award equal to $150,000, Mr. Johanning elected to receive a cash payment of $112,500, which is equal to $150,000 prorated for Mr. Johanning joining the Board in March 2018. The quarterly fees were paid directly to Värde. |
| |
(7) | Mr. Ormand became a nonemployee Director on the Board on June 6, 2019. Beginning with the third quarter of 2019, Mr. Ormand received a fee of $15,000 per quarter for his service as a Director. Effective as of April 15, 2020, Mr. Ormand resigned from the Board. |
| |
(8) | Mr. Specks was appointed to the Board on March 1, 2018. In 2019, Mr. Specks received a fee of $15,000 per quarter for his service as a Director and $1,875 per quarter for his service as a member of the Nominating and Corporate Governance Committee. In lieu of the prorated annual stock award equal to $150,000, Mr. Specks elected to receive a cash payment of $112,500, which is equal to $150,000 prorated for Mr. Specks joining the Board in March 2018. The quarterly fees were paid directly to Värde. |
| |
(9) | Mr. Steinsberger was appointed to the Board on May 3, 2018. In 2019, Mr. Steinsberger received $15,000 per quarter for his service as a Director and $2,500 per quarter for his service as a member of the Reserves Committee. For the first quarter of 2019, in lieu of his $15,000 cash payment for service as a Director, Mr. Steinsberger elected to receive a grant award of 6,912 shares of the Company’s common stock, which at the grant date stock price of $2.17 per share was equal to $15,000. Mr. Steinsberger also received an annual stock award grant of $87,500, which at the grant date stock price of $2.17 per share resulted in 40,323 shares of the Company’s common stock. Mr. Steinsberger also received a non-qualified incentive stock award for 45,000 of the Company’s common stock that vests over three years. Mr. Steinsberger also received $60,000 per quarter for consulting with the Company; see “Item 13. Certain Relationships and Related Transactions, and Director Independence - Related Party Transactions” below for more information. |
| |
(10) | Mr. Wood was appointed to the Board on June 1, 2018 and resigned from the Board on March 12, 2020. Mr. Wood received a fee of $15,000 per quarter for his service as a Director, $1,875 for his service as a member on the Nominating Committee and $3,125 per quarter for his service as a member of the Audit Committee. Mr. Wood also received an annual stock award grant of $75,000, which at the grant date stock price of $2.17 per share resulted in 34,562 shares of the Company’s common stock. Mr. Wood received a grant award of 127,119 shares of the Company’s stock for his compensation as Chairman, which at the grant date stock price of $0.52 per share was equal to $66,101, as approved by the Board. Mr. Wood also received a non-qualified incentive stock award for 45,000 of the Company’s common stock that vests over three years. Effective as of March 13, 2020, Mr. Wood resigned from the Board. |
Indemnification of Directors and Officers
Pursuant to our certificate of incorporation we provide indemnification of our directors and officers to the fullest extent permitted under Nevada law. We believe that this indemnification is necessary to attract and retain qualified directors and officers.
Item 12. | Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Securities Authorized for Issuance under Equity Compensation Plans
The following table represents the securities authorized for issuance under our equity compensation plans at December 31, 2016.
| Plan category | | Number of
securities to
be issued
upon exercise
of outstanding
options,
warrants and
rights (1) | | | Weighted-average
exercise price of
outstanding
options, warrants
and rights (2) | | | Number of
securities
remaining
available for
future issuance
under equity
compensation
plans | |
| | | | | | | | | | |
| Equity compensation plans approved by security holders | | | 5,354,794 | | | | 1.74 | | | | 3,574,742 | |
| Equity compensation plans not approved by security holders | | | - | | | | - | | | | | |
| Total | | | 5,354,794 | | | | 1.74 | | | | 3,574,742 | |
| (1) | Includes stock options and restricted stock units outstanding under our 2016 Plan and our 2012 EIP as of December 31, 2016. Does not include shares of restricted stock issued pursuant to our 2016 Plan or our 2012 EIP. |
| (2) | Represents the weighted average exercise price of outstanding options issued pursuant to our 2016 Plan and our 2012 EIP as of December 31, 2016. |
Other Equity Compensation
We have entered into various services agreements for which compensation has been paid with equity securities, including (i) a consulting agreement with Bristol Capital LLC pursuant to which we issued to Bristol a five year warrant to purchase up to 641,026 shares of common stock at an exercise price of $3.12 per share (or, in the alternative, 641,026 options, but in no case both), (ii) consulting agreements with Market Development Consulting Group, Inc. pursuant to which we issued five year warrants to purchase up to an aggregate of 500,000 shares of common stock ,with an exercise price of $2.33 for the warrant to purchase 250,000 shares of common stockCertain Beneficial Owners and an exercise price of $2.00 for the warrant to purchase 250,000 shares of common stock; (iii) an investment banking agreement with TRW pursuant to which we issued 900,000 warrants at an exercise price of $4.25 per share;Management and (iv) various agreements pursuant to which issued an aggregate amount of 150,000 and 300,000 five year warrants to purchase shares of common stock at an exercise price of $2.50 and $2.00, respectively. With respect to the warrants awarded to Bristol Capital, we recorded the warrants as a derivative due to the price reset provision encompassed in the warrants.
Related Stockholder Matters SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information with respect to beneficial ownership of our common stock as of
March 1, 2017,April 30, 2020 by each of our executive officers and directors and each person known to be the beneficial owner of 5% or more of the outstanding common stock.
This table is based upon the total number of shares outstanding as of
March 1, 2017 of 24,387,793.April 30, 2020. Unless otherwise indicated, the persons and entities named in the table have sole voting and sole investment power with respect to the shares set forth opposite the stockholder’s name. Beneficial ownership is determined in accordance with Rule 13d-3 under the
Securities Exchange
Act of 1934, as amended.Act. In computing the number of shares beneficially owned by a person or a group and the percentage ownership of that person or group, shares of our common stock subject to options or warrants currently exercisable or exercisable within 60 days after
March 1, 2017April 30, 2020, are deemed outstanding by such person or group, but are not deemed outstanding for the purpose of computing the percentage ownership of any other person. All share amounts that appear in this report have been adjusted to reflect a 1-for-10 reverse stock split of our outstanding common stock effected on June 23, 2016. Unless otherwise indicated, the address of each stockholder listed in the table is c/o Lilis Energy, Inc.,
300 E. Sonterra Blvd. Ste. 1220, San Antonio,201 Main Street, Suite 700, Fort Worth, Texas
78258| | | Series B Preferred Stock | | | Common Stock | |
Name and Address of Beneficial
Owner | | Shared
Beneficially
Owned (1) | | | % of
Class | | | Lilis
common
stock
Held
Directly | | | Lilis
common
stock
Acquirable
Within 60
Days(2) | | | Total
Beneficially
Owned(2) | | | Percent of
Class
Beneficially
Owned(2) | |
| | | | | | | | | | | | | | | | | | | |
| Directors and Named Executive Officers | | | | | | | | | | | | | | | | | | | | | | | | |
| Abraham Mirman, Chief Executive Officer and Director | | | 1,650 | | | | 10.59 | % | | | 762,906 | (3) | | | 643,334 | (4) | | | 1,406,240 | | | | 5.6 | %(5) |
| Ronald D. Ormand, Executive Chairman of the Board | | | 1,000 | | | | 6.42 | % | | | 2,495,752 | (6) | | | 115,001 | (7) | | | 2,610,753 | | | | 10.7 | %(8) |
| Joseph Daches, Chief Financial Officer | | | — | | | | — | | | | 45,000 | | | | 250,000 | (9) | | | 295,000 | | | | 1.2 | % |
| Ariella Fuchs, Executive Vice President, General Counsel and Secretary | | | — | | | | — | | | | — | | | | 250,000 | (10) | | | 250,000 | | | | 1.0 | % |
| Peter Benz, Director | | | — | | | | — | | | | 75,000 | | | | 25,000 | (11) | | | 100,000 | | | | * | |
| Nuno Brandolini, Director | | | — | | | | — | | | | 402,060 | | | | 159,574 | (12) | | | 561,634 | | | | 2.3 | % |
| R. Glenn Dawson, Director | | | — | | | | — | | | | 440,861 | | | | 108,486 | (13) | | | 549,347 | | | | 2.2 | % |
| General Merrill McPeak, Director | | | — | | | | — | | | | 406,207 | | | | 143,521 | (14) | | | 549,728 | | | | 2.2 | % |
| Directors and Officers as a Group (10 persons) | | | 2,650 | | | | 17.0 | % | | | 4,627,786 | | | | 1,694,916 | (15) | | | 6,322,702 | | | | 24.2 | %(16) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| 5% Stockholders | | | | | | | | | | | | | | | | | | | | | | | | |
| Bryan Ezralow, 23622 Calabasas Road, Suite 200, Calabasas, CA 913012 | | | 900 | | | | 5.8 | % | | | 1,564,969 | (17) | | | — | (18) | | | 1,564,969 | | | | 6.42 | % |
| Marc Ezralow, 23622 Calabasas Road, Suite 200, Calabasas, CA 913012 | | | 750 | | | | 4.8 | % | | | 1,221,566 | (19) | | | — | (20) | | | 1,221,566 | | | | 5.01 | % |
|
| | | | | | | | | | | | |
| Name and Address of Beneficial Owner | | Lilis common
stock
Held Directly | | Lilis common
stock
Acquirable
Within 60
Days(1) | | Total
Beneficially
Owned | | Percent of
Class
Beneficially
Owned |
| Directors and Named Executive Officers | | | | | | | | |
| Joseph Daches, Chief Executive Officer, President, and Chief Financial Officer | | 1,149,560 |
| | 750,000 |
| | 1,899,560 |
| | 1.7 |
|
| Michael Long, Chairman of the Board | | 67,083 |
| | 25,000 |
| | 92,083 |
| | * |
| Nuno Brandolini, Director | | 704,709 |
| | 45,000 |
| | 749,709 |
| | * |
| John Johanning, Director | | — |
| | — |
| | — |
| | * |
Ronald D. Ormand, Former Director (2) | | 4,829,064 |
| | 295,000 |
| | 5,124,064 |
| | 4.5 |
|
| Markus Specks, Director | | — |
| | — |
| | — |
| | * |
| Nicholas Steinsberger, Director | | 67,235 |
| | 25,000 |
| | 92,235 |
| | * |
Directors and Officers as a Group (7 persons) (3) | | 6,817,651 |
| | 1,140,000 |
| | 7,957,651 |
| | 7.0 |
|
| | | | | | | | | |
| 5% Stockholders | | | | | | | | |
Värde Partners, Inc.(5)
901 Marquette Avenue South
Suite 330,
Minneapolis, MN 55402 | | 23,594,401 |
| | 24,000,000 (4) |
| | 47,594,401 |
| | 41.4 |
|
| |
| * | Represents beneficial ownership of less than 1% of the outstanding shares of common stock. |
| |
(1) | Applicable percentages are based on 15,588Represents shares of Series B Preferred Stock outstanding as of the date March 1, 2017. Series B Preferred Stock is non-voting, and currently, no holder of shares of Series B Preferred Stock may convert such shares if, upon conversion, such holder would beneficially own more than 4.99% of the Company’s then-outstanding stock. Accordingly, holders of 5% or more of shares of Series B Preferred Stock have been excluded from this beneficial ownership table.
|
(2)
| The terms of the Series B Preferred Stock, and each of the Company’s outstanding warrants, the “Blocker Securities”) contain a provision prohibiting the conversion of such Series B Preferred Stock, and the exercise of warrants into common stock of the Company if, upon such conversion or exercise, as applicable, the holder thereof would beneficially own more than a certain percentage of the Company’s then outstanding common stock (the “Blocker Limitation”). This percentage limitation is 4.99%, except that upon 61 days prior noticesubject to the Company, a holder of Series B Preferred Stock may increase the percentage limitation with respect to the Series B Preferred up to a maximum of 9.99%. However, the foregoing restrictions do not prevent such holder from converting or exercising, as applicable, some of its holdings, selling those shares,options and then converting or exercising, as applicable, more of its holdings, while still staying below the respective percentage limitation. As a result, the holder could sell more than any applicable ownership limitation while never actually holding more shares than the applicable limitations allow. Accordingly, the share numbers in the above table represent ownership without regard to the beneficial ownership limitations described in this footnote. While the ownership percentages are also given without regard to this beneficial ownership limitation, specific footnotes indicate what the effect of each ownership limitation would be as of March 1, 2017.warrants exercisable within 60 days. |
| |
| |
(3)(2) | Consists of: (i) 11,0872,706,792 shares of common stock held by The Bralina Group, LLC;Perugia Investments, LP (“Perugia”) and (ii) 751,8192,122,272 shares of common stock held directly by Mr. Mirman.Ormand. Mr. MirmanOrmand is manager of Perugia and has shared voting and dispositive power over the securities held by The Bralina Group, LLC with Susan Mirman.Perugia. |
| |
(3) | |
(4) | Represents shares of common stock subject to options exercisable within 60 days.
In addition, Mr. Mirman beneficially owns an aggregate of 2,566,274 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, Mr. Mirman’s percentage ownership is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 1,500,000 shares of common stock issuable upon conversion of shares of Series B Preferred held by the Bralina Group; (ii) 305,187 shares of common stock issuable upon exercise of warrants held by the Bralina Group and (iii) 761,087 shares of common stock issuable upon exercise of warrants held directly by Mr. Mirman.
|
| |
(5) | Including the Blocker Securities, and ignoring the Blocker Limitation, Mr. Mirman beneficially owns a total 3,972,514 shares of common stock, which represents 14.4% of our currently issued and outstanding common stock. |
(6)
| Consists of: (i) 1,259,388 shares of common stock held directly by Mr. Ormand; (ii) 100,000 shares of common stock held by Perugia Investments L.P. (“Perugia”); and (iii) 1,136,364 shares of common stock held by The Bruin Trust, an irrevocable trust managed by Jerry Ormand, Mr. Ormand’s brother, as trustee and whose beneficiaries include the adult children of Mr. Ormand. Mr. Ormand is the manager of Perugia and has sole voting and dispositive power over the securities held by Perugia.
|
| |
(7) | Represents shares of common stock subject to options exercisable within 60 days.
In addition, Mr. Ormand beneficially owns an aggregate of 1,874,011 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, Mr. Ormand’s percentage ownership is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (i) 464,920 shares of common stock issuable upon exercise of warrants held by Perugia; (ii) 500,000 shares of common stock issuable upon exercise of warrants held by The Bruin Trust; and (iii) 909,091 shares of common stock issuable upon conversion of shares of Series B Preferred Stock held by Perugia.
|
| |
(8) | Including the Blocker Securities, and ignoring the Blocker Limitation, Mr. Ormand beneficially owns a total 4,484,764 shares of common stock, which represents 17% of our currently issued and outstanding common stock. |
| |
(9) | Represents shares of common stock subject to options exercisable within 60 days. |
(10) | Represents shares of common stock subject to options exercisable within 60 days. |
| |
(11) | Represents shares of common stock subject to options exercisable within 60 days. |
| |
(12) | Consists of: (i) 45,000 shares of common stock subject to options exercisable within 60 days; and (ii) 114,574 shares of common stock issuable upon exercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as Mr. Brandolini is below the threshold of any such limitation. |
| |
(13) | Consists of: (i) 31,667 shares of common stock subject to options exercisable within 60 days; and (ii) 76,819 shares of common stock issuable upon exercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as Mr. Dawson is below the threshold of any such limitation. |
| |
(14) | Consists of: (i) 38,333 shares of common stock subject to options exercisable within 60 days; (ii) 105,188 shares of common stock issuable upon exercise of warrants. The effect of any Blocker Limitation with respect to the securities described here has been excluded, as General McPeak is below the threshold of any such limitation. |
| |
(15) | As indicated in the above footnotes, this amount excludes an aggregate of 4,440,285 additional shares of common stock acquirable within 60 days, which are subject to Blocker Limitations. |
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(16) | Including the Blocker Securities, and ignoring the Blocker Limitation, the directors and officers as a group beneficially own a total of 10,762,9877,957,651 shares of common stock, which represents 37.34%7.0% of our currently issued and outstanding common stock. |
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(17)(4) | Based solely on athe Schedule 13G13D/A filed by Bryan Ezralow on February 14, 2017. Collectively,March 8, 2019. This represents shares of common stock which may be issued pursuant to the conversion of the shares Series E Preferred Stock within 60 days as if such Series E Preferred Stock had been converted on the date of Common Stock reported herein in which Bryan Ezralow has shared voting and dispositive power over such sharesborrowing or issuance, as applicable. |
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(5) | Värde Partners, Inc. is an aggregate of 1,011,451 shares. Such shares are held directly by (a) the Ezralow Family Trust u/t/d 12/9/1980 (the “Family Trust”) in the amount of 36,723 shares, where Bryan Ezralow as a co-trusteeultimate owner of the Family Trust shares votinggeneral partners (the “General Partners”), of each of The Värde Fund XI (Master), L.P., The Värde Fund XII (Master), L.P., The Värde Skyway Fund, L.P., The Värde Skyway Mini-Master Fund, L.P., Värde Investment Partners (Offshore) Master, L.P., The Värde Fund VI-A, L.P., Värde Investment Partners, L.P., and dispositive power overVärde Investment Partners (Offshore) Master, L.P. (the “Värde Entities”), or of the General Partners’ general partners or managing members. Mr. George Hicks and Mr. Ilfryn Carstairs are the co-chief executive officers of Värde Partners, Inc. As such, shares,each of Värde Partners, Inc., Mr. Hicks and thus,Mr. Carstairs may be deemed to beneficially own such shares; (b) the Ezralow Marital Trust u/t/d 1/12/2002 (the “Marital Trust”) in the amount of 42,583 shares, where Bryan Ezralow as a co-trusteehave beneficial ownership of the Marital Trust shares votingowned by each of the Värde Entities. Each of Värde Partners, Inc., Mr. Hicks, and dispositive power over such shares,Mr. Carstairs disclaims beneficial ownership of the securities held indirectly through the Värde Entities except to the extent of their pecuniary interest therein, and thus, maythis disclosure shall not be deemed to beneficially ownan admission that any such shares; (c) Elevado Investment Company, LLC, a Delaware limited liability company (“Elevado Investment”), inreporting person is the amountbeneficial owner for purposes of 140,821 shares, where Bryan Ezralow as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of Elevado Investment, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (d) EMSE LLC (“EMSE”), a Delaware limited liability company, in the amount of 81,949 shares, where Bryan Ezralow, as a manager of EMSE, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (e) EZ Colony Partners, LLC, a Delaware limited liability company (“EZ Colony”), in the amount of 709,372 shares, where Bryan Ezralow as the sole trustee of one of the trusts that is a manager of EZ Colony, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (f) EZ MM&B Holdings, LLC, a Delaware limited liability company (“EZ MM&B”), in the amount of 3 shares, where Bryan Ezralow as the sole trustee of one of the trusts that is a manager of EZ MM&B, and as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of one of thethis Proxy Statement or for any other managers of EZ MM&B, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares.Collectively, the shares of Common Stock reported herein in which Bryan Ezralow has sole voting and dispositive power over such shares are 553,518 shares. Such shares are held directly by (a) the Bryan Ezralow 1994 Trust u/t/d/ 12/22/1994, Bryan Ezralow, Trustee (the “Bryan Trust”) in the amount of 518,669 shares, where Bryan Ezralow as sole trustee of the Bryan Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (b) the Marc Ezralow Irrevocable Trust u/t/d 6/1/2004 (the “Irrevocable Trust”) in the amount of 34,849 shares, where Bryan Ezralow as sole trustee of the Irrevocable Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares.
purpose. |
(18) | In addition, Bryan Ezralow beneficially owns an aggregate of 2,137,598 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, the percentage ownership by Bryan Ezralow is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (A) (i) 272,728 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 529,091 shares of common stock issuable upon the exercise of warrants, each held by the Bryan Trust; (B) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 68,546 shares of common stock issuable upon the exercise of warrants, each held by the Irrevocable Trust; (C) (i) 136,364 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 200,371 shares of common stock issuable upon the exercise of warrants, each held by Elevado; (D) (i) 90,910 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 75,550 shares of common stock issuable upon the exercise of warrants, each held by EMSE; (E) (i) 181,819 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 343,168 shares of common stock issuable upon the exercise of warrants, each held by EZ Colony; (F) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 53,234 shares of common stock issuable upon the exercise of warrants, each held by the Marital Trust; and (H) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 49,452 shares of common stock issuable upon the exercise of warrants, held by the Family Trust. |
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(19) | Based solely on a Schedule 13G filed by Marc Ezralow on February 14, 2017. Collectively, the shares of Common Stock reported herein in which Marc Ezralow has shared voting and dispositive power over such shares are an aggregate of 1,011,451 shares. Such shares are held directly by (a) the Ezralow Family Trust u/t/d 12/9/1980 (the “Family Trust”) in the amount of 36,723 shares, where Marc Ezralow, as a co-trustee of the Family Trust, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (b) the Ezralow Marital Trust u/t/d 1/12/2002 (the “Marital Trust”) in the amount of 42,583 shares, where Marc Ezralow, as a co-trustee of the Marital Trust, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (c) Elevado Investment Company, LLC, a Delaware limited liability company (“Elevado Investment”), in the amount of 140,821 shares, where Marc Ezralow as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of Elevado Investment, shares voting and dispositive power over such shares, and thus, be deemed to beneficially own such shares; (d) EMSE LLC (“EMSE”), a Delaware limited liability company, in the amount of 81,949 shares, where Marc Ezralow, as a manager of EMSE shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; (e) EZ Colony Partners, LLC, a Delaware limited liability company (“EZ Colony”), in the amount of 709,372 shares, where Marc Ezralow as the sole trustee of one of the trusts that is a manager of EZ Colony, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (f) EZ MM&B Holdings, LLC, a Delaware limited liability company (“EZ MM&B”) in the amount of 3 shares, where Marc Ezralow as the sole trustee of one of the trusts that is a manager of EZ MM&B, and as a co-trustee and manager, respectively, of the two trusts and limited liability company that comprise the managing members of one of the other managers of EZ MM&B, shares voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares.
Collectively, the shares of Common Stock reported herein in which Marc Ezralow has sole voting and dispositive power over said Common Stock are 210,115 shares. Such shares are held directly by (a) the Marc Ezralow 1997 Trust u/t/d/ 11/26/1997, Marc Ezralow, Trustee (the “Marc Trust”) in the amount of 175,266 shares, where Marc Ezralow as sole trustee of the Marc Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares; and (b) the SPA Trust u/t/d 9/13/2004 (the “SPA Trust”), in the amount of 34,849 shares, where Marc Ezralow as sole trustee of the SPA Trust has sole voting and dispositive power over such shares, and thus, may be deemed to beneficially own such shares.
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(20) | In addition, Marc Ezralow beneficially owns an aggregate of 1,769,416 additional shares of common stock acquirable within 60 days, each of which is subject to a Blocker Limitation. However, the percentage ownership by Marc Ezralow is currently in excess of such Blocker Limitations, and as a result, such Blocker Securities have been excluded from the table. These Blocker Securities consist of the following: (A) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock and (ii) 68,546 shares of common stock issuable upon exercise of warrants, each held the SPA Trust; (B) (i) 136,364 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 297,273 shares of common stock issuable upon exercise of warrants, each held by the 1997 Trust; (C) (i) 136,364 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 200,371 shares of common stock issuable upon the exercise of warrants, each held by Elevado; (D) (i) 90,910 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 75,550 shares of common stock issuable upon the exercise of warrants, each held by EMSE; (E) (i) 181,819 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 343,168 shares of common stock issuable upon the exercise of warrants, each held by EZ Colony; (F) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 53,234 shares of common stock issuable upon the exercise of warrants, each held by the Marital Trust; and (H) (i) 45,455 shares of common stock issuable upon conversion of shares of Series B Preferred Stock, and (ii) 49,452 shares of common stock issuable upon the exercise of warrants, held by the Family Trust.
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To Lilis’sour knowledge, except as noted above, no person or entity is the beneficial owner of 5% or more of Lilis’sour common stock.
Equity Compensation Plan Information
The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2019:
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| Plan Category | | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights
(a) | | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights
(b) | | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in column (a))
(c) |
| Equity compensation plans approved by security holders | | 3,588,350 | | 4.05 | | 5,372,127 |
| Equity compensation plans not approved by security holders | | — |
| | — |
| | — |
|
| Total | | 3,588,350 | | 4.05 | | 5,372,127 |
For additional information regarding the Company’s benefit plans and share-based compensation expense, see Note 17 - Share Based and Other Compensation to our consolidated financial statements included in this Annual Report.
Item 13. | Certain Relationships and Related Transactions, and Director Independence |
Item 13. Certain Relationships and Related Transactions, and Director Independence
Related Party Transactions
We describe below transactions and series of similar transactions, since January 1,
2016,2018, to which we were a party, in which:
| · | The amounts involved exceeded or will exceed the lesser of $120,000 or one percent (1%) of our average total assets at year-end for the last two completed fiscal years; and |
| · |
The amounts involved exceeded or will exceed the lesser of $120,000 or one percent (1%) of our average total assets at year-end for the last two completed fiscal years; and
Any of our directors, executive officers, or holders of more than 5% of our capital stock, or any member of the immediate family of, or person sharing the household with, any of the foregoing persons, who had or will have a direct or indirect material interest. |
All share and per share amounts applicable to our common stock from transactions that occurred prior to the June 23, 2016 reverse split in the following summaries of related party transactions have not been adjusted to reflect the 1-for-10 reverse split of our issued and outstanding common stock, unless specifically described below.
Series B Preferred Stock Private Placement
On June 15, 2016, we entered into the Series B Purchase Agreement with certain institutional and accredited investors (the “Purchasers”) in connection with the Series B preferred stock offering. For more information on the Series B preferred stock offering see Note 13-Shareholders Equity.
On June 6, 2016, as subsequently amended, we entered into a Transaction Fee Agreement with TRW, a more than 5% shareholder of our company during the year ended December 31, 2016, in connection with the Series B preferred stock offering to act as co-broker dealers along with KES7, and as administrative agent. TRW received a cash fee of $500,000 and broker warrants to purchase up to 452,724 shares of common stock, at an exercise price of $1.30, exercisable on or after September 17, 2016, for a period of two years. Of the cash fee paid to TRW, $150,000 was reinvested into the Series B preferred stock offering in exchange for 150 shares of Series B preferred stock and the related warrants to purchase 68,182 shares of common stock at an exercise price of $2.50. These fees were recorded as a reduction to equity.
Certain other Purchasers in the Series B preferred stock offering include certain of our related parties, such as Abraham Mirman, our Chief Executive Officer and a director, through the Bralina Group, LLC for which Mr. Mirman holds shared voting and dispositive power ($1.65 million); Ronald D. Ormand, the Chairman of our Board of Directors through Perugia Investments LP for which Mr. Ormand holds sole voting and dispositive power ($1.0 million), Kevin Nanke, the Company’s former Executive Vice President and Chief Financial Officer during the year ended December 31, 2016, through KKN Holdings LLC, for which Mr. Nanke holds sole voting and dispositive power ($200,000), R. Glenn Dawson, a director of our company ($125,000), Pierre Caland through Wallington Investment Holdings, Ltd. a more than 5% shareholder of our company ($250,000) during the year ended December 31, 2016 and Bryan Ezralow and Marc Ezralow through various entities beneficially owned by them ($1.3 million).
Credit and Guarantee Agreement and Warrant Reprice
On September 29, 2016, we entered into the Credit Agreement. For more information about the Credit Agreement see Management’s Discussion and Analysis—Credit Agreement and Warrant Reprice.
Certain parties to the Credit Agreement included certain of our related parties such as TRW, acting as collateral agent, and Bryan Ezralow, Marc Ezralow and Marshall Ezralow through certain of their investment entities ($2.8 million).
Debenture Conversion Agreement
On December 29, 2015, we entered into the Debenture Conversion Agreement with all of the remaining holders of the Debentures. For more information about the Debentures see Management’s Discussion and Analysis—Debentures.
Certain parties to the Debenture Conversion Agreement included certain of our related parties at that time, such as the Steven B. Dunn and Laura Dunn Revocable Trust dated 10/28/10, of which its respective Debenture amount converted was approximately $1.02 million, Bryan Ezralow through EZ Colony Partners, LLC of which his respective Debenture amount converted was approximately $1.54 million and Pierre Caland through Wallington Investment Holdings, Ltd., of which its respective Debenture amount converted was approximately $2.09 million. Steven B. Dunn and Laura Dunn Revocable Trust dated October 28, 2010 who held more than 5% of our Common Stock duringcapital stock, or any member of the year ended December 31, 2016.
immediate family of, or person sharing the household with, any of the foregoing persons, who had or will have a direct or indirect material interest.
Series A Preferred Stock
On May 30, 2014, we entered into a securities purchase agreement with accredited investors, pursuant to which it issued an aggregate of $7.5 million in Series A preferred stock with a conversion price of $24.10 and warrants to purchase up to 155,602 shares of common stock.
On June 23, 2016, after the receipt of requisite stockholder approval and in connection
Transactions with the
consummation of the Merger, all outstanding shares of Series A preferred stock were converted into common stock at a reduced conversion price of $5.00 a share, resulting in the issuance of 1,500,000 shares of common stock. In exchange for the reduction in conversion price from $24.10 per share to $5.00 per share, all accrued but unpaid dividends were forfeited.Several of our officers, directors and affiliates were investors in the Series A preferred stock and converted their shares at $5.00 including Abraham Mirman ($250,000), Ronald D. Ormand (through Perugia Investments ($500,000), Nuno Brandolini ($100,000), General Merrill McPeak ($250,000), TRW ($779,000) and Pierre Caland through Wallington Investment Holdings, Ltd. ($125,000).
Convertible Notes
In a series of transactions from December 29, 2015 to May 6, 2016, we issued an aggregate of approximately $5.8 million in Convertible Notes maturing on JuneVärde Parties
On January 30,
2016 and April 1, 2017 at a conversion price of $5.00 and warrants to purchase an aggregate of approximately 2.3 million shares of common stock with an exercise price of $2.50 for warrants issued between December 2015 and March 2016 and $0.10 for the warrants issued in May 2016. The purchasers include certain of our related parties, including Abraham Mirman, our Chief Executive Officer and director of our company ($750,000), the Bruin Trust (the “Bruin Trust”), an irrevocable trust managed by an independent trustee and whose beneficiaries include the adult children of Ronald D. Ormand, Chairman of our Board of Directors ($1.15 million), General Merrill McPeak, a director of our company ($250,000), Nuno Brandolini, a director of our company ($250,000), Glenn Dawson, a director of our company ($50,000), Kevin Nanke, the Company’s former Executive Vice President and Chief Financial Officer during the year ended December 31, 2016 ($100,000, which was reinvested instead of a cash bonus payment due to Mr. Nanke pursuant to his prior executive employment agreement), Pierre Caland through Wallington Investment Holdings, Ltd. ($300,000), who held more than 5% of our common stock during the year ended December 31, 2016, Bryan and Marc Ezralow, through various entities who held more than 5% of our common stock during the year ended December 31, 2016 ($905,381) and TRW ($400,000).Subsequently, warrants to purchase up to 620,000 shares of common stock issued in connection with the Convertible Notes between December 2015 and March 2016 were amended and restated to reduce the exercise price to $0.10 in exchange for additional consideration given to us in the form of participation in the May Convertible Notes offering. Of those warrants, a total of 80,000 warrants were exercised. Additionally, during the three months ended June 30, 2016, in exchange for several offers to immediately exercise a portion of each investor’s outstanding warrants issued between 2013 and 2014, we reduced the exercise price on warrants to purchase a total of 416,454 shares of common stock ranging from $42.50 to $25.00 per share to $0.10 per share, of which a total of 315,990 were subsequently exercised, resulting in the issuance of an aggregate amount of 300,706 shares of common stock due to certain cashless exercises. TRW net exercised warrants to purchase 80,000 shares of common stock at a reset exercise price of $0.10, resulting in the issuance of 75,820 shares.
TRW also received an advisory fee on the Convertible Notes in the amount of $350,000, which was subsequently reinvested in full into the Series B Preferred Offering for 350 shares of Series B Preferred Stock and related warrants to purchase up to 159,091 shares of common stock.
On June 23, 2016, we entered into the Note Conversion Agreement. Certain parties to the Note Conversion Agreement include certain of our related parties, such as each officer and director who invested in the Notes, each of whom converted their outstanding amounts in full. In addition, Pierre Caland, through Wallington Investments, Ltd., was signatory to the Note Conversion Agreement and converted its outstanding amounts in full.
On August 3, 2016, we entered into the first amendment to the Notes with the remaining holders of approximately $1.8 million of our Notes. Each of Bryan Ezralow and Marc Ezralow through various entities and TRW was a party to the first amendment. For a detailed description of the first amendment to the Convertible Notes see—Note 8—Long Term Debt.
SOS
In connection with the Merger, SOS, Brushy’s former subordinated lender, and a more than 5% shareholder of our Company during the year ended December 31, 2016, agreed to extinguish approximately $20.5 million of its outstanding debt in exchange for Brushy’s divestiture of its properties to SOS in the Giddings Field, the SOS Note and the SOS Warrant, which was completed on June 23, 2016.
March 2017 Private Placement
On February 28, 2017,2018, we entered into a Securities Purchase Agreement with certain private funds affiliated with Värde Partners, Inc. (the “Series C Purchasers”), pursuant to which, on January 31, 2018, the Series C Purchasers purchased 100,000 shares of our newly created series of preferred stock of the Company, designated as “Series C 9.75% Convertible Participating Preferred Stock” (the “Series C Preferred Stock”), for a purchase price of $1,000 per share, or an aggregate of $100,000,000. Värde Partners, Inc. is the lead lender, and certain private funds affiliated with Värde Partners, Inc. are lenders, under the Company’s Second Lien Credit Agreement.
On October 10, 2018, we entered into a transaction agreement (the “2018 Transaction Agreement”) by and among the Company and the Värde Parties, pursuant to which we agreed to issue to the Värde Parties (i) an aggregate of 5,952,763 shares of the Company’s common stock, par value $0.0001 per share, which includes 5,802,763 shares of common stock at an exchange price of $5.00 per share of common stock plus an additional 150,000 shares of common stock, and (ii) 39,254 shares of a newly created series of preferred stock of the Company, designated as “Series D 8.25% Convertible Participating Preferred Stock” (the “Series D Preferred Stock”), as consideration for the reduction by approximately $56.3 million of the outstanding principal amount of the Second Lien Term Loan under the Second Lien Credit Agreement, together with accrued and unpaid interest and the make-whole amount thereon totaling approximately $11.9 million, and issue and sell to the Värde Parties 25,000 shares of a newly created subseries of the Company’s Series Preferred Stock, designated as “Series C-2 9.75% Convertible Participating Preferred Stock”, for a purchase price of $1,000 per share, or an aggregate of $25 million. Värde Partners, Inc. is the lead lender, and certain private funds affiliated with Värde Partners, Inc. are lenders, under the Company’s Second Lien Credit Agreement. For more
information about the 2018 Transaction Agreement, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Preferred Stock Issuance” under Item 7 of this Annual Report.
On March 5, 2019, we entered into the transaction agreement (the “2019 Transaction Agreement”) by and among the Company and the Värde Parties, pursuant to which we agreed to issue to the Värde Parties an aggregate of (i) 9,891,638 shares of the Company’s common stock, par value $0.0001 per share (the “Term Loan Exchanged Common Stock”), (ii) 60,000 shares of a newly created series of preferred stock of the Company, designated as “Series E 8.25% Convertible Participating Preferred Stock” (the “Series E Preferred Stock” or the “Exchanged Series E Shares”), and (iii) 55,000 shares of a newly created series of preferred stock of the Company, designated as “Series F 9.00% Participating Preferred Stock” (the “Series F Preferred Stock” or the “Exchanged Series F Shares”, as consideration for the termination of the Second Lien Credit Agreement (as defined in connectionthe 2019 Transaction Agreement) and the satisfaction in full, in lieu of repayment in full in cash, of $133.6 million pursuant to the Payoff Letter (as defined in the 2019 Transaction Agreement) and issue to the Värde Parties, as consideration for the amendment and restatement of the Second Amended and Restated Series C Certificate of Designation and the Amended and Restated Series D Certificate of Designation, 7,750,000 shares of the Common Stock.
Värde Partners, Inc. was the lead lender, and certain private funds affiliated with Värde Partners, Inc. were lenders, under the March 2017 Private Placement.Company’s Second Lien Credit Agreement. Värde Partners, Inc. and its applicable affiliated funds beneficially own over 5% of our common stock. For more information onabout the March 2017 Private Placement2018 Transaction Agreement, see “Note 14 Preferred Stock - Preferred Stock Issuance” to our consolidated financial statements included in this Annual Report.
On April 21, 2020, Värde Investment Partners, L.P., an affiliate of Värde Partners, Inc., became a lender under our Revolving Credit Agreement by acquiring, from a prior lender, loans and commitments under the Revolving Credit Agreement in the principal amount of approximately $25.7 million. The loans and commitments acquired by Värde Investment Partners, L.P. are subject to certain subordination provisions set forth in the Revolving Credit Agreement, as amended by the Fourteenth Amendment thereto dated April 21, 2020. For additional information regarding our Revolving Credit Agreement, as amended, see Note 11 - Long-Term Debt to our consolidated financial statements included in this Annual Report and “Item 7 - Management’s Discussion and Analysis—LiquidityAnalysis of Financial Condition and Capital Resources—Subsequent Events—March 2017 Private Placement.The subscribers includeResults of Operations - Revolving Credit Agreement” in Part II of this Annual Report.
VPD Acquisition
On February 28, 2018, pursuant to an agreement we entered into with VPD Texas, L.P. (“VPD”) dated that date, we acquired from VPD a 50% undivided leasehold interest in certain
oil and gas properties and assets in Loving and Winkler Counties, Texas for a purchase price of
our related parties, including Bryanapproximately $10.5 million. VPD is affiliated with Värde Partners, Inc., which is the lead lender under the Second Lien Credit Agreement, and
Marc Ezralow through various entities ($2.6 million)Värde Partners, Inc. and
TRW, described further below.
G. Tyler Runnelscertain affiliated funds hold all of the issued and T.R. Winston
We have participated in several transactions with TRW,outstanding shares of which G. Tyler Runnels, a former member of our Board of Directors, is chairmanSeries C Preferred Stock. As such, Värde Partners, Inc. and majority owner. During the year ended December 31, 2016, Mr. Runnelsits applicable affiliated funds beneficially held more thanown over 5% of our common stock includingas a result of their respective conversion rights under the holdings of TRWSecond Lien Credit Agreement and his personal holdings, and has personally participated in certain transactions with us.
On January 31, 2014, we entered into the Debenture Conversion Agreement with all of the holders of the Debentures, including TRW and Mr. Runnels’ personal trust. On June 23, 2016, all of the outstanding Debentures were converted at $5.00. See “—Debenture Conversion Agreement.”
On May 3, 2016 through May 5, 2016, in exchange for several offers to immediately exercise outstanding warrants issued between 2013 and 2014, we reduced the exercise price on warrants to purchase a total of 265,803 shares of common stock from a range of $42.50 to $25.00 per share to $0.10 per share which resulted in the issuance of a total of 250,520 shares of common stock. TRW received a total of 758,203 shares of common stock in this transaction.
On June 6, 2016, as subsequently amended, we entered into a Transaction Fee Agreement with TRW in connection with the Series B preferred stock offering. See “—Series B Private Placement.”
C Preferred Stock.
Compensation of Directors
On
NovemberAugust 1,
2016, we entered into a sublease agreement with TRW to sublease office space in New York, for which we pay $10,000 per month on a month-to-month basis.On February 28, 2017, we entered into a Subscription Agreement in connection with2019, Steinsberger Tight Gas Consulting LLC and the March 2017 Private Placement, for which TRW acted as placement agent and received a fee of $459,060. Additionally, TRW was a participant in the offering for an aggregate amount of $750,000.
Ronald D. Ormand
On March 20, 2014, weCompany entered into an Engagement Agreement (the “Engagement Agreement”) with MLV & Co.engagement letter effective as of June 1, 2019, under which the Steinsberger Tight Gas Consulting LLC (“MLV”), whichprovides consulting services involving all areas of operations to the Company for $60,000 per quarter. Mr. Steinsberger, who is now owned by FBR & Co., after it acquired MLV in September of 2015, pursuant to which MLV acted as our exclusive financial advisor. Ronald D. Ormand, a member ofDirector on our Board, is Managing Partner of Directors since February 2015 and the current Executive Chairman of our Board of Directors, was previously the Managing Director and Head of the Energy Investment Banking Group at MLV. The Engagement Agreement provided for a fee of $25,000 to be paid monthly to MLV, subject to certain adjustmentsSteinsberger Tight Gas Consulting LLC.
For more information on this and other
specific fee arrangements in connection with the nature of financial services being provided. We expensed $75,000 and $175,000 for the three and six months ended June 30, 2015, respectively. On May 27, 2015, MLV agreed to take $150,000 of its accrued fees in our common stock and was issued 75,000 shares in lieu of payment. The closing share price on May 27, 2015 was $1.56. The term of Engagement Agreement expired on October 31, 2015. On November 8, 2016, we paid FBR $100,000 as final settlement of outstanding fees owed under the Engagement Agreement.Additionally, MLV had been involved in certain initial discussions relating to the Merger for which it did not receive a fee.
Agreements with FormerDirector compensation, see “Item 12. Executive Officers
Kevin Nanke, Former Executive Vice President and Chief Financial Officer
On February 13, 2017, we entered into a Separation and Release of Claims Agreement (the “Separation Agreement”) with Mr. Nanke, providing for his separation as an officer of our company, effective January 23, 2017. Pursuant to the Separation Agreement and the terms of his employment agreement, Mr. Nanke will receive (1) a lump sum severance payment in an amount equal to 24 months of base salary in effect immediately prior to the date of termination, (2) a lump sum payment equal to 24 months of COBRA premiums based on the terms of our group health plan and Mr. Nanke’s coverage under such plan as of the date of termination, and (3) a lump sum bonus payment of $175,000. For consideration of the separation benefits listed above, Mr. Nanke (1) provided a general release of claims against us, our affiliates, and related parties, (2) to the extent reasonable, shall continue to provide full and continued cooperation in good faith with our company, our subsidiaries, and affiliates for 24 months following the date of termination in connection with certain matters relating to our company, and (3) agreed to be bound by confidentiality commitments to our company.
Additionally, pursuant to Mr. Nanke’s former employment agreement with us, dated as of March 18, 2016, he was entitled to receive a performance bonus of $100,000 if we were to achieve certain compliance goals set forth therein. In May 2016, our Board of Directors approved the reinvestment by Mr. Nanke of his performance bonus in the amount of $100,000 into the May Offering, pursuant to the same terms as the May Offering.
Edward Shaw, Former Executive Vice President and Chief Operating Officer of the Company
On February 13, 2017, we entered into a Separation and Release of Claims Agreement (the “Settlement Agreement”) with Mr. Shaw, providing for his separation as an officer of our company, effective January 24, 2017 (the “Separation Date”). Pursuant to the Settlement Agreement, Mr. Shaw received (1) a lump sum severance payment in an amount equal to 3 months of base salary in effect immediately prior to the date of termination, (2) a lump sum payment equal to 3 months of COBRA premiums based on the terms of our group health plan and Mr. Shaw’s coverage under such plan as of the date of termination, and (3) a period of three months from the separation date to exercise all vested options. For consideration of the separation benefits listed above, Mr. Shaw (1) provided a general release of claims against us, our affiliates, and related parties, (2) to the extent reasonable, shall continue to provide full and continued cooperation in good faith with our company, our subsidiaries, and affiliates for 24 months following the date of termination in connection with certain matters relating to our company, and (3) agreed to be bound by confidentiality commitments to our company.
For additional information on the above-mentioned agreements, see “Employment Agreements and Other Arrangements” above.
Compensation of Directors
See “Executive Compensation—- Compensation of Nonemployee Directors” above.
Employee Relationship
The Company employs Austin Brooks, who is the son-in law of Ronald Ormand, who was a Director on our Board until his resignation on April 15, 2020. In 2019, his total compensation, including salary, bonus and other benefits, totaled approximately $379,204. Our employment relationship with Mr. Brooks was entered into in 2018 in the ordinary course of business and has been conducted on an arm’s-length basis, and the compensation paid to Mr. Brooks is commensurate with that of his peers.
Conflict of Interest
PolicyOur Board of Directors has recognized that transactions between us and certain related persons present a heightened risk of conflicts of interest. Disclosure
We have a corporate code of business conduct that requires disclosure of any conflicts of interests at least annually and upon awareness of any potential conflict of interest, policy that prohibits conflicts of interests unless approved by our Board of Directors. such conflict will either be prohibited or the Company will adopt a mitigation plan to protect the Company’s interest.
Director Independence
Our Board follows the standards of Directors hasindependence established a course of conduct whereby it considers in each case, whetherunder the proposed transaction is on terms as favorable or more favorable to us than would be available from a non-related party. Our Board of Directors also looks at whether the transaction is fair and reasonable to us, taking into account the totalityrules of the NYSE American, as well as our Corporate Governance Guidelines on Director Independence, in determining if directors are independent. The Board has determined that four of our current directors, Mr. Brandolini, Mr. Johanning, Mr. Specks, and Mr. Long, are “independent directors” under the NYSE American rules referenced above.
No independent director receives, or has received, any fees or compensation directly as an individual from us other than compensation received in his capacity as a director or indirectly through their respective companies, except as described above. There were no transactions, relationships
betweenor arrangements not otherwise disclosed that were considered by the
parties involved, including other transactions that may be particularly favorable or advantageous to us. EachBoard in determining whether any of the
related party transactions described above was presented to our Board of Directors for consideration and each of these transactions was unanimously approved by our Board of Directors after reviewing the criteria set forth in the preceding two sentences.Director Independence
See “Directors, Executive Officers and Corporate Governance—Affirmative Determinations Regarding Director Independence and Other Matters” above.
directors were independent.
Item 14. Principal Accounting Fees and Services
The following table sets forth fees billed by our principal accounting firm
MarcumBDO USA, LLP for the years ended December 31,
20162019 and
2015:| | | Year Ended December 31, | |
| Fee Category | | 2016 | | | 2015 | |
| | | (In thousands) | |
| Audit Fees | | $ | 358 | | | $ | 264 | |
| Audit-Related Fees | | | 341 | | | | 5 | |
| Tax Fees | | | - | | | | - | |
| All Other Fees | | | - | | | | - | |
| Total Fees | | $ | 699 | | | $ | 269 | |
|
| | | | | | | | |
| (In thousands) | | Year Ended
December 31, |
| | | 2019 | | 2018 |
| Audit Fees | | $ | 738 |
| | $ | 1,032 |
|
| Audit Related Fees | | $ | — |
| | $ | — |
|
| Tax Fees | | $ | — |
| | $ | — |
|
| All Other Fees | | $ | — |
| | $ | — |
|
Audit Fees consist of the aggregate fees for professional services rendered for the audit of our annual financial statements and the reviews of the financial statements included in our Quarterly Reports on Forms 10-Q and for any other services that were normally provided by our auditors in connection with our statutory and regulatory filings or engagements.
Audit-Related Fees consist of the aggregate fees billed or reasonably expected to be billed for professional services rendered for assurance and related services that were reasonably related to the performance of the audit or review of our financial statements and were not otherwise included in Audit Fees. Majority of these services were related to the Brushy merger.
Tax Fees consist of the aggregate fees billed for professional services rendered for tax consulting. Included in such Tax Fees were fees for consultancy, review, and advice related to our income tax provision and the appropriate presentation on our financial statements of the income tax related accounts.
All Other Fees consist of the aggregate fees billed for products and services provided by our auditors and not otherwise included in Audit Fees, Audit-Related Fees or Tax Fees.
Audit Committee Pre-Approval Policy
Consistent with SEC rules regarding auditor independence, our Audit Committee has the responsibility for appointing, approving the compensation of, and overseeing the work of our independent public accounting firm. Our independent registered public accounting firm may not be engaged to provide non-audit services that are prohibited by law or regulation to be provided by it, nor may our independent registered public accounting firm be engaged to provide any other non-audit service unless it is determined that the engagement of the principal accountant provides a business benefit resulting from its inherent knowledge of our
companyCompany while not impairing its independence. Our
audit committeeAudit Committee must pre-approve permissible non-audit services. During the year ended December 31,
2016,2019, we had no non-audit services provided by our independent registered public accounting firm.
PART IV
Item 15. Exhibits, Financial Statement Schedules
| a) | Index to Financial Statements |
| b) |
| (i) | ExhibitsThe consolidated financial statements of Lilis Energy, Inc. are listed on the Index to this Form 10-K, page 79. |
The information required by this Item is set forth on the exhibit index that follows the signature page to this Annual Report on Form 10-K and is incorporated herein by reference.
| c) |
| b. | Financial Statement SchedulesThe following exhibits are filed or furnished with this Annual Report on Form 10-K or incorporated by reference: |
Not applicable.
b) Exhibits
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 3, 2017 | By: | /s/ Abraham Mirman |
| | Abraham Mirman |
| | 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/ Abraham Mirman | | Chief Executive Officer, Director | | March 3, 2017 |
Abraham Mirman | | (Principal Executive Officer) | | |
| | | | |
/s/ Joseph C. Daches | | Executive Vice President and Chief Financial Officer | | March 3, 2017 |
Joseph C. Daches | | (Principal Financial and Accounting Officer) | | |
| | | | |
/s/ Ronald D. Ormand | | Executive Chairman of the Board | | March 3, 2017 |
Ronald D. Ormand | | | | |
| | | | |
/s/ Peter Benz | | Director | | March 3, 2017 |
Peter Benz | | | | |
| | | | |
/s/ Nuno Brandolini | | Director | | March 3, 2017 |
Nuno Brandolini | | | | |
| | | | |
/s/ R. Glenn Dawson | | Director | | March 3, 2017 |
R. Glenn Dawson | | | | |
| | | | |
/s/ General Merrill McPeak | | Director | | March 3, 2017 |
General Merrill McPeak | | | | |
Exhibit Index
The following exhibits are either filed herewith or incorporated herein by reference
2.1 | Agreement and Plan of Merger, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016). |
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| Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of May 30, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 4, 2014). |
3.4 | Amendment to Certificate of Designation of Preferences, Rights, and Limitations of Series A 8% Convertible Preferred Stock, dated as of June 12, 2014 (incorporated herein by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed on June 17, 2014). |
3.5 | Certificate of Designation of Preferences, Rights and Limitations of 6% Redeemable Preferred Stock, dated as of August 29, 2014 (incorporated herein by reference to Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014). |
3.6 | Certificate of Designation of Preferences, Rights and Limitations of Series B 6% Convertible Preferred Stock, dated as of June 15, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 16, 2016). |
3.7 | |
3.8 | |
4.1 | |
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| Five Year Warrant to David Castaneda dated January 17, 2014 (incorporated herein by reference to Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014). |
4.4 | Five Year Warrant (Anniversary Warrant) to David Castaneda dated January 17, 2014 (incorporated herein by reference to Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014). |
4.5 | |
4.6 | |
4.7 | Warrant to Purchase Common Stock issued to Heartland Bank (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q, filed on February 26, 2015). |
4.8 | Form of Convertible Note (incorporated herein by reference to Exhibit 4.14.2 to the Company’s Current Report on Form 8-K filed on January 5, 2016). |
4.9 | Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016). |
4.10 | |
4.11 | Common Stock Purchase Warrant issued to SOSV Investments, LLC on June 23, 2016. (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q filed on August 25, 2016). |
4.12 | Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 28, 2017). |
4.13 | |
4.14† | |
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4.15† | |
10.1† | Employment Agreement with Kevin Nanke, |
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10.2† | Employment Agreement with Ariella Fuchs, dated as |
10.3† | Amended and Restated Employment Agreement between the Company and Abraham Mirman, dated as of March 30, 2015 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 2, 2015). |
10.4 | |
10.5 | Voting Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc., Brushy Resources, Inc. and SOSventures, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 5, 2016). |
10.6 | Voting Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., Lilis Merger Sub, Inc., Brushy Resources, Inc. and Longview Marquis Fund LP, LMIF Investments LLC and SMF investments, LLC (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on January 5, 2016). |
10.7 | Debenture Conversion Agreement, dated as of December 29, 2015, among Lilis Energy, Inc., T.R. Winston & Company, acting as placement agent, and each Debenture holder (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on January 5, 2016). |
10.8 | |
10.9 | |
10.10 | |
10.11 | |
10.12 | Convertible Subordinated Promissory Note Conversion Agreement, dated as of June 23, 2016, among Lilis Energy, Inc. and the parties signatory thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 28, 2016). |
10.13 | First Amendment to the Convertible Subordinated Promissory Notes, dated as of August 3, 2016, among Lilis Energy, Inc. and the parties signatory thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 5, 2016). |
10.14† | Employment Agreement with Michael Pawelek, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 8, 2016). |
10.15† | Employment Agreement with Edward Shaw, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on July 8, 2016). |
10.16† | Employment Agreement with Abraham Mirman, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on July 8, 2016). |
10.17† | Employment Agreement with Kevin Nanke, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on July 8, 2016). |
10.18† | Employment Agreement with Ariella Fuchs, dated as of July 5, 2016 (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on July 8, 2016). |
10.19† | |
10.20 | Transaction Fee Agreement, dated as of June 6, 2016, between Lilis Energy, Inc. and T.R. Winston & Company, LLC (incorporated herein by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 filed on August 25, 2016). |
10.21 | First Amendment to Transaction Fee Agreement, dated as of June 8, 2016, between Lilis Energy, Inc. and T.R. Winston & Company, LLC (incorporated herein by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 filed on August 25, 2016). |
10.22 | Escrow Deposit Agreement, dated as of May 26, 2016, by and among Lilis Energy, Inc., T.R. Winston & Company, LLC and Signature Bank (incorporated herein by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016 filed on August 25, 2016). |
10.23 | |
10.24 | |
10.25 | Credit and Guarantee Agreement, dated as of September 29, 2016 by and among Lilis Energy, Inc., Brushy Resources, Inc., ImPetro Operating, LLC, ImPetro Resources, LLC, the Lenders party thereto and T.R. Winston & Company, LLC acting as collateral agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed on October 26, 2016). |
10.26† | Employment Agreement with Joseph C. Daches, dated as of January 23, 2017 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 25, 2017). |
10.27†
| Employment Agreement with Brennan Short, dated as of January 27, 2017 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 31, 2017). |
10.28†* | Employment Agreement with Seth Blackwell, dated as of December 1, 2016. |
10.29† | Separation and Release Agreement, dated February 13, 2017, between Kevin Nanke and Lilis Energy, Inc. (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 17, 2017). |
10.30 | |
10.31 | |
21.1* | |
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| Second Amended and Restated Senior Secured Revolving Credit Agreement dated as of October 10, 2018, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 16, 2018). |
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| Amendment No. 6 to Credit Agreement and Amendment No. 1 to Pledge and Security Agreement dated as of October 10, 2018, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc., party thereto as guarantors, Wilmington Trust, National Association, as administrative agent, Varde Partners, Inc., as lead lender, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on October 16, 2018). |
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| First Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of March 1, 2019, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, Wilmington Trust, National Association, as administrative agent, Värde Partners, Inc., as lead lender, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.41 to the Company’s Annual Report on Form 10-K filed on March 7, 2019). |
| Transaction Agreement, dated as of March 5, 2019, by and among Lilis Energy, Inc., the Värde Fund Vi-A, L.P., Värde Investment Partners, L.P., the Värde Fund Xi (Master), L.P., Värde Investment Partners (Offshore) Master, L.P., the Värde Skyway Fund, L.P., the Värde Skyway Mini-Master Fund, L.P. and the Värde Fund Xii (Master), L.P. (incorporated herein by reference to Exhibit 10.42 to the Company’s Annual Report on Form 10-K filed on March 7, 2019). |
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| Second Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of May 6, 2019, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto. (incorporated herein by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q filed on May 9, 2019). |
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| Third Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of July 26, 2019, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 1, 2019). |
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| Fourth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of November 5, 2019, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q filed on November 7, 2019). |
| Fifth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of November 27, 2019, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 27, 2019). |
| Sixth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of December 16, 2019, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on December 17, 2019). |
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| Seventh Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of January 17,2020, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 21, 2020). |
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| Eighth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of January 23,2020, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 24, 2020). |
| Ninth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of February 6, 2020, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 6, 2020). |
| Tenth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of February 14, 2020, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 14, 2020). |
| Eleventh Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of March 13, 2020, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 16, 2020). |
| Twelfth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of March 30,2020, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 30, 2020). |
| Thirteenth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of April 14,2020, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto. (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 14, 2020). |
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| Fourteenth Amendment and Waiver to Second Amended and Restated Credit Agreement dated as of April 21,2020, among Lilis Energy, Inc., the subsidiaries of Lilis Energy, Inc. party thereto as guarantors, BMO Harris Bank, N.A., as administrative agent for the Lenders, and the other lenders party thereto. (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 21, 2020). |
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31.2* | Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 2002. |
32.1* | |
32.2* | Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002 |
99.1* | |
| 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 |
| † | Indicates management contract or compensatory plan. |
| + | To be filed by amendment. |
c) Financial Statement Schedules
Not applicable.
Item 16. Form 10-K Summary
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | |
| LILIS ENERGY, INC. |
| | |
Date: April 30, 2020
| By: | /s/ Joseph C. Daches |
| | Joseph C. Daches |
| | Chief Executive Officer, President, and Chief Financial Officer |
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.
|
| | | | |
| Signature | | Title | | Date |
| | | | |
| /s/ Joseph C. Daches | | Chief Executive Officer, President, and Chief Financial Officer | | April 30, 2020 |
| Joseph C. Daches | | (Principal Executive Officer and Principal Financial and Accounting Officer) | | |
| | | | |
| /s/ Nuno Brandolini | | Director | | April 30, 2020 |
| Nuno Brandolini | | | | |
| | | | |
| /s/ John Johanning | | Director | | April 30, 2020 |
| John Johanning | | | | |
| | | | |
| /s/ Markus Specks | | Director | | April 30, 2020 |
| Markus Specks | | | | |
| | | | |
| /s/ Michael G. Long | | Director | | April 30, 2020 |
| Michael G. Long | | | | |
| | | | |
| /s/ Nicholas Steinsberger | | Director | | April 30, 2020 |
| Nicholas Steinsberger | | | | |
| | | | |
| | | | |
| | | | |
Index to Financial Statements
Report of Independent Registered Public Accounting Firm
To the Audit Committee of the
Shareholders and Board of Directors
and Shareholdersof
Lilis Energy, Inc.
and SubsidiariesFort Worth, Texas
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Lilis Energy, Inc. and Subsidiaries (the “Company”) as of December 31, 20162019 and 2015, and2018, the related consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for each of the two years then ended.in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
Going Concern Uncertainty
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has incurred significant losses, negative cash flows from operations, and working capital deficiencies. Additionally, the Company has significant borrowing base deficiency payments due under its revolving credit agreement and does not anticipate maintaining compliance with the debt covenants contained in its revolving credit agreement during 2020, which may accelerate the Company’s debt obligations. These matters raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on
thesethe Company’s consolidated financial statements based on our audits.
We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).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.misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included considerationAs part of our audits we are required to obtain an understanding of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes
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
supportingregarding the amounts and disclosures in the
consolidated financial
statements, assessingstatements. 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
statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
In our opinion,
/s/ BDO USA, LLP
We have served as the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Company’s auditor since 2017.
Dallas, Texas
April 30, 2020
Lilis Energy, Inc. and Subsidiaries
as of December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America./s/ Marcum LLP
Marcum LLP
New York, NY
March 3, 2017
Lilis Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(In thousands, except share and per share data)
| | | December 31, | |
| | | 2016 | | | 2015 | |
| ASSETS | | | | | | | | |
| Current assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 11,738 | | | $ | 110 | |
| Accounts receivables, net of allowance of $106 and $80, respectively | | | 2,247 | | | | 952 | |
| Prepaid expenses and other current assets | | | 767 | | | | 79 | |
| Total current assets | | | 14,752 | | | | 1,141 | |
| Oil and gas properties, full cost method of accounting | | | | | | | | |
| Unproved | | | 24,461 | | | | - | |
| Proved | | | 69,809 | | | | 50,096 | |
| Less: accumulated depreciation, depletion, amortization and impairment | | | (55,771 | ) | | | (49,573 | ) |
| Total oil and gas properties, net | | | 38,499 | | | | 523 | |
| | | | | | | | | |
| Other property and equipment, net | | | 52 | | | | 44 | |
| Other assets | | | 216 | | | | 2,000 | |
| Total other assets | | | 268 | | | | 2,044 | |
| | | | | | | | | |
| Total assets | | $ | 53,519 | | | $ | 3,708 | |
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| ASSETS | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 3,753 |
| | $ | 21,137 |
|
| Accounts receivable, net of allowance of $448 and $25, respectively | 18,146 |
| | 20,546 |
|
| Derivative instruments | 427 |
| | 2,551 |
|
| Prepaid expenses and other current assets | 4,438 |
| | 1,851 |
|
| Total current assets | 26,764 |
| | 46,085 |
|
| Property and equipment: | | | |
| Oil and natural gas properties, full cost method of accounting, net | 228,855 |
| | 430,379 |
|
| Other property and equipment, net | 421 |
| | 524 |
|
| Total property and equipment, net | 229,276 |
| | 430,903 |
|
| Right-of-use assets | 1,722 |
| | — |
|
| Other assets | 837 |
| | 3,785 |
|
| Total assets | $ | 258,599 |
| | $ | 480,773 |
|
| LIABILITIES, MEZZANINE EQUITY AND STOCKHOLDERS’ EQUITY (DEFICIT) | | | |
| Current liabilities: | | | |
| Current portion of long-term debt | $ | 115,000 |
| | $ | — |
|
| Accounts payable | 24,834 |
| | 47,112 |
|
| Accrued liabilities and other | 13,972 |
| | 14,794 |
|
| Revenue payable | 11,442 |
| | 14,546 |
|
| Derivative instruments | 5,044 |
| | 515 |
|
| Total current liabilities | 170,292 |
| | 76,967 |
|
| Asset retirement obligations | 3,423 |
| | 2,433 |
|
| Long-term debt | — |
| | 157,804 |
|
| Long-term derivative instruments and other non-current liabilities | 3,762 |
| | 4,699 |
|
| Long-term deferred revenue and other long-term liabilities | 73,749 |
| | 52,513 |
|
| Total liabilities | 251,226 |
| | 294,416 |
|
| Commitments and Contingencies - Note 21 |
|
| |
|
|
| Mezzanine equity: | | | |
| 10,000,000 shares of preferred stock authorized | | | |
| Series C-1 9.75% Participating Preferred Stock, 100,000 shares issued and outstanding with a stated value of $1,203 and $1,093, per share, as of December 31, 2019 and 2018, respectively | 80,446 |
| | 106,774 |
|
| Series C-2 9.75% Participating Preferred Stock, 25,000 shares issued and outstanding with a stated value of $1,128 and $1,024, per share, as of December 31, 2019 and 2018, respectively | 18,857 |
| | 25,522 |
|
| Series D 8.25% Participating Preferred Stock, 39,254 shares issued and outstanding with a stated value of $1,107 and $1,021, per share, as of December 31, 2019 and 2018, respectively | 29,082 |
| | 40,729 |
|
| Series E 8.25% Convertible Participating Preferred Stock, 60,000 shares issued and outstanding with a stated value of $1,069, per share, as of December 31, 2019 | 66,285 |
| | — |
|
| Series F 9.00% Participating Preferred Stock, 55,000 shares issued and outstanding with a stated value of $1,076, per share, as of December 31, 2019 | 50,861 |
| | — |
|
|
| | | | | | | |
| Stockholders’ equity (deficit): | | | |
| Common stock, $0.0001 par value per share, 150,000,000 shares authorized 91,584,460 and 71,182,016 issued and outstanding as of December 31, 2019 and December 31, 2018, respectively | 9 |
| | 7 |
|
| Additional paid-in capital | 342,382 |
| | 321,753 |
|
| Treasury stock, 253,598 shares at cost | (997 | ) | | (997 | ) |
| Accumulated deficit | (579,552 | ) | | (307,431 | ) |
| Total stockholders’ equity (deficit) | (238,158 | ) | | 13,332 |
|
| Total liabilities, mezzanine equity and stockholders’ equity (deficit) | $ | 258,599 |
| | $ | 480,773 |
|
The accompanying notes are an integral part of these consolidated financial statements.
Lilis Energy, Inc. and Subsidiaries
Consolidated
Balance SheetStatements of Operations
(In thousands, except share and per share data)
| | | December 31, | |
| | | 2016 | | | 2015 | |
| | | | | | | |
| LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY | | | | | | | | |
| Current liabilities: | | | | | | | | |
| Accounts payable | | $ | 5,166 | | | $ | 1,331 | |
| Accrued liabilities | | | 2,706 | | | | 3,496 | |
| Dividends payable | | | 808 | | | | 719 | |
| Asset retirement obligations | | | 338 | | | | - | |
| Current portion of long-term debt | | | 17 | | | | 11,067 | |
| Total current liabilities | | | 9,035 | | | | 16,613 | |
| Asset retirement obligations | | | 919 | | | | 209 | |
| Long-term debt | | | 30,226 | | | | - | |
| Long-term derivative liabilities | | | 1,400 | | | | 56 | |
| Total liabilities | | | 41,580 | | | | 16,878 | |
| | | | | | | | | |
| Commitments and contingencies (Note 9) | | | | | | | | |
| Conditionally redeemable 6% preferred stock, $0.0001 par value, 7,000 shares authorized, 2,000 shares issued and outstanding with a liquidation preference of $2,240 at December 31, 2016. | | | 1,874 | | | | 1,173 | |
| | | | | | | | | |
| Stockholders’ Equity (Deficit): | | | | | | | | |
| Series A Preferred stock, $0.0001 par value; stated rate $1,000:10,000 shares authorized, 0 and 7,500 shares issued and outstanding as of December 31, 2016 and 2015, respectively. | | | - | | | | 6,794 | |
| Series B Preferred stock, $0.0001 par value; stated rate $1,000: 20,000 shares authorized; 17,000 and 0 shares issued and outstanding at December 31, 2016 and 2015, respectively, with a liquidation preference of $20,627 at December 31, 2016. | | | 13,432 | | | | - | |
| Common stock, $0.0001 par value per share; 100,000,000 shares authorized, 20,918,901 and 2,786,275 shares issued and outstanding as of December 31, 2016 and 2015, respectively. | | | 2 | | | | - | |
| Additional paid-in capital | | | 219,837 | | | | 159,773 | |
| Accumulated deficit | | | (223,206 | ) | | | (180,910 | ) |
| Total stockholders’ equity (deficit) | | | 10,065 | | | | (14,343 | ) |
| | | | | | | | | |
| Total liabilities, redeemable preferred stock and stockholders’ equity | | $ | 53,519 | | | $ | 3,708 | |
The accompanying notes are an integral part of these consolidated financial statements
Lilis Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
(In thousands, except share and per share data)
| | | Years Ended December 31, | |
| | | 2016 | | | 2015 | |
| | | | | | | |
| Oil, natural gas and natural gas liquid sales | | $ | 3,435 | | | $ | 396 | |
| | | | | | | | | |
| Costs and expenses: | | | | | | | | |
| Production costs | | | 1,247 | | | | 195 | |
| Production taxes | | | (167 | ) | | | 28 | |
| General and administrative | | | 14,570 | | | | 7,930 | |
| Depreciation, depletion and amortization | | | 1,566 | | | | 574 | |
| Accretion of asset retirement obligations | | | 132 | | | | 10 | |
| Impairment of evaluated oil and gas properties | | | 4,718 | | | | 24,478 | |
| Total operating expenses | | | 22,066 | | | | 33,215 | |
| | | | | | | | | |
| Loss from operations | | | (18,631 | ) | | | (32,819 | ) |
| | | | | | | | | |
| Other income (expenses): | | | | | | | | |
| Other income | | | 90 | | | | 3 | |
| Debt conversion inducement expense | | | (8,307 | ) | | | - | |
| Gain on extinguishment of debt | | | 250 | | | | - | |
| Gain (loss) in fair value of derivative instruments | | | (1,222 | ) | | | 1,638 | |
| Gain (loss) in fair value of conditionally redeemable 6% preferred stock | | | (701 | ) | | | 514 | |
| Gain on modification of convertible debts | | | 602 | | | | - | |
| Interest expense | | | (4,924 | ) | | | (1,697 | ) |
| Total other income (expenses) | | | (14,212 | ) | | | 458 | |
| | | | | | | | | |
| Net loss | | | (32,843 | ) | | | (32,361 | ) |
| Dividends on redeemable preferred stock | | | (407 | ) | | | (120 | ) |
| Loss on extinguishment of Series A Convertible Preferred Stock | | | (540 | ) | | | - | |
| Dividend and deemed dividend Series B Convertible Preferred stock | | | (8,506 | ) | | | (600 | ) |
| Net loss attributable to common stockholders | | $ | (42,296 | ) | | $ | (33,081 | ) |
| | | | | | | | | |
| Net loss per common share basic and diluted | | $ | (3.73 | ) | | $ | (12.13 | ) |
| Weighted average common shares outstanding: | | | | | | | | |
| Basic and diluted | | | 11,328,252 | | | | 2,726,775 | |
|
| | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| Revenues: | | | |
| Oil sales | $ | 59,015 |
| | $ | 58,042 |
|
| Natural gas sales | 3,180 |
| | 5,246 |
|
| Natural gas liquid sales | 3,868 |
| | 6,928 |
|
| Total revenues | 66,063 |
| | 70,216 |
|
| Operating expenses: | | | |
| Production costs | 16,127 |
| | 13,843 |
|
| Gathering, processing and transportation | 3,960 |
| | 3,392 |
|
| Production taxes | 3,302 |
| | 3,709 |
|
| General and administrative | 28,371 |
| | 33,251 |
|
| Depreciation, depletion, amortization and accretion | 33,252 |
| | 25,367 |
|
| Impairment of oil and natural gas properties | 228,324 |
| | — |
|
| Total operating expenses | 313,336 |
| | 79,562 |
|
| Operating loss | (247,273 | ) | | (9,346 | ) |
| Other income (expense): | | | |
| Loss on early extinguishment of debt | (1,299 | ) | | (20,370 | ) |
| Gain (loss) from commodity derivatives | (8,985 | ) | | 55 |
|
| Change in fair value of financial instruments | (3,573 | ) | | 58,343 |
|
| Interest expense | (11,426 | ) | | (32,827 | ) |
| Other income | 435 |
| | 2 |
|
| Total other income (expense) | (24,848 | ) | | 5,203 |
|
| Net loss before income taxes | (272,121 | ) | | (4,143 | ) |
| Income tax expense | — |
| | — |
|
| Net loss | (272,121 | ) | | (4,143 | ) |
| Paid-in-kind dividends on preferred stock | (25,397 | ) | | (10,687 | ) |
| Net loss attributable to common stockholders | $ | (297,518 | ) | | $ | (14,830 | ) |
| | | | |
| Net loss per common share-basic and diluted: (Note 18) | | | |
| Basic | $ | (3.38 | ) | | $ | (0.24 | ) |
| Diluted | $ | (3.38 | ) | | $ | (0.47 | ) |
| | | | |
| Weighted average common shares outstanding: | | | |
| Basic | 87,912,362 |
| | 62,854,214 |
|
| Diluted | 87,912,362 |
| | 78,451,341 |
|
The accompanying notes are an integral part of these consolidated financial statements.
Lilis Energy, Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders’ Equity (Deficit)
(In thousands, except share
and per share data)
| | | Series A Preferred | | | Series B Preferred | | | | | | | | | Additional | | | | | | | |
| | | Shares | | | Shares | | | Common Shares | | | Paid In | | | Accumulated | | | | |
| | | Shares | | | Amount | | | Shares | | | Amount | | | Shares | | | Amount | | | Capital | | | Deficit | | | Total | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance, January 1, 2015 | | | 7,500 | | | $ | 6,794 | | | | - | | | $ | - | | | | 2,699,273 | | | $ | - | | | $ | 155,101 | | | $ | (147,829 | ) | | $ | 14,066 | |
| Issuances of common stock | | | - | | | | - | | | | - | | | | - | | | | 87,002 | | | | - | | | | 365 | | | | - | | | | 365 | |
| Fair value of warrants issued for professional services | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 425 | | | | - | | | | 425 | |
| Fair value of warrants issued for bridge term loan | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 1,222 | | | | - | | | | 1,222 | |
| Stock based compensation | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 2,660 | | | | - | | | | 2,660 | |
| Dividend Preferred stockholders | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (120 | ) | | | (120 | ) |
| Deemed dividend Series A Convertible Preferred Stock | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (600 | ) | | | (600 | ) |
| Net loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (32,361 | ) | | | (32,361 | ) |
| Balance, December 31, 2015 | | | 7,500 | | | | 6,794 | | | | - | | | | - | | | | 2,786,275 | | | | - | | | | 159,773 | | | | (180,910 | ) | | | (14,343 | ) |
| Stock based compensation | | | - | | | | - | | | | - | | | | - | | | | 711,667 | | | | - | | | | 7,078 | | | | - | | | | 7,078 | |
| Exercise of warrants | | | - | | | | - | | | | - | | | | - | | | | 420,707 | | | | - | | | | 187 | | | | - | | | | 187 | |
| Fair value of warrants issued for financing costs | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 713 | | | | - | | | | 713 | |
| Issuance and repricing of warrants to induce conversion | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 8,307 | | | | - | | | | 8,307 | |
| Gain on modification of convertible debentures | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (602 | ) | | | - | | | | (602 | ) |
| Fair value of warrants issued for debt discount | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 1,479 | | | | - | | | | 1,479 | |
| Common stock issued for conversion of convertible notes and | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| accrued interest | | | - | | | | - | | | | - | | | | - | | | | 6,778,115 | | | | 1 | | | | 14,871 | | | | - | | | | 14,872 | |
| Common stock and warrants issued in connection with the | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Brushy merger | | | - | | | | - | | | | - | | | | - | | | | 5,785,119 | | | | - | | | | 7,111 | | | | - | | | | 7,111 | |
| Series B Preferred stock issued for cash, net of fees | | | - | | | | - | | | | 20,000 | | | | 18,195 | | | | - | | | | - | | | | - | | | | - | | | | 18,195 | |
| Warrants issued for Series B Preferred Stock offering fees | | | - | | | | - | | | | - | | | | (1,590 | ) | | | - | | | | - | | | | 1,590 | | | | - | | | | - | |
| Common stock issued for conversion of Series A Preferred | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Stock and accrued dividends | | | (7,500 | ) | | | (6,794 | ) | | | - | | | | - | | | | 1,500,000 | | | | 1 | | | | 7,681 | | | | - | | | | 888 | |
| Loss on extinguishment of Series A Preferred Stock | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 540 | | | | (540 | ) | | | - | |
| Common stock issued for conversion of Series B Preferred | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Stock and accrued dividends | | | - | | | | - | | | | (3,000 | ) | | | (3,173 | ) | | | 2,937,018 | | | | - | | | | 3,230 | | | | - | | | | 57 | |
| Dividends and deemed dividends for Preferred Stock | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 7,879 | | | | (8,913 | ) | | | (1,034 | ) |
| Net Loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (32,843 | ) | | | (32,843 | ) |
| Balance, December 31, 2016 | | | - | | | $ | - | | | | 17,000 | | | $ | 13,432 | | | | 20,918,901 | | | $ | 2 | | | $ | 219,837 | | | $ | (223,206 | ) | | $ | 10,065 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Shares | | Additional
Paid-In Capital | | Treasury Shares | | Accumulated Deficit | | Total |
| | Shares | | Amount | | | Shares | | Amount | | |
| Balance, January 1, 2018 | 53,368,331 |
| | $ | 5 |
| | $ | 272,335 |
| | — |
| | $ | — |
| | $ | (303,288 | ) | | $ | (30,948 | ) |
| Stock-based compensation | — |
| | — |
| | 9,000 |
| | — |
| | — |
| | — |
| | 9,000 |
|
| Common stock for restricted stock | 404,093 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Common stock withheld for taxes on stock-based compensation | (484,727 | ) | | — |
| | (2,230 | ) | | — |
| | — |
| | — |
| | (2,230 | ) |
| Common stock for acquisition of oil and natural gas properties | 6,940,722 |
| | 1 |
| | 24,777 |
| | — |
| | — |
| | — |
| | 24,778 |
|
| Exercise of warrants and stock options | 5,000,834 |
| | — |
| | 3,751 |
| | — |
| | — |
| | — |
| | 3,751 |
|
| Common stock issued for extinguishment of debt | 5,952,763 |
| | 1 |
| | 24,584 |
| | — |
| | — |
| | — |
| | 24,585 |
|
| Reclassification of warrant derivative liabilities | — |
| | — |
| | 223 |
| | — |
| | — |
| | — |
| | 223 |
|
| Purchase of treasury stock | — |
| | — |
| | — |
| | (253,598 | ) | | (997 | ) | | — |
| | (997 | ) |
| Dividends on preferred stock | — |
| | — |
| | (10,687 | ) | | — |
| | — |
| | — |
| | (10,687 | ) |
| Net loss | — |
| | — |
| | — |
| | — |
| | — |
| | (4,143 | ) | | (4,143 | ) |
| Balance, December 31, 2018 | 71,182,016 |
| | $ | 7 |
| | $ | 321,753 |
| | (253,598 | ) | | $ | (997 | ) | | $ | (307,431 | ) | | $ | 13,332 |
|
| Stock-based compensation | — |
| | — |
| | 6,506 |
| | — |
| | — |
| | — |
| | 6,506 |
|
| Common stock for restricted stock | 3,178,448 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Common stock withheld for taxes on stock-based compensation | (417,642 | ) | | — |
| | (546 | ) | | — |
| | — |
| | — |
| | (546 | ) |
| Common stock issued for extinguishment of debt | 17,641,638 |
| | 2 |
| | 32,988 |
| | — |
| | — |
| | — |
| | 32,990 |
|
| Gain on extinguishment of debt | — |
| | — |
| | 7,078 |
| | — |
| | — |
| | — |
| | 7,078 |
|
| Dividends on preferred stock | — |
| | — |
| | (25,397 | ) | | — |
| | — |
| | — |
| | (25,397 | ) |
| Net loss | — |
| | — |
| | — |
| | — |
| | — |
| | (272,121 | ) | | (272,121 | ) |
| Balance, December 31, 2019 | 91,584,460 |
| | $ | 9 |
| | $ | 342,382 |
| | (253,598 | ) | | $ | (997 | ) | | $ | (579,552 | ) | | $ | (238,158 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
Lilis Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(In thousands)
| | | Years Ended December 31, | |
| | | 2016 | | | 2015 | |
| Cash flows from operating activities: | | | | | | | | |
| Net loss | | $ | (32,843 | ) | | $ | (32,361 | ) |
| Adjustments to reconcile net loss to net cash used in operating activities: | | | | | | | | |
| Equity instruments issued for services and compensation | | | 7,078 | | | | 3,450 | |
| Bad debt expense | | | 494 | | | | - | |
| Inducement Expense | | | 8,307 | | | | - | |
| Amortization of deferred financing cost | | | 328 | | | | 52 | |
| Accretion of debt discount | | | 2,857 | | | | - | |
| Gain on extinguishment of debt | | | (250 | ) | | | - | |
| Gain (loss) in fair value of derivative instruments | | | 1,222 | | | | (1,604 | ) |
| Gain (loss) in fair value of conditionally redeemable 6% preferred stock | | | 701 | | | | (514 | ) |
| Gain on modification of convertible debt | | | (602 | ) | | | - | |
| Depreciation, depletion, amortization and accretion of asset retirement obligation | | | 1,698 | | | | 584 | |
| Impairment of evaluated oil and gas properties | | | 4,718 | | | | 24,478 | |
| Changes in operating assets and liabilities: | | | | | | | | |
| Accounts receivable | | | (1,264 | ) | | | (120 | ) |
| Other assets | | | 1,554 | | | | 57 | |
| Accounts payable, accrued expenses and other liabilities | | | (307 | ) | | | 2,027 | |
| Net cash used in operating activities | | | (6,309 | ) | | | (3,951 | ) |
| | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | |
| Cash advance to Brushy Resources, Inc. | | | - | | | | (1,750 | ) |
| Cash consideration for Brushy merger, net of cash acquired | | | (2,302 | ) | | | - | |
| Restricted cash | | | - | | | | 145 | |
| Capital expenditures | | | (16,828 | ) | | | (98 | ) |
| Net cash used in investing activities | | | (19,130 | ) | | | (1,703 | ) |
| | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | |
| Net proceeds from issuance of Series B Preferred Stock | | | 18,195 | | | | - | |
| Proceeds from bridge notes, net | | | 2,863 | | | | 5,950 | |
| Proceeds from warrant exercise | | | 187 | | | | - | |
| Dividend payments on preferred stock | | | - | | | | (180 | ) |
| Debt issuance costs | | | (1,299 | ) | | | (266 | ) |
| Proceeds from issuance of term loan | | | 31,000 | | | | - | |
| Repayment of debt | | | (13,879 | ) | | | (250 | ) |
| Net cash provided by financing activities | | | 37,067 | | | | 5,254 | |
| Increase (decrease) in cash | | | 11,628 | | | | (400 | ) |
| Cash at beginning of period | | | 110 | | | | 510 | |
| Cash at end of period | | $ | 11,738 | | | $ | 110 | |
| Supplemental disclosure: | | | | | | | | |
| Cash paid for interest | | $ | 762 | | | $ | 365 | |
|
| | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| Cash flows from operating activities: | | | |
| Net loss | $ | (272,121 | ) | | $ | (4,143 | ) |
| Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | | | |
| Stock-based compensation | 6,506 |
| | 9,000 |
|
| Bad debt recovery | 422 |
| | 106 |
|
| Amortization of debt issuance cost and accretion of debt discount | 2,460 |
| | 15,656 |
|
| Payable in-kind interest | 1,590 |
| | 12,213 |
|
| Loss on early extinguishment of debt | 1,299 |
| | 20,370 |
|
| Loss (gain) from commodity derivatives, net | 8,985 |
| | (55 | ) |
| Net settlements paid on commodity derivatives | (3,214 | ) | | (2,742 | ) |
| Change in fair value of financial instruments | 3,573 |
| | (58,343 | ) |
| Deferred revenue realized | (232 | ) | | — |
|
| Impairment of oil and natural gas properties | 228,324 |
| | — |
|
| Depreciation, depletion, amortization and accretion | 33,252 |
| | 25,367 |
|
| Operating lease ROU amortization | (453 | ) | | — |
|
| Changes in operating assets and liabilities: | | | |
| Accounts receivable | (6,378 | ) | | (13,226 | ) |
| Prepaid expenses and other assets | (944 | ) | | (473 | ) |
| Accounts payable and accrued liabilities | (31,393 | ) | | 53,402 |
|
| Proceeds from options associated with future midstream services | 2,500 |
| | 35,000 |
|
| Net cash (used in) provided by operating activities | (25,824 | ) | | 92,132 |
|
| Cash flows from investing activities: | | | |
| Acquisition of oil and natural gas properties | — |
| | (92,410 | ) |
| Proceeds from the sale of assets | 16,851 |
| | 17,500 |
|
| Capital expenditures | (82,378 | ) | | (168,025 | ) |
| Net cash used in investing activities | (65,527 | ) | | (242,935 | ) |
| Cash flows from financing activities: | | | |
| Proceeds from term loans, net of financing costs | — |
| | 47,806 |
|
| Proceeds from revolving credit agreement, net of financing costs | 56,883 |
| | 72,566 |
|
| Repayment of term loans and notes payable | — |
| | (88,836 | ) |
| Repayment of revolving credit agreement | (18,000 | ) | | — |
|
| Proceeds from the issuance of Series C Preferred Stock | — |
| | 122,418 |
|
| Proceeds from the Värde financing arrangement, net of transaction costs | 38,230 |
| | — |
|
| Partial repayment of the Värde financing arrangement | (2,600 | ) | | — |
|
| Repurchase of common stock | — |
| | (997 | ) |
| Proceeds from exercise of warrants and stock options | — |
| | 3,751 |
|
| Payment for tax withholding on stock-based compensation | (546 | ) | | (2,230 | ) |
| Net cash provided by financing activities | 73,967 |
| | 154,478 |
|
| Net increase (decrease) in cash and cash equivalents | (17,384 | ) | | 3,675 |
|
| Cash and cash equivalents at beginning of period | 21,137 |
| | 17,462 |
|
| Cash and cash equivalents at end of period | $ | 3,753 |
| | $ | 21,137 |
|
| Supplemental disclosure: | | | |
| Cash paid for interest | $ | 6,488 |
| | $ | 4,958 |
|
The accompanying notes are an integral part of these consolidated financial statements.
Lilis Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
NOTE 1 –- ORGANIZATIONOn September 21, 2007, Universal Holdings, Inc. (“Universal”), a Nevada corporation, completed the acquisition of Coronado Acquisitions, LLC (“Coronado”). Under the terms of the acquisition, Coronado was merged into Universal. On October 12, 2009, Universal changed its name to Recovery Energy, Inc. On December 1, 2013, Recovery Energy, Inc. changed its name to
Lilis Energy, Inc. (“Lilis”
, “Lilis Energy” and or the “Company”)
.The Company is an independent oil and natural gas exploration and production company focused on the Delaware Basin in Winkler, Loving, and LovingReeves Counties, Texas and Lea County, New MexicoMexico.
NOTE 2 - LIQUIDITY AND GOING CONCERN
These consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the
Denver-Julesburg Basin (“DJ Basin”)satisfaction of liabilities and other commitments in
Wyoming, Colorado, and Nebraska.On June 23, 2016, the Company effected a 1-for-10 reverse stock splitnormal course of its Common Stock (the “Reverse Split”). Thebusiness for the twelve-month period following the date of issuance of these consolidated financial statements. As such, the accompanying consolidated financial statements and these notesdo not include any adjustments relating to the consolidated financial statements give retroactive effect torecoverability and classification of assets and their carrying amount, or the Reverse Split for all periods presented.
All references to production, sales volumesamount and reserves quantities are net to the Company’s interest unless otherwise indicated.
NOTE 2 – MANAGEMENT PLANS AND LIQUIDITY
The Company has reported net operating losses during the year ended December 31, 2016 and for the past five years. As aclassification of liabilities that may result should the Company funded its operations in 2016 and the merger with Brushy Resources, Inc. through additional debt and equity financing. On September 29, 2016, the Company entered intobe unable to continue as a new Credit and Guaranty Agreement (the “Credit Agreement”) that provides for a three-year, senior, secured term loan with initial aggregate principal commitments of $31 million and a maximum facility size of $50 million. The term loan was funded in two draws, with $25 million collected as of September 30, 2016 and the additional $6 million collected as of November 11, 2016.
going concern.
As of December 31, 2016,2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt), with $115.0 million of indebtedness outstanding under our Revolving Credit Agreement. As provided for in the Seventh Amendment to our Revolving Credit Agreement and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million.
As a result of the January 17, 2020 redetermination of the borrowing base, a borrowing base deficiency in the amount of $25.0 million (the “Borrowing Base Deficiency”) was created under the Revolving Credit Agreement. The Borrowing Base Deficiency constitutes the difference between the principal amount of borrowings currently outstanding under the Revolving Credit Agreement ($115.0 million) and the borrowing base as so redetermined ($90.0 million). On February 28, 2020, we paid $17.3 million towards the Borrowing Base Deficiency. Pursuant to the Fourteenth Amendment to the Revolving Credit Agreement, the remaining payment of $7.8 million is due June 5, 2020.
The Company is seeking additional funding and considering certain strategic transactions to enable it to pay the remaining Borrowing Base Deficiency amount of $7.8 million. Unless funding or additional transactions are completed, the Company hadwill not be able to pay the remaining Borrowing Base Deficiency. There is no assurance that such transactions will occur or that the bank group will agree to further deficiency payment extensions. If the Company is unable to repay the remaining borrowing base deficiency as and when required under the Revolving Credit Agreement, an event of default would occur under the Revolving Credit Agreement.
Our next borrowing base redetermination is scheduled to occur on or about June 5, 2020. If the borrowing base is further reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination.
We have experienced losses and negative cash flows from operations and working capital balancedeficiencies. Additionally, our liquidity and operating forecasts have been negatively impacted by the recent decrease in commodity prices, which impacts our ability to comply with debt covenants under our Revolving Credit Agreement. The commodity prices have fallen significantly since the beginning of 2020, due in part to failed OPEC negotiations as well as concerns about the COVID-19 pandemic, which has significantly decreased worldwide demand for oil and natural gas. Our Revolving Credit Agreement contains financial covenants that require the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a cash balanceratio of approximately $5.7 millionCurrent Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter thereafter. See Note 11-Long-term Debt for additional information regarding the financial covenants under our Revolving Credit Agreement. As of December 31, 2019, the Company was not in compliance with the Leverage Ratio and $11.7 million, respectively. Current Ratio covenants under the Revolving Credit Agreement. Pursuant to the Twelfth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants, among other waivers of default, as of December 31, 2019.
As of March 1, 2017,31, 2020, the Company’s cash balanceCompany was approximately $9.0not in compliance with the Leverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as of March 31, 2020. If we are not able to pay or defer the $7.8 million which included a drawdownBorrowing Base Deficiency due on June 5, 2020 or do not maintain compliance with our debt covenants, the
obligations of additional principalthe Company under itsthe Revolving Credit Agreement may be accelerated, which would have a material adverse effect on February 7, 2017our business. The Company does not expect to be in compliance with debt covenants in future periods without additional sources of $7.1 millionliquidity or future amendments to the Revolving Credit Agreement.
Fluctuations in oil and excluded net proceedsnatural gas prices have a material impact on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. Historically, oil and natural gas prices have been volatile, and may be subject to wide fluctuations in the future. If continued depressed prices persist, the Company will continue to experience operating losses, negative cash flows from operating activities, and negative working capital.
In order to improve our leverage position and current ratio to meet the financial covenants under the Revolving Credit Agreement, we are currently pursuing or considering a number of actions, which in certain cases may require the consent of current lenders and stockholders. In November 2019, our board of directors formed a committee of independent directors (the “Special Committee”) tasked with reviewing and evaluating strategic alternatives that may enhance the value of the equity offering completedCompany, including alternatives that may be available to identify and access further sources of liquidity through financing alternatives or deleveraging transactions. The Special Committee hired financial and legal advisors to advise the Special Committee on March 1, 2017,these matters.
The Special Committee continues to explore financing alternatives and deleveraging transactions. We are also addressing operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs and intend to continue to pursue and consider other strategic alternatives.
There can be no assurance that we will be able to implement any of these plans successfully, or
approximately $18.6 million.that such plans, if executed, will result in the ability to pay borrowing base deficiencies, generate sufficient liquidity to continue as a going concern or comply with our Revolving Credit Agreement covenants. The
Company believes that it will have sufficient capitalfactors discussed above raise substantial doubt about our ability to
operate over the next 12 months fromcontinue as a going concern within twelve-month period following the date of
the filingissuance of
this annual report. However, it is possible that the Company will seek to raise additional debt, equity capital, or both depending on the pace of its drilling and leasing activity.these consolidated financial statements.
NOTE 3 –- BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES
Principles of Consolidation
and Presentation
The
accompanying consolidated financial statements include the accounts of the Company and its wholly owned
subsidiaries. The Company’s wholly owned subsidiaries,
include Brushy Resources,
Inc (“Brushy”)Inc., ImPetro Operating, LLC,
(“ImPetro Operating”) and ImPetro Resources, LLC,
(“ImPetro”), and Lilis Operating Company, LLC,
(“Lilis Operating”).and Hurricane Resources LLC. All significant intercompany accounts and transactions have been eliminated in consolidation.
The
preparation ofaccompanying consolidated financial statements
are prepared in conformity with
generally accepted accounting principles in the United States (“U.S. GAAP”)GAAP which requires the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting period; and the quantities and values of proved oil, natural gas and
NGLnatural gas liquid (“NGL”) reserves used in calculating depletion and assessing impairment of its oil and
natural gas properties.
The most significant financial estimates are associated withpertain to the Company’s estimated volumesevaluation of unproved properties for impairment, proved oil and natural gas reserves asset retirement obligations, assessments of impairment imbeddedand related cash flow estimates used in the carrying valuedepletion and impairment of undeveloped acreageoil and undevelopednatural gas properties; the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool; the fair value of financial instruments, includingembedded derivatives and commodity derivative liabilities, depreciationcontracts, accrued oil and accretion, income taxesnatural gas revenues and contingencies. Although management believes that these estimates are reasonable, actualexpenses, valuation of options and warrants, and common stock; and the allocation of general and administrative expenses. Actual results could differ significantly from thosethese estimates.
Certain
prior-period amountsreclassifications have been
reclassified formade to the prior year comparative
purposesfinancial statements to conform
withto the
fiscal 20162019 presentation. These reclassifications have no effect on the Company’s previously reported results of
operations.operations, stockholders’ equity or cash flows.
Cash and Cash
EquivalentEquivalents
Cash and cash equivalents include highly liquid instruments with an original maturity of three months or less
when purchased to be cash equivalents as these instruments are
readily convertible to known amounts of cash and do not bear significant risk of changes in value due to their short maturity period.
stated at cost, which approximates fair value.
The Company
records actual and estimated oil and gas revenuehas accounts receivable from
third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest
partners.owners of properties operated by the Company. The Company typically has the right to withhold future revenue disbursements to recover
outstandingany non-payment of related joint interest
billings on outstanding receivables from joint interest owners.billings. Management
periodically reviewsroutinely assesses accounts receivable amounts
forto determine their collectability and
records itsaccrues an allowance for uncollectible receivables
using the allowance methodwhen, based on
past experience. Allowance for doubtful accounts are based primarily on joint interest billings for expenses related tothe judgment of management, it is probable that a receivable will not be collected. The Company records actual and estimated oil and natural gas
wells. Receivables which deriverevenue receivable from third parties at its net revenue interest. In addition, the Company has receivables derived from sales of certain oil and
natural gas production
which are collateral under the Company’s
Credit Agreement.Concentrationcredit agreements. The Company had an allowance for doubtful accounts of Credit Risk
The Company’s cash is invested at major financial institutions primarily within the United States. At$0.4 million as of December 31, 20162019. There was no allowance for doubtful accounts as of December 31, 2018.
Fair Value of Financial Instruments
As of December 31, 2019, and
2015,2018, the
Company’scarrying value of cash
was maintained inand cash equivalents, accounts
that are insured upreceivable, accounts payable, accrued liabilities, revenue payable and advances from joint interest partners approximates fair value due to the
limit determined by the federal governmental agency.short-term nature of such items. The
Company may at times have balances in excess of the federally insured limits. Periodically, the Company evaluates the creditworthiness of the financial institutions, and has not experienced any losses in such accounts.Significant Customers
The Company’s major customers include, Noble Energy, Texican and Energy Transfer, Inc. These customers accounted for approximately 41%, 38% and 16%carrying value of the Company’s revenue forsecured debt is carried at cost which approximates the year ended December 31, 2016. The Company’s major customers include, Shell Trading (US), PDC Energy and Noble Energy, which accounted for approximately 43%, 26% and 21% of its revenue for the year ended December 31, 2015.
However, the Company believe that the loss of a single purchaser could not materially affect the Company’s business because alternative purchasers are available.
Reserves
Allfair value of the reserves data included herein are estimates. Estimates ofdebt as the Company’s crude oil and natural gas reserves are prepared in accordance with guidelines established byrelated interest rates approximates interest rates currently available to the Securities Exchange Commission (“SEC”), including rule revisions designed to modernize the oil and gas company reserves reporting requirements, which the Company implemented effective December 31, 2010. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. In addition, the ability to produce economic reserves is dependent on the oil and gas prices used in the reserves estimate. The Company’s reserves estimates are based on 12-month average commodity prices, unless contractual arrangements otherwise designate the price to be used, in accordance with the SEC rules. However, oil and gas prices are volatile and, as a result, the Company’s reserves estimates may change in the future.
Estimates of proved crude oil and natural gas reserves significantly affect the Company’s depreciation, depletion, and amortization (“DD&A”) expense. For example, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also result in an impairment charge, which would reduce earnings.
Oil and
Natural Gas Properties
The Company uses the full cost method of accounting for oil and
natural gas operations. Under this method, costs related to the exploration, non-production related development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive
wells and/or plugging and abandoning non-productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves.
The Company accounts for its unproven long-lived assets in accordance with Accounting Standards Codification (“ASC”) Topic 360-10-05, Accounting for the Impairment or Disposal of Long-Lived Assets. ASC Topic 360-10-05 requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the historical cost carrying value of an asset may no longer be appropriate.
Depletion of exploration and development costs and depreciation of wells and tangible production assets is computed using the units-of-production method based upon estimated proved oil and
natural gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion,
and (b) estimated future development cost to be incurred in developing proved
reserves; and (c) estimated decommissioning and abandonment/restoration costs, net of estimated salvage values,reserves, that are not otherwise included in capitalized costs.
Costs associated with undeveloped acreage are excluded from the depletion base until it is determined whether proved reserves can be assigned to the properties. When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such properties is added to full cost pool which is subject to depletion calculations.
Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion and net(net of deferred income taxestaxes) may not exceed an amount equal to the sum of the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves and the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. During 2016, commodity prices continued to trade in a low range. With low commodity prices sustained for the majority of 2016 in the DJ Basin, some of the Company’s properties became uneconomic triggering an impairment charge of $4.7 million at December 31, 2016. Due to the decline in commodity prices and lack of liquidity the Company recorded an impairment charge during the year ended December 31, 2015. During the years ended December 31, 2016 and 2015, the Company recorded $4.7 million and $24.5 million impairment charges, respectively.The present value of estimated future net cash flows was computed by applying:applying a flat oil price to forecast revenues from estimated future production of proved oil and natural gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes.
For the year ended December 31, 2019, the ceiling value of the Company’s reserves was calculated based upon SEC pricing of $55.69 per barrel for oil and $2.58 per MMBtu for natural gas. For the year ended December 31, 2018, the ceiling value of the Company’s reserves was calculated based upon SEC pricing of $65.56 per barrel for oil and $3.10 per MMBtu for natural gas. Full-cost ceiling impairments totaling $228.3 million were recorded for the year ended December 31, 2019 and resulted primarily from decreased commodity prices and reduction in expected PUDs used in preparation of estimated future net revenues from proved oil and natural gas reserves as compared to the commodity prices used for the year ended December 31, 2018, when no such impairments were recognized.
The costs of unproved oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved oil and natural gas reserves are established or if impairment is determined. Unproved oil and natural gas properties are assessed periodically, at least annually, to determine whether impairment had occurred. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, the economic viability of development if proved reserves were assigned and other current market conditions. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and were then subject to amortization.
Wells in progress connotes wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produce oil and
natural gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves or abandonment, the costs for these wells are then transferred to the full cost pool and become subject to both depletion and the ceiling test calculations in accordance with full cost accounting under Rule 4-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.
Capitalized Interest
For significant oil and natural gas investments in unproved properties, and significant exploration and development projects that have not commenced production, interest is capitalized as part of the historical cost of developing and constructing assets. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. As of December 31, 2019, there were no significant exploratory projects on unproved properties and none of the development projects exceeded the interest capitalization qualifying asset limit. As a result, no interest was capitalized as of December 31, 2019 and 2018.
Other Property and Equipment
Property and equipment include
vehicles, office equipment and furniture which are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. The estimated useful lives of property and equipment range from
three4 to
seven20 years. The Company recorded approximately
$0.04$0.2 million and
$0.03$0.1 million of depreciation for the years ended December 31,
20162019 and
2015,2018, respectively.
Impairment of Long-lived Assets
The Company accounts for long-lived assets (other than oil and gas properties) at cost. The Company may impair these assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be fully recoverable. Recoverability is measured by comparing the carrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may not be recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference.
Asset Retirement Obligations
The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value. For purposes of depletion, calculations, the Company includes estimated dismantlement and abandonment cost, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability
Revenue Recognition
Revenue is
allocated to operating expense using a systematic and rational method.Fair Value of Financial Instruments
As of December 31, 2016 and 2015, the carrying value of cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, interest and dividends payable and advance from joint interest partners approximates fair value duerecognized when control passes to the short-term naturepurchaser which generally occurs when production is transferred to the purchaser. The Company measures revenue as the amount of such items. The carrying valueconsideration it expects to receive in exchange for the commodities transferred. All of the Company’s secured debtrevenues from contracts with customers represent products transferred at a point in time as control is carried at cost which is approximately the fair value of the debt as the related interest rate are at the terms approximates rates currently availabletransferred to the Company.
Revenue Recognition
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
whenin the amount that reflects the consideration it
is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidenceexpects to receive in exchange for transferring control of
an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's pricethose goods to the
buyercustomer. The contract consideration in the Company’s variable price contracts is
fixedtypically allocated to specific performance obligations in the contract according to the price stated in the contract. Payment is generally received one or
determinable and (iv) collectability is reasonably assured.two months after the sale has occurred.
Stock based Compensation
The Company
uses the entitlementsapplies a fair value method of accounting for
oil, NGLs and gas revenues. Sales proceedsstock based compensation, which requires recognition in
excessthe financial statements of the
Company's entitlement are includedcost of services received in
other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets. The Company had no material oil, NGL or gas entitlement assets or liabilities as of December 31, 2016 or 2015.Stock Based Compensation
The Company measures the fair value of stock-based compensation expense awards made to employees and directors, including stock options, restricted stock units, and restricted stock, on the date of grant using a Black-Scholes model.exchange for equity awards. For equity awards, compensation expense is based on the fair value on the grant date or modification date and is recognized in the Company’s financial statements over the vesting period. The measurementCompany utilizes the Black-Scholes Merton option-pricing model to measure the fair value of share-based compensation expense isstock options based on several criteria, including but not limited to, the valuation model used and associated input factors, such as expected term of the award, stock price volatility, risk free interest rate, dividend rate and award cancellation rate. These inputs are subjective and are determined using management’s judgment. If differences arise between the assumptions used in determining share-basedstock based compensation expense and the actual factors, which become known over time, the Company may change the input factors used in determining future share-based
stock based compensation expense.
The fair value of restricted stock awards is identified as the closing stock price on the day the award was granted. The Company recognizes forfeitures as and when the stock awards are forfeited.
The Company accounts for warrant grants to nonemployees whereby the fair values of such warrants are determined using the option pricing model at the earlier of the date at which the nonemployee’s performance is complete or a performance commitment is reached.
Warrant Modification Expense
The Company accounts for the modification of warrants as an exchange of the old award for a new award. The incremental value is measured as the excess, if any, of the fair value of the modified award over the fair value of the original award immediately before modification, and is either expensed as a period expense or amortized over the performance or vesting date. The Company estimates the incremental value of each warrant using the Black-Scholes option pricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimate with the greatest degree of subjective judgment is the estimated volatility of the Company’s stock price.
Earnings (Loss) Per Share
Basic income (loss) per share was calculated by dividing net income or loss applicable to common shares by the weighted average number of common shares outstanding during the periods presented. The calculation of diluted income (loss) per share should include the potential dilutive impact of shares issuable upon the conversion of debt or preferred stock, vested restricted stock and exercise of warrants and options during the period, unless their effect is anti-dilutive. At December 31, 2016 and 2015, shares underlying restricted stock units, restricted stock, options, warrants, preferred stock and debentures have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. The Company has included 3,522,735 warrants, with an exercise price of $.01, in its earnings per share calculation for the year ended December 31, 2016.
The Company had the following shares of Common Stock equivalents at December 31, 2016 and 2015:
| | | December 31, | |
| | | 2016 | | | 2015 | |
| Stock Options | | | 5,956,833 | | | | 6,083,333 | |
| Restricted Stock Units | | | 149,584 | | | | 1,869,000 | |
| Restricted Stock | | | 1,068,305 | | | | - | |
| Series A Preferred Stock | | | - | | | | 3,112,033 | |
| Series B Preferred Stock | | | 15,454,545 | | | | - | |
| Stock Purchase Warrants | | | 12,392,776 | | | | 24,383,161 | |
| Convertible Debentures | | | - | | | | 3,423,233 | |
| Convertible Bridge Notes | | | - | | | | 5,900,004 | |
| | | | 35,022,043 | | | | 44,770,764 | |
The Company uses the asset and liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporary differences between financial statement carrying amounts and the tax bases of assets and liabilities and are measured using the tax rates expected to be in effect when the differences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is used to reduce deferred tax assets when uncertainty exists regarding their realization.
The Company recognizes its tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed that do not meet these recognition and measurement standards. As of December 31, 20162019 and 2015,2018, the Company has determined that no liability is required to be recognized.
The Company’s policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. No interest or penalties were required to be accrued at December 31, 20162019 and 2015.2018. Further, the Company does not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months.Recently Issued Accounting Pronouncements
Concentration of Credit Risk
The Company considersoperates a substantial portion of its oil and natural gas properties. As the applicabilityoperator of a property, the Company makes full payment for costs associated with the property and impactseeks reimbursement from the other joint interest owners in the property for their portion of all Accounting Standards Updates (“ASUs”). those costs. When warranted, prepayments are required from joint interest owners for drilling and completion projects. Joint interest owners consist primarily of independent oil and natural gas producers whose ability to reimburse the Company could be negatively impacted by adverse market conditions.
The ASUspurchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, major oil and natural gas companies, refiners and natural gas pipeline companies. Credit evaluations are performed on the Company’s purchasers of its production and their financial condition is monitored on an ongoing basis. Based on those evaluations and monitoring, the Company may obtain letters of credit or parental guarantees from some purchasers.
All of the Company’s oil and natural gas derivative transactions are carried out in the over-the-counter market and are not
listed belowtypically subject to margin-deposit requirements. The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The Company monitors the credit ratings of its derivative counterparties on an ongoing basis. If a counterparty were
assessed and determined to
be either not applicable or are expected to have minimal impactdefault on its
consolidated financial position and/obligations to the Company under the derivative contracts or
results of operations.
In January 2017, the FASB issued ASU 2017-01“Business Combinations (Topic 805): Clarifying the Definition of a Business”, which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The standard introduces a screen for determining when assets acquired are not a business and clarifies that a business must include, at a minimum, an input and a substantive process that contribute to an output to be considered a business. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. The Company adopted this ASU on January 1, 2017, and expects that the adoption of this ASUseek bankruptcy protection, it could have a material impactadverse effect on its ability to fund planned activities and could result in a larger percentage of our future production being subject to commodity price volatility. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened and fewer counterparties may participate in derivative transactions, which could result in greater concentration of exposure to any one counterparty or a larger percentage of the Company’s future production being subject to commodity price changes.
Derivative Instruments
All derivative instruments are recorded on the consolidated
financial statementsbalance sheet at fair value as either an asset or a liability with changes in fair value recognized currently in earnings. Although derivative instruments are used by the Company to manage the price risk attributable to its expected oil and natural gas production, those derivative instruments have not been designated as accounting hedges under the accounting guidance. All of our derivatives are accounted for
acquisitions thatas mark-to-market activities. Under ASC Topic 815, “Derivatives and Hedging,” these instruments are
not consideredrecorded 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
be businesses.The FASB issued ASU 2016-18, “Restricted Cash (Topic 230),” to clarify the presentation of restricted cashsuch offset exists. Changes in the statement ofderivatives’ fair values are
recognized in current earnings since the Company has elected not to designate its current derivative contracts as cash flows. flow hedges for accounting purposes.
The amendments requireCompany has recognized certain conversion features within its Second Lien Term Loan as embedded derivatives that a statement of cash flows explainhave been bifurcated from the change duringSecond Lien Term Loan, as defined in Note 9 - Derivatives, and accounted for separately from the period in restricted cash or restricted cash equivalents. In additionsdebt.
The Company has recognized that our crude oil sales agreement with ARM no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging,” due to
changes in cashthe Company not meeting the minimum quantities deliverable under the contract and
cash equivalents, restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the
beginning-of-period and end-of-period total amounts shown on the statement of cash flows.net settlement criteria being met. As a result,
transfers between cashan embedded derivative exists as it is no longer probable the contract will only result in physical deliveries of crude oil and
restricted cash will not be presented as a separate line item in the operating, investing or financing section of the cash flow statement. The amendments are effectmay net settle. See Note 9 - Derivatives for
public business entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted. The Company will adopt this ASU in 2017. The adoption of this ASU will affect the presentations in the Company’s consolidated balance sheets and consolidated statement of cash flows and will not materially impact the results of operations.additional information.
Recently Adopted Accounting Standards
In February 2016, the
FASBFinancial Accounting Standards Board (“FASB”) issued
ASUAccounting Standards Update (ASU) No. 2016-02,
“LeasesLeases (Topic 842),
” which requires companies a standard on lease accounting requiring a lessee to recognize
the assets and liabilities
for the rights and obligations created by long-term leases of assets on the balance
sheet. The guidance requires adoption by application of a modified retrospective transition approachsheet for
existing long-term leases
and is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The effect of this guidance relating to the Company’s existing long-term leases will not have material impact on the Company’s consolidated financial statements. As of December 31, 2016, the Company currently has only one 2-year operating lease.The FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.with lease terms greater than 12 months. This ASU will simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This ASU isstandard was effective for annual and interim periods beginning in 2017 with early adoption permitted. The Companyafter December 15, 2018. We adopted this ASU onstandard effective January 1, 20172019, utilizing a modified retrospective transition approach. We chose to use the effective date as our date of initial application. Consequently, financial information was not updated and the disclosures required under the new standard were not provided for dates and periods before January 1, 2019.
The standard includes optional transition practical expedients intended to simplify its adoption. We elected to adopt the package of practical expedients, which allowed us to retain the historical lease classification, including treatment for land easements, determined under legacy GAAP as well as a relief from reviewing expired or existing contracts to determine if they contain leases. This standard does not believeapply to the Company’s leases that provide the simplificationright to explore for minerals, oil, or natural gas resources.
Upon adoption, we recognized operating lease liabilities totaling approximately $7.5 million, with corresponding right of accountinguse assets totaling $7.4 million. The liabilities were calculated as the present value of the remaining minimum rental payments for share-based compensationexisting operating leases. This standard did not materially impact our consolidated net earnings and related income taxes will have a materialhad no impact on its consolidated financial statements.our cash flows (see
Note 10 - Leases).
Accounting Standards Not Yet Adopted
In MarchJune 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers2016-13, Financial Instruments-Credit Losses (Topic 606)326): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This ASU amends the principal versus agent guidance in ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)Measurement of Credit Losses on Financial Instruments, which was issued in May 2014 (“ASU 2014-09”). Further, in April 2016,replaces the FASB issued ASU No. 2016-10, Revenue from Contractscurrently required incurred loss methodology with Customers (Topic 606): Identifying Performance Obligations and Licensing.an expected loss methodology. This ASU also amends ASU 2014-09 and is related tonew methodology requires that a financial asset measured at amortized cost be presented at the identification of performance obligations and accounting for licenses. The effective date and transition requirements for both of these amendments to ASU 2014-09 are the same as those of ASU 2014-09, which was deferred for one year by ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. That is, the guidance under these standards isnet amount expected to be applied using a full retrospective method or a modified retrospective method, as outlined in the guidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted only for annual periods, and interim period within those annual periods, beginning after December 15, 2016. The Company has not selected a transition method and is evaluating its revenue recognition policies and existing customer contracts to determine the impact this guidance will have on its financial statements.In March 2016, the FASB issued ASU No. 2016-06, “Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments” (“ASU 2016-06”). This new standard simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess whether a contingent event is related to interest rates or credit risks. This new standard will be effective for the Company on January 1, 2017. The Company expects the adoption of this standard may have material impact on the Company’s result of operations from its continued efforts in raising capital to fund its operations and develop its oil and gas properties from issuing convertible equity or debt instruments.
On August 26, 2016, the FASB issued ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force), (“ASU 2016-15”). The amendments in ASU 2016-15 address eight specific cash flow issues and apply to all entities, including both business entities and not-for-profit entities that are required to present a statement of cash flows under FASB Accounting Standards Codification (FASB ASC) 230, Statement of Cash Flows. The amendments in ASU 2016-15 are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The Company adopted this ASU on January 1, 2017 and expects the adoption will only affect the classifications within the consolidated statement of cash flows.
In September 2015, the FASB issued ASU No. 2015-16, “Business Combinations (Topic 805), Simplifying the Accounting for Measurement-Period Adjustments” (“ASU 2015-16”).collected. The update requires that the acquirer in a business combination recognize adjustmentsis intended to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined (not retrospectively as with prior guidance). Additionally, the acquirer must record in the same period’s financial statements the effect on earnings of changes in depreciation, amortization or other income effects as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the time of acquisition. The acquiring entity is required to disclose, on the face of the financial statements or in the footnotes to the financial statements, the portion of the amount recorded in current period earnings, byprovide financial statement line item, that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date.users with more useful information about expected credit losses on financial instruments. The guidance in ASU No. 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. Earlier application is permitted for financial statements that have not been issued. The Company adopted this standard on January 1, 2016 and there were no material impact on its consolidated financial statements.
In April 2015, the FASB issued ASU No. 2015-03 (“ASU 2015-03”), “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, consistent with debt discounts, instead of being presented as an asset. ASU 2015-03 is effective for the Company on January 1, 2016. Once adopted, entities are required to apply the new guidance retrospectively to all prior periods presented. The retrospective application represents a change in accounting principle. Early adoption is permitted for financial statements that have not been previously issued. The Company adopted this standard on January 1, 2016. The adoption of ASU 2015-03 only affects the presentation of the Company’s accompanying consolidated balance sheets and related financial statement disclosures in Note 9. In conjunction with the adoption of ASU 2015-03, $1.8 million and $0.2 million of debt issuance costs, previously presented as part of other assets was included as part of long-term debt which was reclassified as a direct deduction from the carrying amount of that debt liability as of December 31, 2016 and 2015, respectively.
In August 2014, the FASB issued ASU No. 2014–15 (“ASU 2014-15”), “Presentation of Financial Statements – Going Concern.” ASU 2014-15 provides GAAP guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raise substantial doubt about a company’s ability to continue as a going concern within one year from the date the financial statements are issued. The newamended standard is effective for the Company on January 1, 2017. As2023, with early adoption permitted, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company is evaluating the impact the adoption of ASU 2016-13 will have on its consolidated financial statements.
In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement, which modifies the fair value disclosure requirements based on application of the disclosure framework. The provisions removed or amended certain disclosures and in some cases, the ASU requires additional disclosures. The standard is effective for the Company for fiscal years, and interim periods within those years, beginning after December 15, 2019. The Company is evaluating the impact the adoption of ASU 2018-13 will have on its consolidated financial statements.
Accrued Liabilities and Other
At December 31,
2016,2019 and 2018, the
Company believes that it has sufficient capital to operate forCompany’s accrued liabilities consisted of the
next 12 months – see management’s assessment and analysis of its plans and liquidity in Note 2 - Management Plans and Liquidity above.following:
|
| | | | | | | |
| | 2019 | | 2018 |
| | (In thousands) |
| Accrued personnel costs | $ | — |
| | $ | 2,300 |
|
| Accrued drilling and completion costs | 5,021 |
| | 2,849 |
|
| Drilling advances | 1,328 |
| | 5,001 |
|
| Accrued production expenses | 3,326 |
| | 2,926 |
|
| Other accrued liabilities | 3,885 |
| | 1,718 |
|
| Short-term operating lease liabilities | 412 |
| | — |
|
| | $ | 13,972 |
| | $ | 14,794 |
|
NOTE 4 –- OIL AND NATURAL GAS PROPERTIES
The following table sets forth a summary of oil and
natural gas property costs (net of divestitures)
not being amortized at December 31,
20162019 and
2015:| | | December 31, | |
| | | 2016 | | | 2015 | |
| | | (In thousands) | |
| Undeveloped unevaluated acreage | | | | | | | | |
| Beginning Balance | | $ | - | | | $ | 2,886 | |
| Lease purchases | | | 546 | | | | - | |
| Assets conveyed | | | 23,915 | | | | - | |
| Transfer and other reclassification to evaluated properties | | | - | | | | (2,886 | ) |
| Total undeveloped acreage | | $ | 24,461 | | | $ | - | |
| | | | | | | | | |
| Wells in progress: | | | | | | | | |
| Beginning Balance | | $ | - | | | $ | 6,042 | |
| Additions | | | 7,453 | | | | - | |
| Disposition of wells in progress for elimination of accrued expenses for drilling | | | - | | | | (5,198 | ) |
| Reclassification to evaluated properties | | | - | | | | (844 | ) |
| Total wells in progress and not subject to DD&A | | $ | 7,453 | | | $ | - | |
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| | (In thousands) |
| Oil and natural gas properties: | | | |
| Proved | $ | 478,569 |
| | $ | 358,858 |
|
| Unproved | 109,590 |
| | 169,863 |
|
| Total oil and natural gas properties | 588,159 |
| | 528,721 |
|
| Accumulated depletion, depreciation, amortization and impairment | (359,304 | ) | | (98,342 | ) |
| Oil and natural gas properties, net | $ | 228,855 |
| | $ | 430,379 |
|
The following table sets forth a summary of costs withheld from amortization as of December 31, 2019:
|
| | | | | | | | | | | | | | | |
| | Year of Acquisition |
| | Total | | 2019 | | 2018 | | 2017 |
| | (In thousands) |
| Unamortized costs: | | | | | | | |
| Unproved leasehold costs | $ | 109,590 |
| | $ | 1,643 |
| | $ | 85,598 |
| | $ | 22,349 |
|
| Total | $ | 109,590 |
| | $ | 1,643 |
| | $ | 85,598 |
| | $ | 22,349 |
|
For the years ended December 31, 2019 and 2018, $56.2 million and $11.1 million, respectively, of unproved property costs were recorded as impairments of unproved property costs and transferred to proved properties. Impairments for 2019 were the result of title defects, lease expirations, changes to management’s development plans and uncertainty that the Company will have access to necessary funding to either extend the leases expiring in 2020 or begin drilling before their expiration dates. The 2018 impairment of $11.1 million was the result of defective titles for certain leases.
Depreciation, depletion and amortization expense related to proved properties was approximately $32.6 million and $25.2 million, respectively for the years ended December 31, 2019 and 2018. Full-cost ceiling impairments totaling $228.3 million were recorded for the year ended December 31, 2019. For the year ended December 31, 2018, no such impairments were recognized.
The 2019 impairment charges were the result of a decrease in crude oil and natural gas prices used in preparation of the proved reserves estimates. Additionally, proved undeveloped reserves previously included in the Company’s proved reserves report were reclassified as unproved because of the uncertainty regarding the availability of capital for development those reserves as of December 31, 2019. The reclassification of proved undeveloped reserves to unproved are recognized in the Company’s proved reserves report as of December 31, 2019. These changes have contributed, in part, to higher depletion rates for 2019 as compared to 2018.
NOTE 5 - ACQUISITIONS AND DIVESTITURES
Divestitures During 2019
On July 31, 2019, the Company entered into two agreements with Winkler Lea Royalty, L.P. (“WLR”) and Winkler Lea WI, L.P. (“WLWI”) for the sale of an overriding royalty interest and a non-operated working interest in undeveloped assets, respectively, for combined cash proceeds of $39.0 million, including WLWI’s drilling advance (the “Asset Sales”). WLR and WLWI are affiliates of Värde Partners, Inc., a related party (see Note 13 - Related Party Transactions).
The Company entered into a Purchase and Sale Agreement with WLR (the “ORRI Agreement”), pursuant to which the Company sold to WLR an overriding royalty interest (the “ORRI”) in approximately 1,446 net royalty acres in Winkler and Loving Counties, Texas, and Lea County, New Mexico. The ORRI is equal to the positive difference, if any, between 25% and existing royalties and other burdens, subject to proportionate reduction and the other terms and conditions set forth in the instrument of conveyance. The ORRI Agreement provides the Company with a right to repurchase all, but not less than all, of the ORRI for a period of three years and an obligation, at WLR’s election only upon a change of control, to repurchase all, but not less than all, of the ORRI, and also includes certain limitations on WLR’s right to transfer the ORRI during such three year period without the consent of the Company. The repurchase price for the first two years of the repurchase period is 1.5 times the purchase price paid by WLR, less the proportionate share of production paid by the Company. For the third year, the repurchase price is the same with the multiplier increased to 1.75. After the third year, the repurchase period expires.
The Company entered into a Purchase and Sale Agreement with WLWI (the “WI Agreement”), pursuant to which the Company sold an undivided 49% of its right, title and interest in certain undeveloped assets located in Winkler and Loving Counties, Texas, consisting of approximately 749 net acres. The WI Agreement provides that the Company must drill, complete and equip five commitment wells after closing (the “Development Plan”). Contemporaneously with the purchase, WLWI paid a drilling advance which funded its proportionate share of the development costs to drill, complete and equip such commitment wells. Any drilling cost overruns or costs incurred below estimated costs are the responsibility of the Company. As of December 31, 2019, three of the five commitment wells are producing, the fourth well is drilled and awaiting completion and the fifth well has not yet been drilled. Under the WI Agreement, the fourth and fifth wells are required to begin production mid-year 2020, subject to reasonable delays on account of Force Majeure or modifications or revisions to the Development Plan as approved by both parties. Should the Company otherwise breach the scheduled Development Plan, WLWI shall be entitled to liquidated damages of an amount equal to $150,000 plus $1,500 for each day beyond a 60-day period after Development Plan commitment date until the actual date of first production.
The WI Agreement provides the Company with a right to repurchase all, but not less than all, of the interest for a period of three years and an obligation, at WLWI’s election only upon a change of control, to repurchase all, but not less than all, of the interest, and also includes certain limitations on WLWI’s right to transfer the interest during such three year period without the consent of the Company. The repurchase price is 1.5 times the consideration paid by WLWI plus additional capital expenditures of WLWI. The repurchase period expires after three years.
As a result of the repurchase rights, the agreements with WLR and WLWI do not meet the criteria for a conveyance or sale of assets under ASC 932, “Extractive Activities - Oil & Gas”, and are accounted for as a financing arrangement. The net proceeds of the transaction of $39.0 million are included in long-term deferred revenue and other long-term liabilities on the Company’s consolidated balance sheet as of December 31, 2019. WLR’s proportionate share of revenue of $0.4 million and WLWI’s proportionate share of net revenues, (revenues less production costs), of $0.5 million for the year ended December 31, 2019 is included in interest expense on the Company’s consolidated statements of operations.
On August 16, 2019, we sold approximately 513 noncontiguous net acres in New Mexico for net cash proceeds of $16.7 million, which was recorded as a reduction to the full cost pool. The Company repurchased certain overriding royalty interests in the acreage previously sold to WLR under the ORRI Agreement for $2.6 million, resulting in a $1.3 million loss on extinguishment of a portion of the financing arrangement and is included in loss on early extinguishment of debt on the Company’s consolidated statements of operations.
On February 28, 2020, the Company closed on the sale of approximately 1,185 undeveloped net acres in Lea County, New Mexico, for net cash proceeds of approximately $24.1 million, subject to customary purchase price adjustments (the “Marlin Disposition”). The proceeds were used to fund a substantial portion of the Borrowing Base Deficiency with the balance to be used for general corporate purposes.
Acquisitions During 2018
During the year ended December 31, 2016,2018, the Company enteredacquired the following oil and natural gas properties:
Certain leasehold acreage in the Delaware Basin throughin Lea County, New Mexico from OneEnergy Partners Operating, LLC for $40.0 million in cash and 6,940,722 shares of the Merger. Since then, Lilis has increased its Delaware Basin acreage position by 53%Company’s common stock valued at approximately $24.9 million, for total consideration of approximately $64.9 million. Transaction costs associated with this acquisition were approximately $1.1 million. The transaction was recorded as an asset acquisition.
Certain leasehold interests and has added 860 net contiguous acres further expanding its Delaware Basin footprint. Atother oil and natural gas assets in Loving and Winkler Counties, Texas from VPD Texas, L.P. for total cash consideration of approximately $11.1 million, including approximately $0.5 million of related acquisition costs. The transaction was recorded as an asset acquisition.
Certain leasehold interests and other oil and natural gas assets in Loving and Winkler Counties, Texas from Anadarko for total cash consideration of $7.1 million. The transaction was recorded as an asset acquisition.
Certain leasehold interests and other oil and natural gas assets in Lea County, New Mexico from Ameradev II, LLC for total cash consideration of $7.2 million and was recorded as an adjustment to the full cost pool.
Certain leasehold interests and other oil and natural gas assets in Loving and Winkler Counties, Texas from Felix Energy Holdings II, LLC for total cash consideration of $0.4 million and was recorded as an adjustment to the full cost pool.
Proved property and certain leasehold interests located in Winkler County, Texas from Southwest Royalties, LLC for total consideration of approximately $17.0 million. The acquisition was accounted for as a business combination. Therefore the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values available at closing. Transaction costs associated for this acquisition were immaterial and were expensed in the Consolidated Statements for Operations during the year ended December 31,
20162018. Revenues and
2015, the Company completed an assessment of its inventory of unevaluated acreage, which resulted in a transfer of $0 and $2.9 million, respectively from unevaluated acreage to evaluated properties.Depreciation, depletion and amortization (“DD&A”)operating expenses related toassociated with the proved properties were approximately $1.6 millioninsignificant to the December 31, 2018 Consolidated Statements of Operations. The following table presents the final allocation of the purchase price to the assets acquired and $0.6 millionliabilities assumed as of the acquisition date:
|
| | | | |
| | | As of October 16, 2018 |
| | | (In thousands) |
| Fair value of net assets: | | |
| Proved oil and natural gas properties | | $ | 12,562 |
|
| Unproved oil and natural gas properties | | 4,542 |
|
| Total assets acquired | | 17,104 |
|
| Asset retirement obligations assumed | | (65 | ) |
| Fair value of net assets acquired | | $ | 17,039 |
|
NOTE 6 - ASSET RETIREMENT OBLIGATIONS
The Company’s asset retirement obligations (“ARO”) represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs. Revisions in estimated liabilities can also include, but are not limited to, revisions of estimated inflation rates, changes in property lives and expected timing of settlement.
The following table summarizes the changes in the Company’s ARO for the years ended December 31,
20162019 and
2015, respectively.2018:
|
| | | | | | | |
| | For the Year Ended December 31, |
| | 2019 | | 2018 |
| | (In thousands) |
| ARO, beginning of period | $ | 2,444 |
| | $ | 952 |
|
| Additional liabilities incurred | 186 |
| | 374 |
|
| Accretion expense | 433 |
| | 85 |
|
| Liabilities settled | (78 | ) | | (87 | ) |
| Revision in estimates | 438 |
| | 1,120 |
|
| ARO, end of period | 3,423 |
| | 2,444 |
|
Less: current portion of ARO (1) | — |
| | (11 | ) |
| ARO, non-current | $ | 3,423 |
| | $ | 2,433 |
|
(1) The current portion of ARO is included in accrued liabilities in the consolidated balance sheets.
NOTE 5 – MERGER WITH BRUSHY RESOURCES, INC. AND RELATED TRANSACTIONSOn7 - REVENUE
Revenue is recognized when control passes to the purchaser, which generally occurs when production is transferred to the purchaser. The Company measures revenue as the amount of consideration it expects to receive in exchange for the commodities transferred. All the Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer.
The Company records revenue based on consideration specified in its contracts with its customers. The amounts collected on behalf of third parties are recorded in revenue payable. The Company recognizes revenue in the amount that reflects the consideration it expects to receive in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts is typically allocated to specific performance obligations in the contract according to the price stated in the contract. Payment is generally received one or two months after the sale has occurred.
Crude Oil Revenues
Crude oil from our operated properties is produced and stored in field tanks. The Company recognizes crude oil revenue when control passes to the purchaser. Effective January 1, 2019 through February 28, 2019, the Company’s crude oil was sold under a single short-term contract. The purchaser’s commitment included all quantities of crude oil from the leases that were covered by the contract, with no quantity-based restrictions or variable terms. Pricing was based on posted indexes for crude oil of similar quality, less a negotiable fees deduction of $5.15 per barrel.
Effective March 1, 2019, the Company’s crude oil is sold under a single long-term contract with a term that extends to at least December 31, 2024. The purchaser’s commitment has a quantity-based minimum set forth in the contract, measured in barrels per day, with the minimum quantity commitment increasing at periodic intervals over the life of the contract to coincide with the Company’s expected growth in production.
Pursuant to the long-term contract, pricing is based on posted indexes for crude oil of similar quality, with a differential based on pipeline delivery to Houston, as opposed to the previous contract differential based on truck delivery to Midland-Cushing, along with a differential basis reduction of $9.25 per barrel that was effective from March 1, 2019 through June 23, 2016,30, 2019, which decreased to $6.50 per barrel for the period of July 1, 2019 through June 30, 2020, and then to $4.95 per barrel for the period from July 1, 2020 through December 31, 2024. The posted index prices and differentials change monthly based on the average of daily index price points for each sales month. The purchaser’s affiliate shipper also charges a tariff fee of $0.75 as a deduction from the received price (see Note 12 - Long-Term Deferred Revenue Liabilities and Other Long-Term Liabilities).
Natural Gas and NGL Revenues
Natural gas from our properties is produced and transported via pipelines to gas processing facilities. NGLs are extracted from the natural gas at the processing facilities and processed natural gas and NGLs are marketed and sold separately on the Company’s behalf after processing. All our operated natural gas production is sold under one of two natural gas contracts, both of which are long-term in nature; however, one of these natural gas contracts includes 30-day cancellation provisions, and the Company completedtherefore classifies such contract as short-term. The processor’s commitment to sell on the merger transaction contemplated byCompany’s behalf includes all quantities of natural gas and NGLs produced from specific wellbores or dedicated acreage as defined in the Agreementcontract, with no quantity-based restrictions or variable terms. Pricing under the gas contracts is generally market-based pricing less adjustments for transportation and Planprocessing fees. A portion of Merger datednatural gas delivered to the processing plants is used as fuel at the processing plant without reimbursement. The Company recognizes revenue for natural gas and NGLs when control passes at the tailgate of the processing plant.
Gathering, Processing and Transportation
Natural gas must be transported to a gas processing plant facility for treatment and to extract NGLs, then the final residue gas and liquid products are marketed for sale to end users at the tailgate of the plant. As a result of these activities, the Company incurs costs that are contractually passed to it from the gatherer per customary industry practice. Such costs include fees for gathering the gas and moving it from wellhead to plant inlet, plant electricity usage, inlet compression, carbon dioxide and hydrogen sulfide treatments, processing tax, fuel usage, and marketing at the tailgate. Gathering, processing and transportation costs are presented as operating expenses in the consolidated statement of operations.
Imbalances
Natural gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If the Company receives less than its entitled share, the under production is recorded as a receivable. The Company did not have any significant natural gas imbalance positions as of December 29, 2015, as amended31, 2019 and 2018.
Contract balances and prior period performance obligations
The Company is entitled to date (the “Merger Agreement”) bypayment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional, and among the Company Brushyrecords these invoiced amounts as accounts receivable
in its condensed consolidated balance sheets. To the extent actual volumes and Lilis Merger Sub, Inc.,prices of oil and natural gas are unavailable for a Delaware corporation, a wholly-owned subsidiarygiven reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as accounts receivable in the accompanying consolidated balance sheets. In this scenario, payment is unconditional, as the Company has satisfied its performance obligations through delivery of the relevant product. As a result, the Company (“Merger Sub”). Pursuanthas concluded that its product sales do not give rise to contract assets or liabilities.
The Company records revenue in the month production is delivered to the termspurchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the customer and the price that will be received for the sale of the Merger Agreement, atproduct. Additionally, to the effective time (the “Effective Time”), Merger Sub merged withextent actual volumes and into Brushy (the “Merger”), with Brushy continuing asprices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third-party purchasers, the surviving corporationexpected sales volumes and becoming a wholly-owned subsidiaryprices for those barrels of Brushy.oil, cubic feet of gas and gallons of NGL are also estimated. The Merger resultedCompany records the differences between its estimates and the actual amounts received for product sales in the acquisitionmonth that payment is received from the purchaser. The Company has existing internal controls in place for its estimation process, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.
Significant judgments
The Company engages in various types of Brushy’s propertiestransactions in which midstream entities process its gas and subsequently market resulting NGLs and residue gas to third-party customers on the Company’s behalf per gas purchase contracts. These types of transactions require judgment to determine whether the Company is the principal or the agent in the Delaware Basincontract and, as well as the majority of its current operating activity.a result, whether revenues are recorded gross or net. The results of Brushy, since the closing dateCompany maintains control of the Mergernatural gas and NGLs during processing and considers itself the principal in these arrangements.
Practical expedients
A significant number of the Company’s product sales are
includedshort-term in nature with contract term of one year or less. For those contracts, the Company utilizes the practical expedient that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s product sales that have contract terms less than one year, the Company utilizes the practical expedient in the
Company’s consolidated statementnew revenue standard that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of
operations. The Merger was effected through the issuance of approximately 5.785 million shares of Common Stock in exchange for all outstanding shares of Brushy common stock usingproduct represents a
ratio of 0.4550916 shares of Lilis Common Stock for each share of Brushy common stockseparate performance obligation; therefore, future volumes are wholly unsatisfied and
the assumption of Brushy's liabilities, including approximately $11.4 million of outstanding debt with Independent Bank, Brushy’s former senior lender, and approximately $6.2 million of accounts payable, accrued expenses and asset retirement obligations. In connection with the closingdisclosure of the
Merger, Lilis paid-down $6.0 million of the principal amount outstanding on Brushy’s term loan with Independent Bank, made a cash payment of $500,000transaction price allocated to
SOSV Investments, LLC (“SOS”), Brushy's former subordinated lender and issued a $1 million promissory note to SOS (the “SOS Note”), along with a warrant to purchase 200,000 shares of Common Stock (the “SOS Warrant”).In connection with the Merger, Lilis incurred costs of approximately $3.22 million to date, including (i) $3.05 million of consulting, investment, advisory, legal and other Merger-related fees, and (ii) $170,000 of value in conjunction with the warrants issued to SOS recorded additional Merger consideration.
Allocation of Purchase Price - The Merger has been accounted for as a business combination, using the acquisition method. remaining performance obligations is not required.
The following table represents the allocation of the total purchase price of Brushy to the assets and liabilities assumed based on the fair value on the closing date of the Merger.The following table sets forthdisaggregates the Company’s purchase price allocationrevenue by contract type (
in thousands except shares data and stock price):| Shares of Lilis Common Stock issued to Brushy shareholders | | | | | | | 5,785,119 | |
| Lilis Common Stock closing price on June 23, 2016 | | | | | | $ | 1.20 | |
| Fair value of Common Stock issued | | | | | | $ | 6,942 | |
| Cash consideration paid to SOS | | | | | | | 500 | |
| SOS Note | | | | | | | 1,000 | |
| Fair value of SOS warrant | | | | | | | 170 | |
| Warrant liability - repricing derivative | | | | | | | 164 | |
| Advance to Brushy pre-merger | | | | | | | 2,508 | |
| Total purchase price | | | | | | | 11,284 | |
| Plus: liabilities assumed by Lilis | | | | | | | | |
| Current Liabilities | | | | | | | | |
| Account payable and accrued expenses | | $ | 5,447 | | | | | |
| Term loan - Independent Bank | | | 11,379 | | | | 16,826 | |
| | | | | | | | | |
| Long-Term Debt | | | | | | | 19 | |
| Asset Retirement Obligation | | | | | | | 777 | |
| Amount attributable to liabilities assumed | | | | | | | 17,622 | |
| | | | | | | $ | 28,906 | |
| Fair Value of Brushy Assets | | | | | | | | |
| Current Assets: | | | | | | | | |
| Cash | | $ | 706 | | | | | |
| Other current assets | | | 624 | | | | | |
| | | | | | | $ | 1,330 | |
| Oil and Gas Properties: | | | | | | | | |
| Evaluated properties | | | 7,512 | | | | | |
| Unevaluated properties | | | 19,662 | | | | | |
| | | | | | | | 27,174 | |
| Other assets | | | | | | | | |
| Other Property Plant & Equipment | | | 42 | | | | | |
| Other assets | | | 360 | | | | 402 | |
| Total Asset Value | | | | | | $ | 28,906 | |
Pro forma Financial Information - The following pro forma condensed combined financial information was derived from the historical financial statements of Lilis and Brushy and gives effect to the Merger as if it had occurred on January 1, 2015
) for the year ended December 31, 2015. Below information reflects pro forma adjustments based on available information and certain assumptions that2019: |
| | | | | | | | | | | |
| Year Ended December 31, 2019 | Short-term contracts | | Long-term contracts | | Total |
| Crude oil | $ | 9,711 |
| | $ | 49,304 |
| | $ | 59,015 |
|
| Natural gas | 220 |
| | 2,960 |
| | 3,180 |
|
| NGLs | 188 |
| | 3,680 |
| | 3,868 |
|
Customer Credit Risk
Our principal exposure to credit risk is through receivables from the Company believes are reasonable, including (i) Lilis’s Common Stock issued to convert Brushy’s outstanding sharessale of common stock as of the closing date of the Merger, (ii) adjustments to conform Brushy’s historical policy of accounting for itsour oil and natural gas propertiesproduction of approximately $9.1 million and $8.2 million at December 31, 2019 and 2018, respectively, and through actual and accrued receivables from the successful efforts methodour joint interest partners of approximately $9.5 million and $11.4 million at December 31, 2019 and 2018, respectively. We are subject to credit risk due to the full cost methodconcentration of accounting, (iii) depletion of Brushy's fair-valued provedour oil and natural gas properties,receivables with our most significant customers. We do not require our customers to post collateral, and (iv) the estimated tax impactsinability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Major Customers
During the year ended December 31, 2019, the Company’s major customers as a percentage of total revenue consisted of the
pro forma adjustments. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by Lilis to integrate the Brushy assets. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Merger taken place on January 1, 2015; furthermore, the financial information is not intended to be a projection of future results.| | | December 31, | |
| | | 2016 | | | 2015 | |
| | | (In thousands, except share data) | |
| | | | |
| Revenue | | $ | 4,989 | | | $ | 3,173 | |
| Net loss | | $ | (35,835 | ) | | $ | (75,808 | ) |
| Net loss attributable to common stockholders | | $ | (45,288 | ) | | $ | (76,528 | ) |
| Net loss per common share basic and diluted | | $ | (4.00 | ) | | $ | (13.32 | ) |
| Weighted average shares outstanding: | | | | | | | | |
| Basic and diluted | | | 11,328,252 | | | | 5,745,785 | |
|
| | | | | |
| | Year ended December 31, |
| | 2019 | | 2018 |
| ARM Energy Management, LLC | 68 | % | | — | % |
| Texican Crude & Hydrocarbon, LLC | 19 | % | | 87 | % |
| Lucid Energy Delaware, LLC | 12 | % | | 10 | % |
| Other below 10% | 1 | % | | 3 | % |
| | 100 | % | | 100 | % |
NOTE 6 –8 - FAIR VALUE OF FINANCIAL INSTRUMENTS The Company measures
the fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs used in the valuation methodologies in measuring fair value:
|
| | |
| ● | Level 1 - Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. |
|
| | |
| ● | Level 2 - Other inputs that are directly or indirectly observable in the marketplace. |
|
| | |
| ● | Level 3 - Unobservable inputs which are supported by little or no market activity. |
The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
Asset Retirement Obligation
Determination of the fair values of our derivative contracts incorporates various factors, including not only the impact of our non-performance risk on our liabilities, but also the credit standing of the counterparties involved. The Company utilizes counterparty rate of default values to assess the impact of non-performance risk when evaluating both our liabilities to, and receivables from, counterparties.
Recurring Fair Value Measurements
|
| | | | | | | | | | | | | | | |
| | Fair Value Measurement Classification | | |
| | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total |
| | (In thousands) |
| As of December 31, 2019 | |
| | |
| | |
| | |
|
| Oil and natural gas derivative instruments: | | | | | | | |
| Oil and natural gas derivative swap contracts | $ | — |
| | $ | (3,932 | ) | | $ | — |
| | $ | (3,932 | ) |
| Oil and natural gas derivative collar contracts | — |
| | 301 |
| | — |
| | 301 |
|
| Embedded derivative instruments: | | | | | | | |
| Net settlement provisions under ARM sales agreement | — |
| | — |
| | (3,238 | ) | | (3,238 | ) |
| Total | $ | — |
| | $ | (3,631 | ) | | $ | (3,238 | ) | | $ | (6,869 | ) |
| As of December 31, 2018 | | | | | | | |
| Oil and natural gas derivative instruments: | | | | | | | |
| Oil and natural gas derivative swap contracts | $ | — |
| | $ | (2,923 | ) | | $ | — |
| | $ | (2,923 | ) |
| Oil and natural gas derivative collar contracts | — |
| | 4,047 |
| | — |
| | 4,047 |
|
| Embedded derivative instruments: | | | | | | | |
| Second Lien Term Loan conversion features | — |
| | — |
| | (1,965 | ) | | (1,965 | ) |
| Total | $ | — |
| | $ | 1,124 |
| | $ | (1,965 | ) | | $ | (841 | ) |
Derivative assets and liabilities include unsettled amounts related to commodity derivative positions, including swaps and collars, as of December 31, 2019 and 2018. The fair value of the Company’s asset retirement obligation liability is calculated at the point of inception by taking into account, the cost of abandoning oil and gas wells, whichderivatives is based on third-party pricing models which utilize inputs that are either readily in the Company’s and/public market or Industry’s historical experience for similar work, or estimateswhich can be corroborated from independent third-parties;active markets of broker quotes. Swaps and collars generally have observable inputs and these instruments are measured using Level 2 inputs.
In addition, derivative liabilities as of December 31, 2019 include an embedded derivative associated with the economic livesARM sales agreement (see Note 21 - Commitments and Contingencies). The Company recognized a derivative liability and an unrealized loss of its properties, which$3.2 million as of December 31, 2019. This embedded derivative has fewer observable inputs from objective sources and are based on estimates from reserve engineers; the inflation rate; and the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to usetherefore measured using Level 3 inputs.Executive Compensation
In September 2013, the Company announced the appointment of Abraham Mirman as its new president. In connection with Mr. Mirman’s appointment, the Company entered into an employment agreement with Mr. Mirman (the “Mirman Agreement”). The Mirman Agreement provides for an incentive bonus package that, depending upon the relative performancefair value of the net settlement provisions under the agreement was determined based on certain assumptions including (1) forward pricing for crude oil basis differentials, (ii) future LIBOR rates and (iii) the Company’s Common Stock compared to the performance of stocks of certain peer group companiesimplied credit rating.
The Company’s derivative liabilities as measured from Mr. Mirman’s initial date of employment through December 31, 2014, may result in a cash bonus payment to Mr. Mirman of up to 3.0 times his base salary. The incentive bonus is recorded as a liability and valued at each reporting period. The Company engaged a valuation firm (“VFIRM”) to complete a valuation of this incentive bonus. As previously announced, on March 30, 2015, the Company entered into an amended and restated employment agreement, which the Company refers to as the Mirman CEO Agreement with Mr. Mirman. The Mirman CEO Agreement also provides for Mr. Mirman to receive a cash incentive bonus if certain production thresholds are achieved by the Company. Mr. Mirman’s new incentive bonus liability was valued by VFIRM at $104,000 at December 31, 2015. As of December 31, 2016, there was no bonus liability due to Mr. Mirman since2018 also include embedded derivatives associated with the production thresholds were not met by the Company. AsSecond Lien Term Loan (as defined in Note 11 - Long-Term Debt). These instruments have fewer observable inputs from objective sources and are therefore measured using Level 3 inputs. The Company recorded an unrealized loss of December 31, 2015, the Company provided for $87,000 of the bonus liability which represents the amount earned as of December31, 2015.On March 6, 2015, the Company announced the appointment of Kevin Nanke as its new Executive Vice President$0.3 million and Chief Financial Officer. Mr. Nanke would also receive a cash incentive bonus if certain production thresholds were achieved by the Company and a performance bonus of $100,000 if the Company achieved certain goals set forth in Mr. Nanke’s employment agreement. Mr. Nanke’s new incentive bonus liability was valued by VFIRM at $83,000 at December 31, 2015. As of December 31, 2016, there was no bonus liability due to Mr. Nanke since the production thresholds were not met by the Company. As of December 31, 2015, the Company provided for $69,000 of the liability which represents the amount earned as of that date.
On March 16, 2015, the Company entered into an employment agreement with Ariella Fuchs for services to be performed as General Counsel to the Company. Ms. Fuchs will also receive a cash incentive bonus if certain production thresholds are achieved by the Company. Ms. Fuchs’ new incentive bonus liability was valued by VFIRM at $80,000 at December 31, 2015. As of December 31, 2016, there was no bonus liability due to Ms. Fuchs since the production thresholds were not met by the Company. As of December 31, 2015, the Company provided for $67,000 of the liability which represents the amount earned as of that date.
Change in Warrant Liability
On September 2, 2014, the Company entered into a Consulting Agreement with Bristol Capital, LLC, pursuant to which the Company issued to Bristol a warrant to purchase up to 100,000 shares of Common Stock at an exercise price of $20.00 per share (or, in the alternative, 100,000 options, but in no case both). The agreement has a price protection feature that will automatically reduce the exercise price if the Company enters into another consulting agreement pursuant to which warrants are issued with a lower exercise price, which triggered during fiscal year 2016. On December 31, 2016, the Company revalued the warrants/option using the revised terms as follows: (i) 641,026 total warrants/options issued; (ii) stock price of $3.10; (iii) exercise price of $3.12; (iv) expected life of 2.67 years; (v) volatility of 101%; (vi) risk free rate of 1.38% for a total value of $1.2$58.3 million which adjustedon the change in fair value valuationof derivative liabilities associated with the Second Lien Term Loan conversion features for the years ended December 31, 2019 and 2018, respectively.
The fair value of the holder conversion features was determined using a binomial lattice model based on certain assumptions including (i) the Company’s stock price, (ii) risk-free rate, (iii) expected volatility, (iv) the Company’s implied credit rating, and (v) the implied credit yield of the Loan.
The following table sets forth a reconciliation of changes in the fair value of the Company’s financial assets and liabilities classified as Level 3 in the fair value hierarchy, except for the commodity derivatives classified as Level 2, as disclosed in Note 9, as of December 31, 2019 and 2018:
|
| | | | | | | | | | | |
| | Firm Takeaway and Pricing Agreement Net Settlement Provisions | | Second Lien Term Loan Conversion Features | | Total |
| | (in thousands) |
| Balance at January 1, 2019 | $ | — |
| | $ | (1,965 | ) | | $ | (1,965 | ) |
| Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan | — |
| | 2,300 |
| | 2,300 |
|
| Fair value of the embedded derivatives in ARM Sales Agreement | (3,238 | ) | | (335 | ) | | (3,573 | ) |
| Balance at December 31, 2019 | $ | (3,238 | ) | | $ | — |
| | $ | (3,238 | ) |
|
| | | | | | | | | | | |
| | Second Lien Term Loan Conversion Features | | Warrant Liabilities | | Total |
| | (in thousands) |
| Balance at January 1, 2018 | $ | (72,714 | ) | | $ | (223 | ) | | $ | (72,937 | ) |
| Transferred to equity | — |
| | 223 |
| | 223 |
|
| Fair value of the converted portion of the embedded derivatives associated with the Second Lien Term Loan | 12,406 |
| | — |
| | 12,406 |
|
| Change in fair value of derivative liabilities | 58,343 |
| | — |
| | 58,343 |
|
| Balance at December 31, 2018 | $ | (1,965 | ) | | $ | — |
| | $ | (1,965 | ) |
NOTE 9 - DERIVATIVES
The Company’s derivative by $1.0instruments as of December 31, 2019 and 2018, include the following:
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| | (In thousands) |
| Derivative assets (liabilities): | | | |
| Derivative assets - current | $ | 427 |
| | $ | 2,551 |
|
Derivative assets - non-current (1) | 187 |
| | 1,822 |
|
Derivative liabilities - current (3) | (5,044 | ) | | (515 | ) |
Derivative liabilities - non-current (2) (3) (4) | (2,439 | ) | | (4,699 | ) |
| Total derivative liabilities, net | $ | (6,869 | ) | | $ | (841 | ) |
(1) The non-current derivative assets are included in other assets in the consolidated balance sheets.
(2) The non-current derivative liabilities are included in long-term derivative instruments and other non-current liabilities in the consolidation balance sheets.
(3) The ARM sales agreement includes an embedded derivative. As of December 31, 2019, the embedded derivative is included as current liabilities and non-current liabilities of $0.8 million and $2.4 million, respectively.
(4) Includes $2.0 million embedded derivative associated with Second Lien Term Loan and $2.7 million in commodity derivatives as of December 31, 2018.
Embedded Derivatives
As discussed in Note 21 - Commitments and Contingencies, the ARM sales agreement contains minimum quantity commitments. Should the Company be unable to meet those minimum commitments, the agreement contains a two way make whole provision that allows for net settlement. As of December 31, 2019, the Company concluded it is no longer probable they will be able to make delivery of the minimum quantities specified in the agreement. The Company has, therefore recorded the fair value of the embedded derivative as of December 31, 2019. The net settlement feature for remaining future minimum commitment volumes are considered embedded derivatives that are recorded, with changes in fair value included in the Company’s consolidated statement of operations.
As of December 31, 2019, the derivative liability associated with the ARM sales agreement was approximately $3.2 million with $0.8 million recorded in current derivative instruments and $2.4 million recorded in long-term derivative instruments on the Company’s consolidated balance sheets.
As discussed in Note 11 - Long-Term Debt, the Second Lien Term Loan contained conversion features that were exercisable at the option of the lead lender thereunder or, in certain circumstances, the Company. The conversion features have been identified as embedded derivatives which (i) contain economic characteristics that are not clearly and closely related to the host contract, the Second Lien Term Loan, and (ii) are separate, stand-alone instruments with similar terms that would qualify as derivative instruments. As such, the conversion features were bifurcated and accounted for separately from the Second Lien Term Loan. The conversion features are recorded at fair value for each reporting period with changes in fair value included in the Company’s consolidated statement of operations for each reporting period.
As of December 31, 2018, the derivative liabilities associated with the Second Lien Term Loan were approximately $2.0 million. On December 31, 2015,March 5, 2019, the embedded derivative associated with the Second Lien Term Loan was written off against the gain on extinguishment of debt following the extinguishment of the Second Lien Term Loan on March 5, 2019, pursuant to the provisions of the 2019 Transaction Agreement (as defined in Note 11 - Long-Term Debt).
Commodity Derivatives
To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues and to protect the economics of property acquisitions, the Company revaluedperiodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix or modify the warrants/options usingfuture prices to be realized. The derivative contracts may include fixed-for-floating price swaps (whereby, on the following variables: (i) 100,000 total warrants/options issued (as stated above,settlement date, the Company will receive or pay an amount based on the difference between a pre-determined fixed price and a variable market price for a notional quantity of production), put options (whereby the Company pays a cash premium in order to establish a fixed floor price for a notional quantity of production and, on the settlement date, receives the excess, if any, of the fixed floor price over a variable market price), and costless collars (whereby, on the settlement date, the Company receives the excess, if any, of a variable market price over a fixed floor price up to a fixed ceiling price for a notional quantity of production).
Our hedging activities are intended to support oil and natural gas prices at targeted levels and manage exposure to oil and natural gas price fluctuations, as well as to meet our obligations under our Revolving Credit Agreement (as defined in Note 11 - Long-Term Debt). It is our policy to enter into derivative contracts only issuewith counterparties that are creditworthy and competitive market makers. All of our derivatives are designated as unsecured. Certain of our derivative counterparties may require the posting of cash collateral under certain conditions. The Company does not enter into derivative contracts for speculative trading purposes.
All of our derivatives are accounted for as mark-to-market activities. Under Accounting Standard Codification (“ASC”) Topic 815, “Derivatives and Hedging,” these instruments are recorded on the Company’s consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets and liabilities by commodity for counterparties where a total of 100,000 shares of Common Stock underlegal right to such offset exists. Because the option or the warrant, but no more than 100,000 shares of Common StockCompany has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes, changes in the aggregate); (ii) stock price of $2.00; (iii) exercise price of $2.00; (iv) expected life of 3.7 years; (v) volatility of 100%; risk free rate of 1.5% for a total value of approximately $44,000, which adjusted the change in fair value valuationvalues of the derivatives are recognized in current earnings.
The following table presents the Company’s derivative by $350,000position for the production periods indicated as of December 31, 2019:
|
| | | | | | | | | | |
| Description | | | Notional Volume (Bbls/d) | | Production Period | | Weighted Average Price ($/Bbl) |
| Oil Positions | | | | | | | |
| | | | | | | | |
| Oil Swaps | | | 1,028 |
| | January 2020 - December 2020 | | $ | 56.28 |
|
| Oil Swaps | | | 370 |
| | January 2021 - December 2021 | | $ | 53.07 |
|
| | | | | | | | |
| Basis Swaps (1) | | | 1,500 |
| | January 2020 - December 2020 | | $ | (5.62 | ) |
| | | | | | | | |
| 3 Way Collar | Floor sold price (put) | | 228 |
| | January 2020 - December 2020 | | $ | 40.00 |
|
| 3 Way Collar | Floor purchase price (put) | | 228 |
| | January 2020 - December 2020 | | $ | 50.00 |
|
| 3 Way Collar | Ceiling sold price (call) | | 228 |
| | January 2020 - December 2020 | | $ | 59.60 |
|
| 3 Way Collar | Floor sold price (put) | | 80 |
| | January 2021 - December 2021 | | $ | 37.50 |
|
| 3 Way Collar | Floor purchase price (put) | | 80 |
| | January 2021 - December 2021 | | $ | 47.50 |
|
| 3 Way Collar | Ceiling sold price (call) | | 80 |
| | January 2021 - December 2021 | | $ | 59.30 |
|
| | | | | | | | |
| Oil Collar | Floor purchase price (put) | | 512 |
| | January 2020 - December 2020 | | $ | 49.50 |
|
| Oil Collar | Ceiling sold price (call) | | 512 |
| | January 2020 - December 2020 | | $ | 63.87 |
|
| Oil Collar | Floor purchase price (put) | | 742 |
| | January 2021 - December 2021 | | $ | 50.00 |
|
| Oil Collar | Ceiling sold price (call) | | 742 |
| | January 2021 - December 2021 | | $ | 59.70 |
|
| | | | | | | | |
| Description | | | Notional Volume (MMBtus/d) | | Production Period | | Weighted Average Price ($/MMBtu) |
| Natural Gas Positions | | | | | | |
| | | | | | | | |
| Gas Swaps | | | 4,557 |
| | January 2020 - December 2020 | | $ | 2.57 |
|
| Gas Swaps | | | 4,184 |
| | January 2021 - March 2021 | | $ | 2.77 |
|
| | | | | | | | |
| 3 Way Collar | Floor sold price (put) | | 563 |
| | January 2020 - December 2020 | | $ | 1.60 |
|
| 3 Way Collar | Floor purchase price (put) | | 563 |
| | January 2020 - December 2020 | | $ | 2.10 |
|
| 3 Way Collar | Ceiling sold price (call) | | 563 |
| | January 2020 - December 2020 | | $ | 3.00 |
|
| 3 Way Collar | Floor sold price (put) | | 133 |
| | January 2021 - December 2021 | | $ | 1.65 |
|
| 3 Way Collar | Floor purchase price (put) | | 133 |
| | January 2021 - December 2021 | | $ | 2.15 |
|
| 3 Way Collar | Ceiling sold price (call) | | 133 |
| | January 2021 - December 2021 | | $ | 3.05 |
|
| Gas Collar | Floor purchase price (put) | | 2,748 |
| | January 2020 - December 2020 | | $ | 2.55 |
|
| Gas Collar | Ceiling sold price (call) | | 2,748 |
| | January 2020 - December 2020 | | $ | 3.07 |
|
| Gas Collar | Floor purchase price (put) | | 4,464 |
| | January 2021 - December 2021 | | $ | 2.20 |
|
| Gas Collar | Ceiling sold price (call) | | 4,464 |
| | January 2021 - December 2021 | | $ | 2.97 |
|
| |
(1) | The weighted average price under these basis swaps is the fixed price differential between the index prices of the Midland WTI and the Cushing WTI. |
The table below summarizes the Company’s net gain (loss) on commodity derivatives for the year ended December 31,
2015.On2019 and 2018:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| | (in thousands) |
| Unrealized gain (loss) on unsettled derivatives | $ | (5,575 | ) | | $ | 1,977 |
|
| Net settlements paid on derivative contracts | (3,214 | ) | | (2,742 | ) |
| Net settlements receivable (payable) on derivative contracts | (196 | ) | | 820 |
|
| Net gain (loss) on commodity derivatives | $ | (8,985 | ) | | $ | 55 |
|
The following information summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s consolidated balance sheets as of December 31, 2019 and as of December 31, 2018:
|
| | | | | | | | | | | |
| | As of December 31, 2019 |
| | Gross Amount of Recognized Assets and Liabilities | | Gross Amounts Offset in the Consolidated Balance Sheets | | Net Amounts Presented in the Consolidated Balance Sheets |
| | (In thousands) |
| Offsetting Derivative Assets: | | | | | |
| Current assets | $ | 1,009 |
| | $ | (582 | ) | | $ | 427 |
|
| Long-term assets | 359 |
| | (172 | ) | | 187 |
|
| Total assets | $ | 1,368 |
| | $ | (754 | ) | | $ | 614 |
|
| Offsetting Derivative Liabilities: | | | | | |
| Current liabilities | $ | (4,827 | ) | | $ | 582 |
| | $ | (4,245 | ) |
| Current embedded derivative liabilities | (799 | ) | | — |
| | (799 | ) |
| Long-term commodity derivative liabilities | (172 | ) | | 172 |
| | — |
|
| Long-term embedded derivative liabilities | (2,439 | ) | | — |
| | (2,439 | ) |
| Total liabilities | $ | (8,237 | ) | | $ | 754 |
| | $ | (7,483 | ) |
| | | | | | |
|
| | | | | | | | | | | |
| | As of December 31, 2018 |
| | Gross Amount of Recognized Assets and Liabilities | | Gross Amounts Offset in the Consolidated Balance Sheets | | Net Amounts Presented in the Consolidated Balance Sheets |
| | (In thousands) |
| Offsetting Derivative Assets: | | | | | |
| Current assets | $ | 4,122 |
| | $ | (1,571 | ) | | $ | 2,551 |
|
| Long-term assets | 1,854 |
| | (32 | ) | | 1,822 |
|
| Total assets | $ | 5,976 |
| | $ | (1,603 | ) | | $ | 4,373 |
|
| Offsetting Derivative Liabilities: | | | | | |
| Current liabilities | $ | (2,086 | ) | | $ | 1,571 |
| | $ | (515 | ) |
| Long-term commodity derivative liabilities | (2,766 | ) | | 32 |
| | (2,734 | ) |
| Long-term embedded derivative liabilities | (1,965 | ) | | — |
| | (1,965 | ) |
| Total liabilities | $ | (6,817 | ) | | $ | 1,603 |
| | $ | (5,214 | ) |
NOTE 10 - LEASES
Lease Recognition
The Company has entered into contractual lease arrangements to rent office space, compressors, drilling rigs and other equipment from third-party lessors. Right-of-use (“ROU”) assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make future lease payments arising from the lease. Operating lease ROU assets and liabilities are recorded at commencement date based on the present value of lease payments over the lease term. Lease payments included in the measurement of the lease liability include fixed payments and termination penalties or extensions that are reasonably certain to be exercised. Variable lease costs associated with leases are recognized when incurred and generally represent maintenance services provided by the lessor, allocable real estate taxes and local sales and business taxes. Leases with an initial term of 12 months or less are not recorded on the balance sheet. The Company recognizes lease expense on a straight-line basis over the lease term. The Company does not account for lease components separately from the non-lease components. The Company uses the implicit interest rate when readily determinable; however, most of the Company’s lease agreements do not provide an implicit interest rate. As such, at implementation and for new or modified leases subsequent to January 8, 2015,1, 2019, the Company uses its incremental borrowing rate based on the information available at commencement date of the contract in determining the present value of future lease payments. The incremental borrowing rate is calculated using a risk-free interest rate adjusted for the Company’s risk. Operating lease ROU assets also include any lease incentives received in the recognition of the present value of future lease payments. Certain of the Company’s leases may also include escalation clauses or options to extend or terminate the lease. These options are included in the present value recorded for the leases when it is reasonably certain that the Company will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term.
The Company determines if an arrangement is or contains a lease at inception of the contract and records the resulting operating lease asset on the consolidated balance sheets as an asset, with offsetting liabilities recorded as a liability. The Company recognizes a lease in the consolidated financial statements when the arrangement either explicitly or implicitly involves property or equipment, the contract terms are dependent on the use of the property or equipment, and the Company has the ability or right to operate the property or equipment or to direct others to operate the property or equipment and receives greater than 10% of the economic benefits of the assets. As of December 31, 2019, the Company does not have any financing leases.
The Company has adopted the modified retrospective method for the new lease recognition rule. Therefore, prior periods are not presented as prior period amounts have not been adjusted under the modified retrospective. Refer to Note 3 - Basis of Presentation and Summary of Significant Accounting Policies for additional information.
The Company’s ROU assets and operating lease liabilities were included in the consolidated balance sheets as follows (in thousands):
|
| | | | |
| | | December 31, 2019 |
| Right of use assets: | | |
Right of use assets - long-term (1) | | $ | 1,722 |
|
| | |
| Lease liabilities: | | |
Lease liabilities - current (2) | | $ | 412 |
|
Lease liabilities - long-term (3) | | 1,323 |
|
| Total lease liabilities | | $ | 1,735 |
|
(1) Right of use assets - long-term are included in other assets on the consolidated balance sheets.
(2) Lease liabilities - current are included in accrued liabilities and other on the consolidated balance sheets.
(3) Lease liabilities - long-term are included in long-term derivatives instruments and other non-current liabilities on the consolidated balance sheets.
During the second quarter of 2019, the Company canceled a long-term drilling rig lease, within the terms of the agreement, which resulted in the write-off of the related lease liability and ROU asset of $5.4 million.
During the third quarter of 2019, the Company entered into
a new long-term drilling rig lease which resulting in a lease liability and ROU asset of $10.8 million. During the
Credit Agreement. In connection with the Credit Agreement,4th quarter of 2019, the Company
issued to Heartland a warrant to purchase up to 22,500 shares of Common Stock at an adjusted exercise price of $4.05 withcanceled the
initial advance, which contains an anti-dilution feature that will automatically reducelong-term drilling rig lease, within the
exercise price if the Company enters into another agreement pursuant to which warrants are issued with a lower exercise price.
On December 31, 2015, the Company revalued the warrants issued to the Heartland Bank using the following variables: (i) 22,500 warrants issued; (ii) stock price of $2.00; (iii) exercise price of $ 25.00; (iv) expected life of 4.0 years; (v) volatility of 100%; (vi) risk free rate of 1.5% for a total value of $12,000, which adjusted the change in fair value valuationterms of the derivative by $12,000agreement, which resulted in the write-off of the related lease liability and ROU asset of $10.4 million.
Lease costs represent the straight line lease expense of ROU assets, short-term leases, and variable lease costs. The components of lease cost were classified as follows (in thousands):
|
| | | |
| | Year Ended December 31, 2019 |
| Fixed lease costs | $ | 5,084 |
|
| Short-term lease costs | 1,096 |
|
| Variable lease costs | 575 |
|
| Total lease costs | $ | 6,755 |
|
|
| | | | |
| Lease Cost included in the Consolidated Financial Statements | | Year Ended December 31, 2019 |
Oil and natural gas properties, full cost method of accounting, net (1) | |
|
| Total lease costs capitalized | | $ | 5,688 |
|
| | | |
| Production costs | | 593 |
|
| General and administrative | | 474 |
|
| Total lease costs expensed | | 1,067 |
|
| Total lease costs | | $ | 6,755 |
|
(1) Represents short-term lease capital expenditures related to drilling rigs for the year ended December 31, 2015. On December 31, 2016, the Company revalued the warrants using the following variables: (i) 22,500 warrants issued; (ii) stock price of $3.10; (iii) adjusted exercise price of $ 4.05; (iv) expected life of 3.02 years; (v) volatility of 101%; (vi) risk free rate of 1.5% for a total value of approximately $42,000, which adjusted the change in fair value valuation of the derivative by $18,675 for2019.
During the year ended December 31,
2016.
2019, the following cash activities were associated with the Company’s leases as follows (in thousands): |
| | | | |
| Cash paid for amounts included in the measurement of operating lease liabilities: | | |
| Operating cash flows from operating leases | | $ | 222 |
|
| Investing cash flows from operating leases | | $ | 4,768 |
|
As of December 31, 2019, the weighted average lease term and discount rate related to the Company’s remaining leases were as follows:
|
| F-16 | | |
| Lease term and discount rate |
| Weighted-average remaining lease term (years) | | 4.45 |
|
| Weighted-average discount rate | | 5.3 | % |
Pursuant
As of December 31, 2019, minimum future payments, including imputed interest, for long-term operating leases under the scope of ASC Topic 842, “Leases”, were as follows (in thousands):
|
| | | | |
| Year | | Amount |
| 2020 | | $ | 477 |
|
| 2021 | | 425 |
|
| 2022 | | 353 |
|
| 2023 | | 379 |
|
| 2024 | | 315 |
|
| After 2024 | | — |
|
| Less: the effects of discounting | | (214 | ) |
| Present value of lease liabilities | | $ | 1,735 |
|
As of December 31, 2018, minimum future payments, including imputed interest, for long-term operating leases under the scope of ASC Topic 840, “Leases”, were as follows (in thousands):
|
| | | | |
| Year | | Amount |
| 2019 | | $ | 7,586 |
|
| 2020 | | 66 |
|
| 2021 | | — |
|
| 2022 | | — |
|
| 2023 | | — |
|
| After 2023 | | — |
|
| Total lease commitment | | $ | 7,652 |
|
NOTE 11 - LONG-TERM DEBT
|
| | | | | | | | |
| | | December 31, |
| | | 2019 | | 2018 |
| | | (In thousands) |
| 8.25% Second Lien Term Loan, due 2021, net of debt issuance costs and debt discount | | $ | — |
| | $ | 82,804 |
|
| Revolving Credit Agreement, due October 2023 | | 115,000 |
| | 75,000 |
|
| Total long-term debt | | $ | 115,000 |
| | $ | 157,804 |
|
| Less: current portion | | (115,000 | ) | | — |
|
| Total long-term debt, net of current portion | | $ | — |
| | $ | 157,804 |
|
Revolving Credit Agreement
On October 10, 2018, the Company entered into a five-year, $500.0 million senior secured revolving credit agreement by and among the Company, as borrower, certain subsidiaries of the Company, as guarantors (the “Guarantors”), BMO Harris Bank, N.A., as administrative agent, and the lenders party thereto (the “Revolving Credit Agreement”). The Revolving Credit Agreement provides for a senior secured reserves based revolving credit facility with an initial borrowing base of $95.0 million. The borrowing base is subject to semiannual re-determinations in May and November of each year. In December 2018, the borrowing base was increased to $108.0 million in connection with our scheduled borrowing base re-determination. On March 5, 2019, the Company’s borrowing base under the Revolving Credit Agreement was increased from $108.0 million to $125.0 million, as the result of an acceleration of the scheduled May 2019 borrowing base redetermination pursuant to the Merger AgreementFirst Amendment (as defined below). As provided in the Third Amendment (as defined below) and as a conditionresult of the Asset Sales (as defined in Note 5 - Acquisitions and Divestitures), in July 2019, the borrowing base was decreased to $115.0 million. As provided for in the Seventh Amendment and as a result of a decrease in commodity prices, on January 17, 2020, the borrowing base was decreased to $90.0 million. The reduction in the borrowing base resulted in a borrowing base deficiency as of January 17, 2020, of $25.0 million. We have made scheduled repayments of $17.3 million and the remaining $7.8 million is due on June 5, 2020.
Borrowings under the Revolving Credit Agreement bear interest at a floating rate of either LIBOR or a specified base rate plus a margin determined based upon the usage of the borrowing base. The Company is required to pay a commitment fee of 0.5% per annum on any unused portion of the borrowing base. The Company’s obligations under the Revolving Credit Agreement are secured by first priority liens on substantially all of the Company’s and the Guarantors’ assets and are unconditionally guaranteed by each of the Guarantors.
As of December 31, 2019, outstanding borrowings under the Revolving Credit Agreement were $115.0 million. The Revolving Credit Agreement also provides for issuance of letters of credit in an aggregate amount of up to $5.0 million. As of December 31, 2019, we were fully drawn against the borrowing base under our Revolving Credit Agreement, with $115.0 million of indebtedness outstanding under our Revolving Credit Agreement, classified as current liability due to uncertainty of the Company’s ability to meet debt covenants over the next twelve months.
The Company capitalizes certain direct costs associated with the debt issuance under the Revolving Credit Agreement and amortizes such costs over the term of the debt instrument. The deferred financing costs related to the
Fourth Amendment (defined below), the Company was required to make a cash payment of $500,000, issue the SOS Note and the SOS Warrant. The SOS Warrant contains a price protection feature that will automatically reduce the exercise price if the Company enters into another financing agreement pursuant to which warrantsRevolving Credit Agreement are
issued with a lower exercise price after June 23, 2016. This initial value of $164,000 was recorded as additional Merger consideration. On December 31, 2016, the Company evaluated the SOS Warrant using the following variables: (i) stock price of $3.10 (ii) exercise price of $25.00 (iii) contractual life of 1.48 years; (iv) volatility of 101%; (v) risk free rate of 1.02% for a total value of approximately $144,000, which adjusted the fair value valuation of the derivative by approximately $284,000 forclassified in assets. For the year ended December 31,
2016.Debentures Conversion Derivative Liability
As of December 31, 2015,2019 and 2018, the Company had $6.85 million in remaining Debentures, which, subject to stockholder approval, were convertible at any time at the holders’ option into shares of Common Stock at $20.00 per share, or 342,323 underlying conversion shares prior to the execution of the Debenture Conversion Agreement. The Debentures have elements of a derivative due to the potential for certain adjustments, including both the conversion option and the price protection embedded in the Debentures. The conversion option allows the Debenture holders to convert their Debentures to underlying Common Stock at a conversion price of $20.00 per share, subject to certain adjustments, including the requirement to reset the conversion for any subsequent offering at a lower price per share amount. The Company values this conversion liability at each reporting period using a Monte Carlo pricing model.
On June 23, 2016, pursuant to the terms of the Debenture Conversion Agreement, dated December 29, 2015, the Company's remaining outstanding 8% Convertible Debentures (the “Debentures”) of approximately $6,846,000 converted automatically upon consummation of the Merger. The conversion price was modified from $20.00 per share to $5.00 per share, resulting in theamortized debt issuance of 1,369,293 shares of Common Stock. Upon the conversion of the Debentures, the associated conversion liability of approximately $43,000 was reclassified to additional paid-in capital. At December 31, 2016 and 2015, the Company valued the conversion featurecosts associated with the Debentures at $0Revolving Credit Agreement of $0.8 million and $6,000,$2.2 million, respectively. As of December 31, 2016,2019, the remaining debentures were fully converted into 1,369,293 shares
Company had $2.6 million of
the Company’s common stock.The following table provides a summary of the recurring fair values of assets and liabilities measured at fair value(unamortized deferred financing costs in thousands):
| December 31, 2016 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| Recurring fair value measurements: | | | | | | | | | | | | | | | | |
| Warrant liabilities | | | - | | | | - | | | | (1,400 | ) | | | (1,400 | ) |
| Total recurring fair value measurements | | $ | - | | | $ | - | | | $ | (1,400 | ) | | $ | (1,400 | ) |
| December 31, 2015 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| Recurring fair value measurements: | | | | | | | | | | | | | | | | |
| Executive employment agreement | | $ | - | | | $ | - | | | $ | (223 | ) | | $ | (223 | ) |
| Warrant liabilities | | | - | | | | - | | | | (56 | ) | | | (56 | ) |
| Convertible debenture conversion derivative liability | | | - | | | | - | | | | (6 | ) | | | (6 | ) |
| Total recurring fair value measurements | | $ | - | | | $ | - | | | $ | (285 | ) | | $ | (285 | ) |
The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities asother current assets. As of December 31, 20162018, the Company had $0.5 million and 2015($1.7 million of unamortized deferred financing costs in thousands):
| | | Conversion
derivative
liability | | | Bristol/
Heartland/SOS
warrant liability | | | Incentive
bonus | | | Total | |
| | | | | | | | | | | | | |
| Balance at January 1, 2016 | | $ | (6 | ) | | $ | (56 | ) | | $ | (223 | ) | | $ | (285 | ) |
| Additional liability | | | - | | | | (164 | ) | | | (393 | ) | | | (557 | ) |
| Reversal of accrued bonus | | | - | | | | - | | | | 718 | | | | 718 | |
| Converted to equity | | | (54 | ) | | | - | | | | - | | | | (54 | ) |
| Change in fair value of liability | | | 60 | | | | (1,180 | ) | | | (102 | ) | | | (1,222 | ) |
| Balance at December 31, 2016 | | $ | - | | | $ | (1,400 | ) | | $ | - | | | $ | (1,400 | ) |
| | | Conversion
derivative
liability | | | Bristol/Heartland warrant
liability | | | Incentive
bonus | | | Total | |
| | | | | | | | | | | | | |
| Balance at January 1, 2015 | | $ | (1,249 | ) | | $ | (394 | ) | | $ | (40 | ) | | $ | (1,683 | ) |
| Additional liability | | | - | | | | (56 | ) | | | (149 | ) | | | (205 | ) |
| Change in fair value of liability | | | 1,243 | | | | 394 | | | | (34 | ) | | | 1,603 | |
| Balance at December 31, 2015 | | $ | (6 | ) | | $ | (56 | ) | | $ | (223 | ) | | $ | (285 | ) |
Assets and liabilities measured at fair value on a nonrecurring basis.Certainother current assets and liabilities are measured at fair valuenon-current assets, respectively.
The Revolving Credit Agreement matures on
a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, butOctober 10, 2023. Borrowings under the Revolving Credit Agreement are subject to
fair value adjustmentsmandatory repayment in certain
circumstances. These assetscircumstances, including upon certain asset sales and
liabilities can include proveddebt incurrences or if a borrowing base deficiency occurs. The Company also may voluntarily repay borrowings from time to time and,
unproved oil and gas propertiessubject to the borrowing base limitation and other
long-lived assetscustomary conditions, may re-borrow amounts that are
written down to fair value when they are impairedvoluntarily repaid. Mandatory and voluntary repayments generally will be made without premium or
held for sale.Proved oil and gas properties. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such amountspenalty.
Pursuant to the carrying amountFourteenth Amendment to the Revolving Credit Agreement, our next borrowing base redetermination is scheduled to occur on or about June 5, 2020. If the borrowing base is further reduced by the lenders in connection with this redetermination, we will be required to repay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to determinesecure our obligations under the Revolving Credit Agreement. Under the Revolving Credit Agreement, we have the option to affect such repayment either in full within 30 days after the redetermination or in monthly installments over a six-month period after the redetermination.
The Revolving Credit Agreement contains certain customary representations and warranties and affirmative and negative covenants, including covenants relating to: maintenance of books and records; financial reporting and notification; compliance with laws; maintenance of properties and insurance; and limitations on incurrence of indebtedness, liens, fundamental changes, international operations, asset sales, certain debt payments and amendments, restrictive agreements, investments, dividends and other restricted payments and hedging. It also requires the Company to maintain a ratio of Total Debt to EBITDAX (each as defined in the Revolving Credit Agreement) (the “Leverage Ratio”) of not more than 4.00 to 1.00 and a ratio of Current Assets to Current Liabilities (each as defined in the Revolving Credit Agreement) (the “Current Ratio”) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter.
Compliance with the Current Ratio and Leverage Ratio covenants in future periods depends on our ability to keep wells online and consistently flowing to sales, commodity prices, our ability to control costs, and if
the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscountednecessary, our ability to complete sales of non-core assets or access other sources of capital to reduce indebtedness. However, our future cash flows,
the Company will adjust the carrying amount of the oil and
natural gas properties to fair value. The factors used to determine fair valueconsequently our EBITDAX, are subject to
management’s judgementa number of variables, including uncertainty in forecasted production volumes and
expertisecommodity prices, and
include, but arewe may not
limitedbe able to
recentcomplete sales
prices of
comparable properties,non-core assets or access other sources of capital on acceptable terms or at all. As of December 31, 2019, the
present value of future cash flows, net of estimated operating and development costs using estimates or proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurateCompany was not in compliance with the
riskLeverage Ratio and
current market conditions associated with realizingCurrent Ratio covenants. Pursuant to the
expected cash flows projected. These assumptions represent Level 3 inputs. Impairment of oil and gas assets for the year ended December 31, 2016 and 2015 was $4.7 million and $24.5 million, respectively.The following table provides a summary of the non-recurring fair values of assets and liabilities measured at fair value(in thousands):
| December 31, 2016 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| Non-recurring fair value measurements | | | | | | | | | | | | | | | | |
| Impairment of proved oil and gas properties | | | - | | | | - | | | | 4,700 | | | | 4,700 | |
| Total non-recurring fair value measurements | | $ | - | | | $ | - | | | $ | 4,700 | | | $ | 4,700 | |
| | | | | | | | | | | | | | | | | |
December 31, 2015 | | | | | | | | | | | | | | | | |
| Non-recurring fair value measurements | | | | | | | | | | | | | | | | |
| Impairment of proved oil and gas properties | | | - | | | | - | | | | 24,500 | | | | 24,500 | |
| Total non-recurring fair value measurements | | $ | - | | | $ | - | | | $ | 24,500 | | | $ | 24,500 | |
The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the years ended December 31, 2016 and 2015.
NOTE 7 – ASSET RETIREMENT OBLIGATIONS (ARO)
The information below reconciles the value of the asset retirement obligation for the periods presented (in thousands):
| | | Year Ended December 31, | |
| | | 2016 | | | 2015 | |
| | | (In thousands) | |
| Balance, beginning of year | | $ | 208 | | | $ | 200 | |
| Liabilities assumed from the Merger | | | 777 | | | | - | |
| Liabilities incurred | | | 311 | | | | - | |
| Accretion expense | | | 132 | | | | 10 | |
| Conveyance of liability with oil and gas properties conveyance | | | (92 | ) | | | - | |
| Change in estimate | | | (79 | ) | | | (1 | ) |
| Balance, end of year | | | 1,257 | | | | 209 | |
| Less: current portion of ARO at end of year | | | (338 | ) | | | - | |
| Total Long-term ARO at end of year | | $ | 919 | | | $ | 209 | |
NOTE 8 – LONG-TERM DEBTS
| | | As of December 31, | |
| | | 2016 | | | 2015 | |
| | | (In thousands) | |
| Term Loan: | | | | | | | | |
| 6% Senior Secured Term Loan, due 2019, net of deferred financing costs and debt discount | | $ | 29,214 | | | $ | - | |
| Senior Secured Term Loan, interest at prime rate, due 2018, net of deferred financing costs and debt discount | | | - | | | | 2,492 | |
| 6% note payable to SOS Investment, LLC, due 2019 | | | 1,000 | | | | - | |
| Convertible Notes: | | | | | | | | |
| 12% convertible related party note, due 2016, net of deferred financing costs and debt discount | | | - | | | | 1,055 | |
| 12% convertible non-related party note, due 2016, net of deferred financing costs and debt discount | | | - | | | | 674 | |
| Convertible Debentures: | | | | | | | | |
| 8% convertible debentures, due 2018, net of deferred financing costs and debt discount | | | | | | | 6,846 | |
| Other notes payable | | | 29 | | | | - | |
| | | $ | 30,243 | | | $ | 11,067 | |
| Less: current portion | | | (17 | ) | | | (11,067 | ) |
| | | $ | 30,226 | | | $ | - | |
Credit and Guarantee Agreement
On September 29, 2016,Twelfth Amendment, the Company entered intoobtained a credit and guaranty agreement (the “Credit and Guarantee Agreement”) by and amongwaiver from the Company andrequisite lenders of its wholly owned subsidiaries, Brushy, ImPetro Operating, LLC (“Operating”) and ImPetro Resources, LLC (“Resources”, and together with Brushy and Operating, the “Initial Guarantors”), and the lenders party thereto (each a “Lender” and together, the “Lenders”) and T.R. Winston & Company, LLC (“TRW”) acting as collateral agent.
The Credit and Guarantee Agreement provides for a three-year senior secured term loan with initial commitments of $31 million, of which $25 million was collected as of September 30, 2016, and the additional $6 million was collected at December 31, 2016. The initial aggregate principal amount may be increased to a maximum principal amount of $50 million at the Company’s request andcompliance with the consent of the Lenders holding loans in excess of 60% of the then outstanding loans pursuant to an accordion advance provision in the CreditLeverage Ratio and Guarantee Agreement (the “Term Loan”).
In connection with the Company’s entry into the Credit and Guarantee Agreement, it incurred commitment fees to each of the Lenders equal to 2.0% of their respective initial loan advances and advisory fees totaled to approximately $1.2 millionCurrent Ratio covenants as of December 31, 2016. The2019.
As of March 31, 2020, the Company accounted forwas not in compliance with the $1.2 millionLeverage Ratio and Current Ratio covenants. Pursuant to the Fourteenth Amendment (as defined in Note 11 - Long-Term Debt), the Company obtained a waiver from the requisite lenders of its compliance with the Leverage Ratio and Current Ratio covenants as deferred financing costsof March 31, 2020. As the Company is not expecting to be amortized overable to meet future covenants without obtaining additional sources of liquidity, the term of the loan. As partial consideration given to the lenders, we also amended certain warrants issued in the Series B preferred stock offering held by the lenders during the third and fourth quarters of the year ended December 31, 2016, to purchase up to an aggregateoutstanding amount of approximately 2,850,000 and approximately 672,000, shares of common stock respectively, such that the exercise price per share was lowered from $2.50 to $0.01 on such warrants. The portion repriced in the fourth quarter was due to certain delayed funding that occurred after the initial commitment. Additionally, each lender received a 2.0% commitment fee equal to their respective initial loan advance. All of the amended warrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions. The Company accounted for the reduction in the conversion priceour Revolving Credit Agreement as a debt discount of $714,000 and will be accreted over the term of the loan. For the year ended December 31, 2016, the Company amortized approximately $108,000 of deferred financing costs and accreted approximately $119,000 of debt discount relating to the loan. These amounts were recorded as a component of non-cash interest expense. As of December 31, 2016, the unamortized portion of the debt discount2019 has been classified as current. See Note 2 - Liquidity and deferred financing costs were $0.6 million and $1.2 million, respectively.Going Concern, for additional information. The
Term Loan bears interest at a rate of 6.0% per annum and matures on September 30, 2019. The Company has the right to prepay the Term Loan, in whole or in part, at any time at a prepayment premium equal to 6.0% of the amount repaid. Such prepayment premium must also be paid if the Term Loan is repaid prior to maturity as a result of a change in control. In certain situations, theRevolving Credit
and Guarantee Agreement requires mandatory prepayments of the Term Loans at the request of the Lenders, including in the event of certain non-ordinary course asset sales, the incurrence of certain debt, and receipt of proceeds in connection with insurance claims.The Credit and Guarantee Agreement also provides for events of default, including failure to pay any principal, interest or interestother amounts when due, failure to perform or observe covenants, cross-default on certain outstanding debt obligations, inaccuracy of representations and warranties, certain Employee Retirement Income Security Act or “ERISA” events, change of control, the failure of a Guarantorsecurity documents or guaranty ceasing to comply with the provisions of its Guaranty,be effective, and bankruptcy or insolvency events. The amountsevents, subject to customary cure periods. Amounts owed by the Company under the Revolving Credit Agreement could be accelerated and bebecome immediately due and payable uponfollowing the occurrence of an event of default.
SOS Investment LLC
The Revolving Credit Agreement also provides for the Company to have and maintain Swap Agreements (as defined in the Revolving Credit Agreement) in respect of crude oil and natural gas, on not less than 75% of the projected production from proved reserves classified as “Developed Producing Reserves” attributable to the oil and natural gas properties of the Company, as reflected in the most recently delivered reserves report, for a period through at least 24 months after the end of each applicable quarter. For further information on our hedges, see NoteOn 9 - Derivatives
. Pursuant to the Twelfth Amendment, the Company obtained a waiver from the requisite lenders of the requirement to comply with certain hedging obligations set forth in the Credit Agreement until the quarter ending June 30, 2016,2020.
First Amendment and Waiver to Revolving Credit Agreement
On March 1, 2019, the Company entered into a First Amendment and Waiver (the “First Amendment”) to the Revolving Credit Agreement. Among other matters, the First Amendment provided for the acceleration of the scheduled May 2019 redetermination of the borrowing base described above, which became effective on March 5, 2019 upon closing of the transactions contemplated by the 2019 Transaction Agreement (as defined below), including the satisfaction in full, as described below, of the Second Lien Term Loan under the Second Lien Credit Agreement (as defined below). The First Amendment also provides for the July 2019 scheduled redetermination of the borrowing base described above.
In addition, the First Amendment provided for a limited waiver of compliance by the Company with the Leverage Ratio covenant in the Revolving Credit Agreement as of December 31, 2018. Further, in connection with the satisfaction in full of the Second Lien Term Loan and the termination of the Second Lien Credit Agreement, the First Amendment amended the maturity date provisions of the Revolving Credit Agreement to eliminate any springing maturity under the Revolving Credit Agreement tied to the maturity of the Second Lien Credit Agreement, resulting in a fixed maturity date under the Revolving Credit Agreement of October 10, 2023. The First Amendment also effected certain other ministerial and conforming amendments to the Revolving Credit Agreement related to the transactions contemplated by the 2019 Transaction Agreement and required payment by the Company to the lenders of customary fees.
Second Amendment and Waiver to Revolving Credit Agreement
On May 6, 2019, the Company entered into a Second Amendment and Waiver (the “Second Amendment”) to the Revolving Credit Agreement, pursuant to which the Mergerrequisite lenders under the Revolving Credit Agreement waived compliance by the Company with the Current Ratio covenant as of March 31, 2019 in exchange for a customary consent fee. Additionally, the Second Amendment provided for a 25-basis point increase in the interest rate margin applicable to loans under the Revolving Credit Agreement if the Company’s Leverage Ratio is equal to or greater than 3.00 to 1.00. The Second Amendment also provides that if the Company has available cash and cash equivalents (subject to certain carveouts) in excess of $10 million for a period of at least five consecutive business days, then it must prepay the loans under the Revolving Credit Agreement in the amount of such excess.
Third Amendment and Waiver to Revolving Credit Agreement
On July 26, 2019, the Company entered into a Third Amendment (the “Third Amendment”) to the Revolving Credit Agreement, pursuant to which the requisite required lenders under the Revolving Credit Agreement agreed to reduce the borrowing base to $115 million from $125 million as a part of the scheduled July 1, 2019 redetermination and as a result of the Asset Sales; to give pro forma effect to the Asset Sales for the calculation of EBITDAX, Total Debt, and Current Liabilities at June 30, 2019; and, subject to the consummation of the Asset Sales completed on July 31, 2019 and the required use of the proceeds, to amend the Current Ratio to be not less than 0.85 to 1.00 on September 30, 2019, rather than the minimum Current Ratio of 1.00 to 1.00 required otherwise. Additionally, the Third Amendment provides for, among other things, an increase in the required amount hedged to 75% of projected production from proved reserves classified as “Developed Producing Reserves”. The Third Amendment also effected certain other ministerial changes to the Revolving Credit Agreement and required payment by the Company to the lenders of customary fees.
Fourth Amendment and Waiver to Revolving Credit Agreement
On November 5, 2019, the Company entered into a Fourth Amendment and Waiver (the “Fourth Amendment”) to the Revolving Credit Agreement, pursuant to which, among other matters, the requisite lenders under the Revolving Credit Agreement waived compliance by the Company with the Leverage Ratio covenant as of September 30, 2019 in exchange for a customary consent fee. Additionally, the Fourth Amendment modified the Leverage Ratio for future periods by modifying the manner in which EBITDAX is calculated for the periods ending December 31, 2019, March 31, 2020 and June 30, 2020 such that EBITDAX is calculated on an annualized basis for those periods, excluding quarterly periods ended prior to December 31, 2019. The Fourth Amendment also (1) requires the Company to use 100% of net cash proceeds from dispositions to repay borrowings until completion of the scheduled November 1, 2019 redetermination or during a borrowing base deficiency, (2) added completion of the scheduled November 1, 2019 redetermination as a condition precedent to future borrowings and (3) limits certain exceptions to certain of the negative covenants under the Revolving Credit Agreement during the period from the date of the Fourth Amendment to the date on which annual financial statements for the fiscal year ending December 31, 2019 are delivered.
Fifth Amendment and Waiver to Revolving Credit Agreement
On November 27, 2019, the Company wasentered into a Fifth Amendment (the “Fifth Amendment”) to the Revolving Credit Agreement dated as of October 10, 2018 which provides that the semi-annual redetermination of the borrowing base under the Revolving Credit Agreement previously scheduled to occur on or about November 1, 2019 (the “Fall 2019 Scheduled Redetermination”) will instead occur on December 16, 2019. Additionally, among other matters, the Fifth Amendment shortened the period over which the Company may repay in installments any borrowing base deficiency that may exist as a result of the Fall 2019 Scheduled Redetermination, as described below.
Under the Revolving Credit Agreement, a borrowing base deficiency will occur if the amounts outstanding under the Revolving Credit Agreement exceed the borrowing base then in effect. If a borrowing base deficiency occurs, the Company is required to makerepay borrowings in excess of the borrowing base or eliminate the borrowing base deficiency by pledging additional oil and natural gas properties to secure its obligations under the Revolving Credit Agreement. The Company has the option to effect such repayment either (1) in full within 30 days after the redetermination or (2) in monthly installments over a cashperiod of, except as amended by the Fifth Amendment, six months, commencing 30 days after the redetermination. The Fifth Amendment provides that, for a borrowing base deficiency that exists as a result of the Fall 2019 Scheduled Redetermination only, the period over which the Company may repay the amount of the deficiency in installments will be four months, rather than six months, commencing 30 days after the redetermination.
Sixth Amendment and Waiver to Revolving Credit Agreement
On December 16, 2019, the Company entered into a Sixth Amendment (the “Sixth Amendment”) to the Revolving Credit Agreement which provides that the semi-annual redetermination of the borrowing base under the Revolving Credit Agreement previously scheduled to occur on or about December 16, 2019 (the “Fall 2019 Scheduled Redetermination”) will instead occur on or about January 14, 2020. Additionally, among other matters, the Sixth Amendment provides that, if any borrowing base deficiency exists as a result of the Fall 2019 Scheduled Redetermination, the date on which the initial payment is due to cure such deficiency is the first business day after such deficiency, rather than 30 days after such deficiency.
Seventh Amendment to Revolving Credit Agreement
On January 17, 2020, the Company entered into a Seventh Amendment (the “Seventh Amendment”) to the Revolving Credit Agreement. The Seventh Amendment provided for the January 14, 2020 redetermination of the borrowing base under the Revolving Credit Agreement (the “Scheduled Redetermination”). As so redetermined, the borrowing base has been set at $90 million. As a result of the Scheduled Redetermination, a borrowing base deficiency in the amount of $25 million existed under the Revolving Credit Agreement (the “Borrowing Base Deficiency”). The Seventh Amendment required repayment of the Borrowing Base Deficiency in four equal monthly installments, with the first payment of $500,000$6.25 million scheduled to SOSV LLC,occur on January 24, 2020.
Eighth Amendment to Revolving Credit Agreement
On January 23, 2020, the Company entered into an Eighth Amendment (the “Eighth Amendment”) to the Revolving Credit Agreement. The Eighth Amendment, among other things, amended the Revolving Credit Agreement to provide that the due date for the first Installment Payment was extended from January 24, 2020 to February 7, 2020 and that the due dates for the subsequent Installment Payments are February 14, 2020, March 16, 2020 and April 14, 2020.
Ninth Amendment to Revolving Credit Agreement
On February 6, 2020, the Company entered into an Ninth Amendment (the “Ninth Amendment”) to the Revolving Credit Agreement. The Ninth Amendment amended the Revolving Credit Agreement to provide that the due date for the first Installment Payment is extended from February 7, 2020 to February 18, 2020 and the due date for the second Installment Payment is extended from February 14, 2020 to February 18, 2020. The due dates for the two subsequent Installment Payments remain March 16, 2020 and April 14, 2020.
Tenth Amendment to Revolving Credit Agreement
On February 14, 2020, the Company entered into an Tenth Amendment (the “Tenth Amendment”) to the Revolving Credit Agreement. The Tenth Amendment amended the Revolving Credit Agreement to provide that the due date for the first two Installment Payments is extended from February 18, 2020 to February 28, 2020 and the due dates for the two subsequent Installment Payments remain March 16, 2020 and April 14, 2020.
Eleventh Amendment to Revolving Credit Agreement
On March 13, 2020, the Company entered into an Eleventh Amendment (the “Eleventh Amendment”) to the Revolving Credit Agreement. The Eleventh Amendment amended the Revolving Credit Agreement to extend the due date for the $1.50 million installment of the Borrowing Base Deficiency from March 16, 2020 to March 30, 2020. The due date for the final installment of the Borrowing Base Deficiency remains April 14, 2020.
Twelfth Amendment to Revolving Credit Agreement
On March 30, 2020, the Company entered into a Twelfth Amendment (the “Twelfth Amendment”) to the Revolving Credit Agreement. The Twelfth Amendment amended the Revolving Credit Agreement to, among other things extend the due date for the $1.50 million installment of the Borrowing Base Deficiency from March 30, 2020 to April 14, 2020. The due date for the final installment of the Borrowing Base Deficiency remains April 14, 2020. The lenders under the Revolving Credit Agreement also executedwaived the requirement under the Revolving Credit Agreement that the Company comply with a subordinated promissory noteleverage ratio and a current ratio, in each case, as of December 31, 2019, and granted certain other waivers, including the requirement to comply with SOSV LLC,certain hedging obligations set forth in the Revolving Credit Agreement until June 30, 2020. Additionally, the lenders consented to an extension of an additional 45 days for $1the Company to provide its audited annual financial statements for the fiscal year ended December 31, 2019, and waived the requirement that such financial statements be delivered without a “going concern” or like qualification or exception.
Thirteenth Amendment to Revolving Credit Agreement
On April 14, 2020, the Company entered into a Thirteenth Amendment (the “Thirteenth Amendment”) to the Revolving Credit Agreement. The Thirteenth Amendment amended the Revolving Credit Agreement to extend the due date for the final $7.75 million installment of the Borrowing Base Deficiency from April 14, 2020 to April 21, 2020.
Fourteenth Amendment to Revolving Credit Agreement
On April 21, 2020, the Company entered into a Fourteenth Amendment (the “Fourteenth Amendment”) to the Revolving Credit Agreement. The Fourteenth Amendment, among other things, amended the Revolving Credit Agreement to extend the due date for the final $7.75 million installment of the Borrowing Base Deficiency from April 21, 2020 to June 5, 2020. The lenders under the Revolving Credit Agreement also waived the requirement under the Revolving Credit Agreement that the Company comply with a leverage ratio and a current ratio, in each case, as of March 31, 2020. Additionally, the lenders consented to defer the timing of the scheduled spring redetermination of the borrowing base under the Revolving Credit Agreement from on or about May 1, 2020 to on or about June 5, 2020.
Second Lien Credit Agreement
On April 26, 2017, the Company entered into a second lien credit agreement (the “Second Lien Credit Agreement”), by and among the Company, certain subsidiaries of the Company, as guarantors, Wilmington Trust, National Association, as administrative agent, and the lenders party thereto, consisting of certain private funds affiliated with Värde Partners, Inc. (“Värde”). The Second Lien Credit Agreement provided for convertible loans in an aggregate initial principal amount of up to $125 million in two tranches (together, the “Second Lien Term Loan”). The first tranche consisted of an $80 million term loan, which was fully drawn and funded on April 26, 2017. The second tranche consisted of up to $45 million in delayed-draw term loans, which was fully drawn and funded in October 2017. In November 2017, the Second Lien Credit Agreement was amended to increase the amount available for borrowing under the second tranche of the Second Lien Term Loan by $25 million, and the additional $25 million was fully drawn and funded in November 2017.
Prior to the satisfaction in full of the Second Lien Term Loan and the termination of the Second Lien Credit Agreement on March 5, 2019, as described below, the Second Lien Term Loan bore interest at an interesta rate of 6% per annum which maturesof 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 June 30, 2019. In conjunctioneach interest payment date, and had a maturity date of April 26, 2021.
Each tranche of the Second Lien Term Loan was separately convertible at any time, in full and not in part, at the option of Värde, as lead lender, as follows: (i) 70% of the principal amount, together with cash paymentaccrued and unpaid interest and the note,make-whole premium on such principal amount, would convert into a number of shares of the Company’s common stock determined by dividing the total of such principal amount, accrued and unpaid interest and make-whole premium by $5.50 (subject to certain customary adjustments, the “Conversion Price”); and (ii) 30% of the principal amount, together with accrued and unpaid interest and the make-whole premium on such principal amount, would convert on a dollar for dollar basis into a new term loan. Additionally, if the closing price of the Company’s common stock on the principal exchange on which it was traded had been at least 150% of the Conversion Price then in effect for at least 20 of the 30 immediately preceding trading days, the Company alsohad the option to convert the Second Lien Term Loan, in whole or in part, into a number of shares of its common stock determined by dividing the principal amount to be converted, together with accrued and unpaid interest on such principal amount, by the Conversion Price.
On October 10, 2018, the Company entered into a transaction agreement (the “2018 Transaction Agreement”) by and among the Company and certain private funds affiliated with Värde that were lenders under the Second Lien Credit Agreement (collectively, the “Värde Parties”), pursuant to which, among other matters, the Company issued 200,000 warrants atto the Värde Parties (i) an exerciseaggregate of 5,952,763 shares of its common stock and (ii) 39,254 shares of a newly created series of preferred stock of the Company, designated as “Series D 8.25% Convertible Participating Preferred Stock”, as consideration for the reduction by approximately $56.3 million of the outstanding principal amount of the Second Lien Term Loan under the Second Lien Credit Agreement, together with accrued and unpaid interest and the make-whole amount thereon totaling approximately $11.9 million.
On March 5, 2019, the Company entered into a transaction agreement (the “2019 Transaction Agreement”) by and among the Company and the Värde Parties pursuant to which, among other matters, the Company issued to the Värde Parties shares of two new series of its preferred stock and shares of its common stock, as consideration for the termination of the Second Lien Credit Agreement and the satisfaction in full, in lieu of repayment in cash, of the Second Lien Term Loan. Specifically, in exchange for satisfaction of the outstanding principal amount of the Second Lien Term Loan, accrued and unpaid interest thereon and the make-whole amount totaling approximately $133.6 million (the “Second Lien Exchange Amount”), the Company issued to the Värde Parties:
an aggregate of 55,000 shares of a newly created series of preferred stock of the Company, designated as “Series F 9.00% Participating Preferred Stock” (the “Series F Preferred Stock”), corresponding to $55 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value (as defined in Note 15 - Preferred Stock) of the shares of Series F Preferred Stock;
an aggregate of 60,000 shares of a newly created series of preferred stock of the Company, designated as “Series E 8.25% Convertible Participating Preferred Stock” (the “Series E Preferred Stock”), corresponding to $60 million of the Second Lien Exchange Amount based on the aggregate initial Stated Value (as defined in Note 15 - Preferred Stock) of the shares of Series E Preferred Stock; and
9,891,638 shares of common stock, corresponding to approximately $18.6 million of the Second Lien Exchange Amount, based on the closing price of $25.00. The Company accounted for the costCompany’s common stock on the NYSE American on March 4, 2019 of warrants$1.88.
Subsequent to this transaction, the Company’s long-term debt consists solely of $0.2 million as partborrowings under the Revolving Credit Agreement.
As a result of the Merger transaction costs satisfaction in full of the Second Lien Term Loan pursuant to the 2019 Transaction Agreement, the Company recorded a gain on extinguishment of debt of $7.1 million, which was recorded as an increase in additional paid in capital due to the Värde Parties, being existing shareholders of the Company.
Interest Expense
The components of interest expense are as follows (in thousands) for the year ended December 31, 2016.Independent Bank2019 and Promissory Note
On June 22, 2016, in connection with the completion2018:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| Interest on debt | $ | 6,488 |
| | $ | 2,975 |
|
| Net revenue payments on financing arrangement | 888 |
| | — |
|
| Paid-in-kind interest on term loans | 1,590 |
| | 12,213 |
|
| Amortization of debt financing costs | 803 |
| | 3,241 |
|
| Amortization of discount on term loans | 1,657 |
| | 14,398 |
|
| Total | $ | 11,426 |
| | $ | 32,827 |
|
NOTE 12 - LONG-TERM DEFERRED REVENUE LIABILITIES AND OTHER LONG-TERM LIABILITIES
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| | (in thousands) |
| Long-term deferred revenue liabilities | $ | 36,920 |
| | $ | 52,500 |
|
| Long-term deferred proceeds, WLR agreement | 13,061 |
| | — |
|
| Long-term deferred proceeds, WLWI agreement | 23,768 |
| | — |
|
| Other | — |
| | 13 |
|
| Total long-term deferred revenue liabilities and other long-term liabilities | $ | 73,749 |
| | $ | 52,513 |
|
SCM Water LLC’s Option to Exercise Purchase of
the Merger, the Company, Brushy and Independent Bank (the “Lender”), Brushy’s senior secured lender, entered into an amendment to Brushy’s forbearance agreement with the Lender (the “Fourth Amendment”), which, among other things, provided for a pay-down of approximately $6.0 million of the principal amount outstanding on the loan (the “Loan”), plus fees and other expenses incurred in connection with the Loan, in exchange for an extension of the maturity date through December 15, 2016, at an interest rate of 6.5%, payable monthly. Additionally, the Company agreed to (i) guaranty the approximately $5.4 million aggregate principal amount of the Loan, (ii) grant a lien in favor of the Lender on all of the Company’s real and personal property, (iii) restrict the incurrence of additional debt and (iv) maintain certain deposit accounts with various restrictions with the Lender. On September 29, 2016, in connection with the Company’s entry into the Credit and Guarantee Agreement, the Company used part of the proceeds of the Term Loan to repay the balance of Brushy’s outstanding indebtedness with Independent Bank in full.Heartland Bank
On January 8, 2015, the Company entered into the Credit Agreement with Heartland Bank (the “Credit Agreement”), as administrative agent and the Lenders party thereto. The Credit Agreement provided for a three-year senior secured term loan in an initial aggregate principal amount of $3 million, or the Term Loan. On December 29, 2015, after a default on an interest payment and in connection with the Merger, the Company entered into the Forbearance Agreement with Heartland (the “Heartland Forbearance Agreement”). The Heartland Forbearance Agreement, restricted Heartland from exercising any of its remedies until April 30, 2016, which was subject to certain conditions, including a requirement for the Company to make a monthly interest payment to Heartland.
Following the First Amendment to the Credit Agreement entered into on March 1, 2016, on May 4, 2016, as a result of a default on the required March 1, April 1 and May 1 interest payments pursuant to the Forbearance Agreement,Salt Water Disposal Assets
In July 2018, the Company entered into a second amendmentwater gathering and disposal agreement and a contract operating and right of first refusal agreement with SCM Water, LLC (“SCM Water”), a subsidiary of Salt Creek Midstream, LLC (“SCM”). The water gathering agreement complements the Company’s existing water disposal infrastructure, and the Company has reserved the right to recycle its produced water. SCM Water will commence, upon receipt of regulatory approval, to build out new gathering and disposal infrastructure to all of the Forbearance Agreement (the “Second Amendment”).Company’s current and future well locations in Lea County, New Mexico, and Winkler County, Texas. All future capital expenditures to construct, maintain and operate the water gathering system will be fully funded by SCM Water and will be designed to accommodate all water produced by the Company’s operations. Pursuant to the Second Amendment,contract operating agreement, the limitCompany will act as contract operator of SCM Water’s salt water disposal wells.
Additionally, the Company sold to SCM Water an option to acquire the Company’s existing water infrastructure, a system which is comprised of approximately 14 miles of pipeline and one SWD well, for cash consideration upon closing, with additional payments based on reaching certain milestones.
On March 7, 2019, SCM Water exercised its option to purchase the Company’s existing water infrastructure. The Company determined that approximately $11.7 million of the upfront payments were attributable to the sale of the water infrastructure and right-of-way/easement, and recorded the exercise of the option as a reduction of deferred liabilities and a reduction of oil and natural gas properties.
The Company is actively working on permitting additional SWD well locations. The Company anticipates that the majority of its water will eventually be disposed of through the future SCM Water system at a competitive gathering rate under the agreement. Total cash consideration for the water gathering and disposal infrastructure is $20.0 million. On July 25, 2018, the Company received an upfront non-refundable payment of $10.0 million for the option to acquire its existing water infrastructure and $5.0 million for a prefunded drilling bonus. Additionally, the Company received $2.5 million on October 1, 2018 as a bonus for the grant of an area right-of-way/easement, and the water gathering agreement provided that the Company would receive an additional $2.5 million bonus upon hitting the target of 40,000 barrels per day of produced water. The Company completed its drilling obligation and recognized the prefunded drilling bonus of $5.0 million as a reduction of deferred liabilities and a reduction of oil and natural gas properties as the deferred payment was attributable to the sale of the water infrastructure.
On March 11, 2019, the Company, SCM Water, and ARM Energy Management, LLC (“ARM”), a related company to SCM Water, agreed to amend the terms of the previously negotiated water gathering and disposal agreement and entered into a new crude oil sales contract (See Note 7 - Revenue and Note 21 - Commitments and Contingencies). Under the terms of such agreements, the Company agreed to an increase in salt water disposal rates in exchange for more favorable pricing differentials on the amountcrude oil sales contract, modification on the minimum quantities of New Subordinated Debtcrude oil required under the crude oil sales contract, an upfront payment of $2.5 million and the elimination of the potential bonus for hitting a target of 40,000 barrels of produced water per day. The Company determined that the upfront $2.5 million payment was primarily attributable to the crude oil sales contract, and the Company had been permittedrecorded the $2.5 million payment as deferred revenues and will recognize it in income ratably as the crude oil is sold.
Crude Oil Gathering Agreement and Option Agreement
On May 21, 2018, the Company entered into a crude oil gathering agreement and option agreement with SCM. The crude oil gathering agreement (the “Gathering Agreement”) enables SCM to raise was eliminated(i) design, engineer, and construct a gathering system which will provide gathering services for the Company’s crude oil under a tariff arrangement and (ii) gather the Company’s crude oil on the gathering system in certain production areas located in Winkler and Loving Counties, Texas and Lea County, New Mexico. Construction of the gathering system has commenced. The Gathering Agreement has a term of 12 years that automatically renews on a year to year basis until terminated by either party.
SCM and the Forbearance Expiration Date was extendedCompany also entered into an option agreement (the “Option Agreement”) whereby the Company granted an option to SCM to provide certain midstream services related to natural gas in Winkler and Loving Counties, Texas and Lea County, New Mexico, subject to the expiration and terms of the Company’s existing gas agreement. The Option Agreement has a term commencing May 31, 2016.21, 2018 and terminating January 1, 2027, pursuant to its one-time option. As consideration for the forgoing,this option, the Company paid Heartlandreceived a one-time payment of $35.0 million, which was recorded in long-term deferred revenue.
Asset Disposition Accounted for as a Financing Arrangement
As a result of certain repurchase rights, as discussed more fully in Note 5 - Acquisitions and Divestitures, the overdueagreements with WLR and WLWI do not meet the criteria for a sale and are accounted for as a financing arrangement under ASC 470. The net proceeds of the transaction of $39.0 million are included in long-term deferred revenue and other long-term liabilities on the Company’s consolidated balance sheet as of December 31, 2019. As a result of the transaction, the net revenue payments of $0.9 million for the year ended December 31, 2019 are included in interest owed pursuant toexpense on the Term LoanCompany’s consolidated statements of operations (see Note 5 - Acquisitions and interest due through June 23, 2016 in the approximate amount of $160,000 and reimbursement of a portion of Heartland’s fees and expenses in an approximate amount of $53,000. Divestitures).
NOTE 13 - RELATED PARTY TRANSACTIONS
During the year ended December 31, 2016,2019 and 2018, the Company amortizedwas engaged in the following transactions with certain related parties:
|
| | | | | | | | | | |
| | | | | As of December 31, |
| Related Party | | Transactions | | 2019 | | 2018 |
| | | | | (In thousands) |
| Directors and Officers: | | | | |
| | |
|
| Värde Partners, Inc. (1) | | The Company acquired oil and natural gas interests from VPD, an affiliate of Värde | | $ | — |
| | $ | 10,705 |
|
| | | Receivable balance outstanding for operating costs associated with VPD's producing wells | | — |
| | 1,843 |
|
| | | ImPetro Operating, LLC, a wholly-owned subsidiary of the Company is the operator for two of VPD's producing wells and VPD reimbursed the Company for operating charges | | — |
| | 44 |
|
| | | Revenue payable balance due as of December 31, 2019 for revenue associated with VPD's producing wells | | (157 | ) | | — |
|
| | | Payable to WLR for net proportionate share of production | | (161 | ) | | — |
|
| | | Payable to WLWI for net proportionate share of production | | (526 | ) | | |
| | | Asset disposition accounted for as a financing arrangement | | (36,833 | ) | | — |
|
| | | Total: | | $ | (37,677 | ) | | $ | 12,592 |
|
(1) Värde was the lead lender in the Company’s Second Lien Term Loan (see Note 11 - Long-Term Debt), is a major stockholder of the Company, and also participated in various transactions in 2018 and 2019 (which such transactions included the issuance of preferred stock to Värde Parties) (see Note 15 - Preferred Stock).
Additionally, on March 5, 2019, pursuant to the 2019 Transaction Agreement and the related payoff letter, the Company agreed to issue to the Värde Parties shares of two new series of its preferred stock and shares of its common stock, as consideration for the termination of the Second Lien Credit Agreement with the Värde Parties and the satisfaction in full, in lieu of repayment in cash, of the Second Lien Term Loan under the Second Lien Credit Agreement. See Note 11 - Long-Term Debt and Note 15 - Preferred Stock for additional information.
On July 31, 2019, the Company entered into two agreements with affiliates of Värde for the sale of an overriding royalty interest and a non-operated working interest in undeveloped assets. WLR’s proportionate share of production of $0.4 million and WLWI’s proportionate share of production, net of production costs, of $0.5 million for the year ended December 31, 2019 is included in interest expense on the Company’s consolidated statements of operations. None of the properties included in the WI Agreement were producing as of December 31, 2019. See Note 5 - Acquisitions and Divestitures for additional information.
On August 16, 2019, the company entered into an agreement with an affiliate of Värde to repurchase the overriding royalty interest for the New Mexico acreage sold. See Note 5 - Acquisitions and Divestitures for additional information.
On April 21, 2020, Värde Investment Partners, L.P., an affiliate of Värde Partners, Inc., became a lender under our Revolving Credit Agreement by acquiring, from a prior lender, loans and commitments under the Revolving Credit Agreement in the principal amount of approximately $38,000$25.7 million. The loans and commitments acquired by Värde Investment Partners, L.P. are subject to certain subordination provisions set forth in the Revolving Credit Agreement, as amended by the Fourteenth Amendment thereto dated April 21, 2020. For additional information regarding our Revolving Credit Agreement, as amended, see Note 11 - Long-Term Debt.
NOTE 14 - INCOME TAXES
The income tax provision (benefit) for the years ended December 31, 2019 and 2018 consisted of debt discount. This amount is recordedthe following:
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| | (in thousands) |
| U.S. Federal: | | | |
| Current | $ | — |
| | $ | — |
|
| Deferred | (55,366 | ) | | (7,496 | ) |
| State and local: | | | |
| Current | — |
| | — |
|
| Deferred | (4,220 | ) | | 509 |
|
| | (59,586 | ) | | (6,987 | ) |
| Change in valuation allowance | 59,586 |
| | 6,987 |
|
| Income tax provision | $ | — |
| | $ | — |
|
The tax effects of temporary differences that give rise to the Company’s deferred tax asset as a component of non-cash interest expense. December 31, 2019 and 2018 consisted of the following:
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| | (In thousands) |
| Deferred tax assets: | | | |
| Net operating loss carry-forward | $ | 31,992 |
| | $ | 27,568 |
|
| Share based compensation | 531 |
| | 808 |
|
| Abandonment obligation | 761 |
| | 541 |
|
| Derivative instruments | 1,526 |
| | — |
|
| Deferred revenue | 15,863 |
| | 11,630 |
|
| Interest expense | 4,540 |
| | 3,804 |
|
| Lease Liability | 386 |
|
| — |
|
| Property Basis | 27,837 |
|
| — |
|
| Accrued liabilities and other | 144 |
| | 85 |
|
| Total deferred tax asset | 83,580 |
| | 44,436 |
|
| Valuation allowance | (83,197 | ) | | (23,611 | ) |
| Deferred tax asset, net of valuation allowance | 383 |
| | 20,825 |
|
| | | | |
| Deferred tax liabilities: | | | |
| Derivative instruments | — |
| | 249 |
|
| Oil and natural gas properties and equipment | — |
| | 20,576 |
|
| Right of use asset | 383 |
|
| — |
|
| Total deferred tax liability | 383 |
| | 20,825 |
|
| Net deferred tax asset (liability) | $ | — |
| | $ | — |
|
Reconciliation of the Company’s effective tax rate to the expected U.S. federal tax rate is:
|
| | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| Effective federal tax rate | 21 | % | | 21 | % |
| State tax rate, net of federal benefit | 1 | % | | 2 | % |
| Change in fair value derivative liability | — | % | | 296 | % |
| Debt discount amortization | — | % | | (73 | )% |
| Change in rate | — | % | | (6 | )% |
| Other permanent differences | — | % | | (6 | )% |
| NOL true-up - §382 limitation | — | % | | (6 | )% |
| Loss from early debt extinguishment | — | % | | (59 | )% |
| Other | — | % | | (1 | )% |
| Valuation allowance | (22 | )% | | (169 | )% |
| Net | — | % | | — | % |
As of December 31,
20162019 and
2015,2018, the
unamortized deferred financing costs were $0Company had net operating loss carry-forwards for federal income tax purposes of approximately $142.2 million and
$38,000, respectively.In connection with$127.5 million respectively, available to offset future taxable income. To the consummationextent not utilized, federal net operating loss carry-forwards incurred prior to January, 1 2018 of $69.9 million will expire beginning in 2028 through 2037. Federal net operating loss carryforwards incurred after December 31, 2017 of $77.1 million have no expiration and can only be used to offset 80% of taxable income when utilized. A portion of the Merger,net operating loss of $142.2 million is subject to Section 382 limitations of utilization due to ownership changes of more than 50% which occurred in the prior tax years.
In assessing the need for a valuation allowance on June 23, 2016,the Company’s deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative. Negative evidence considered by management includes cumulative book and tax losses in recent years, no taxable income in available carryback years, and no tax planning strategies contemplated to realize the valued deferred tax assets.
As of December 31, 2019, and 2018, management assessed the available positive and negative evidence to estimate if sufficient future taxable income would be generated to use the Company’s deferred tax assets and determined that it is not more-likely-than-not that the deferred tax assets would be realized in the near future. Therefore, the Company
repaid the entire balancerecorded a full valuation allowance of
approximately $83.2 million and $23.6 million on its
outstanding indebtedness with Heartland at a discountdeferred tax assets as of
$250,000 (recognized as a gain in other income (expense), resulting in the elimination of $2.75 million in senior secured debtDecember 31, 2019 and
the extinguishment of Heartland’s security interest in the assets of the Company.Convertible Notes
From December 29, 2015 to
NOTE 15 - PREFERRED STOCK
Preferred Stock Issuances
On January 5, 2016,30, 2018, the Company entered into 12% Convertible Subordinated Notea Securities Purchase Agreements with various lending parties, which the Company refers to as the Purchasers, for the issuance of an aggregate principal amount of $3.75 million unsecured subordinated convertible notes, or the Convertible Notes, which includes the $750,000 of short-term notes exchanged for Convertible NotesAgreement by and among the Company and warrantsthe Värde Parties, pursuant to which, on January 31, 2018, the Company issued and sold to the Värde Parties 100,000 shares of a newly created series of preferred stock of the Company, designated as “Series C 9.75% Convertible Participating Preferred Stock” for a purchase up toprice of $1,000 per share, or an aggregate of approximately 1,500,000 shares of Common$100.0 million. The Series C 9.75% Convertible Participating Preferred Stock at an exercise price of $2.50 per share. The proceeds from this financing were used to pay a $2 million refundable depositwas subsequently re-designated as “Series C-1 9.75% Convertible Participating Preferred Stock” in connection with the Merger, to fund approximately $1.3 million of interest paymentstransactions contemplated by the 2018 Transaction Agreement (as defined in Note 11 - Long-Term Debt) and as “Series C-1 9.75% Participating Preferred Stock” in connection with the transactions contemplated by the 2019 Transaction Agreement (as defined in Note 11 - Long-Term Debt) (as re-designated, the “Series C-1 Preferred Stock”).
Pursuant to the 2018 Transaction Agreement, on October 10, 2018, the Company issued and sold to the Värde Parties 25,000 shares of a newly created series of the Company’s lenderspreferred stock designated as “Series C-2 9.75% Convertible Participating Preferred Stock” for a purchase price of $1,000 per share, or an aggregate of $25.0 million. The Series C-2 9.75% Convertible Participating Preferred Stock was subsequently re-designated as “Series C-2 9.75% Participating Preferred Stock” in connection with the transactions contemplated by the 2019 Transaction Agreement (as re-designated, the “Series C-2 Preferred Stock” and, together with the Series C-1 Preferred Stock, the “Series C Preferred Stock”). Also pursuant to the 2018 Transaction Agreement, on October 10, 2018, the Company issued to the Värde Parties 39,254 shares of its Series D 8.25% Convertible Participating Preferred Stock. The Series D 8.25% Convertible Participating Preferred Stock was subsequently re-designated as “Series D
8.25% Participating Preferred Stock” in connection with the transactions contemplated by the 2019 Transaction Agreement (as re-designated, the “Series D Preferred Stock”).
Pursuant to the 2019 Transaction Agreement, on March 5, 2019, the Company issued to the Värde Parties (i) 60,000 shares of its Series E Preferred Stock and (ii) 55,000 shares of its Series F Preferred Stock.
Additionally, pursuant to the 2019 Transaction Agreement, on March 5, 2019, the Company issued to the Värde Parties an aggregate of 7,750,000 shares of its common stock, as consideration for the Värde Parties’ consent to the amendment of the terms of the Series C Preferred Stock and the Series D Preferred Stock to, among other things, eliminate the convertibility and voting rights of the Series C Preferred Stock and the Series D Preferred Stock. As a result of the transactions effected under the 2019 Transaction Agreement, the potential dilution of the Company’s common stockholders resulting from the conversion of convertible debt and convertible preferred stock was reduced from approximately 53.5 million shares of common stock (related to the Second Lien Term Loan, the Series C Preferred Stock and the Series D Preferred Stock) to approximately 24.0 million shares of common stock (related to the Series E Preferred Stock). Other than the Series E Preferred Stock, the Company has no convertible debt or convertible preferred stock outstanding following the closing of the transactions contemplated by the 2019 Transaction Agreement. The amendments to the terms of the Series C Preferred Stock also fixed the redemption price payable by the Company in connection with a redemption of the Series C Preferred Stock at price per share equal to (i) the Stated Value (as defined in the certificate of designation for the Series C Preferred Stock) multiplied by 125.0% plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof. Prior to the amendments, the percentage specified in clause (i) above would have increased to 130.0% for a redemption of the Series C Preferred Stock effected after December 31, 2019.
As of December 31, 2019, the Company accounted for the Series C, D, E and F Preferred Stock at its working capitalinitial fair value at closing of the 2019 Transaction Agreement, plus cumulative paid-in-kind dividends accrued subsequent to the closing of the transactions contemplated by the 2019 Transaction Agreement, under mezzanine equity in the consolidated balance sheet. The components of each series of preferred stock are summarized in the table below:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Series C Preferred Stock | | Series D Preferred Stock | | Series E Preferred Stock | | Series F Preferred Stock |
| | | Number of Shares | | Amount | | Number of Shares | | Amount | | Number of Shares | | Amount | | Number of Shares | | Amount |
| | | (In thousands, except shares) |
| Balance, January 1, 2019 | | 125,000 |
| | $ | 132,296 |
| | 39,254 |
| | $ | 40,729 |
| | — |
| | $ | — |
| | — |
| | $ | — |
|
| Change in carrying value due to modification | | — |
| | (46,632 | ) | | — |
| | (15,056 | ) | | — |
| | — |
| | — |
| | — |
|
| Issuance of Preferred Stock in extinguishment of debt | | — |
| | — |
| | — |
| | — |
| | 60,000 |
| | 62,115 |
| | 55,000 |
| | 46,682 |
|
| Paid-in-kind dividends | | — |
| | 13,639 |
| | — |
| | 3,409 |
| | — |
| | 4,170 |
| | — |
| | 4,179 |
|
| Balance, December 31, 2019 | | 125,000 |
| | $ | 99,303 |
| | 39,254 |
| | $ | 29,082 |
| | 60,000 |
| | $ | 66,285 |
| | 55,000 |
| | $ | 50,861 |
|
Material Terms of the Series C Preferred Stock and
accounts payable.Series D Preferred Stock
Ranking.The Convertible Notes bear interestSeries D Preferred Stock ranks senior to the Series C Preferred Stock, and the Series C Preferred Stock ranks senior to the Common Stock with respect to dividends and rights on the liquidation, dissolution or winding up of the Company.
Stated Value. Each series of the Preferred Stock has a per share stated value of $1,000, subject to increase in connection with the payment of dividends in kind (the “Stated Value”).
Dividends. Holders of shares of Preferred Stock are entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears on January 1, April 1, July 1 and October 1 of each year, commencing April 1, 2018, at aan annual rate of 12% per annum,9.75% of the Stated Value for the Series C Preferred Stock and 8.25% of the Stated Value for the Series D Preferred stock until April 26, 2021, after which the annual dividend rate will increase to 12.00% if paid in full in cash or 15.00% if not paid in full in cash. Dividends are payable, at maturitythe Company’s option, (i) in cash, (ii) in kind by increasing the Stated Value by the amount per share of the dividend, or (iii) in a combination thereof. In addition to these preferential dividends, holders of the Preferred Stock will be entitled to participate in any dividends paid on June 30, 2016.the Common Stock on an as-converted basis.
Optional Redemption. The Convertible Notes andCompany has the accrued but unpaid interest thereon are convertibleright to redeem the Series C Preferred Stock, in whole or in part, at any time (subject to certain limitations on partial redemptions), at a price per share equal to (i) the Stated Value then in effect multiplied by (a) 120% if redeemed during 2018, (b) 125% if redeemed during 2019 or (c) 130% if redeemed after 2019, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series C Optional Redemption Amount”). The Company has the right to redeem the Series D Preferred Stock, in whole or in part at any time (subject to certain limitations on partial redemptions), at a price per share equal to (i) the Stated Value then in effect multiplied by 117.5%, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series D optional Redemption Amount”). Each Series of the Preferred Stock is perpetual and is not mandatorily redeemable at the option of the holders, except upon the occurrence of a Change of Control (as defined in the Certificates of Designation) as described below.
Change of Control. Upon the occurrence of a Change of Control (as defined in the Certificates of Designation), each holder of shares of Preferred Stock will have the option to:
cause the Company to redeem all of such holder’s shares of Preferred Stock for cash in an amount per share equal to (i) the applicable Optional Redemption Amount plus (ii) 2.5% of the Stated Value, in each case as in effect immediately prior to the Change of Control;
convert all of such holder’s shares of Preferred Stock into the number of shares of Common Stock into which such shares are convertible immediately prior to the Change of Control; or
continue to hold such holder’s shares of Preferred Stock, subject to any adjustments to the applicable Conversion Price or the number and kind of securities or other property issuable upon conversion resulting from timethe Change of Control and to the Company’s or its successor’s optional redemption rights described above.
Liquidation Preference. Upon any liquidation, dissolution or winding up of the Company:
holders of shares of Series D Preferred Stock will be entitled to receive, prior to any distributions on the Series C Preferred Stock, the Common Stock or other capital stock of the Company ranking junior to the Series D Preferred Stock, an amount per share of Series D Preferred Stock equal to the greater of (i) the Series D Optional Redemption Amount then in effect and (ii) the amount such holder would receive in respect of the number of shares of Common Stock into which such shares of Series D Preferred Stock is then convertible; and
holders of shares of Series C Preferred Stock will be entitled to receive, prior to any distributions on the Common Stock or other capital stock of the Company ranking junior to the Series C Preferred Stock, an amount per share of Series C Preferred Stock equal to the greater of (i) the applicable Series C Optional Redemption Amount then in effect and (ii) the amount such holder would receive in respect to the number of shares of common stock into which a share of Series C Preferred Stock is then convertible.
Voting Rights. In addition to the Board designation rights described in the Certificate of Designation, holders of shares of Preferred Stock will be entitled to vote with the holders of shares of Common Stock, as a single class, on all matters submitted for a vote of holders of shares of Common Stock. When voting together with the Common Stock, each share of Preferred Stock will entitle the holder to a number of votes equal to (i) the applicable Stated Value as of the applicable record date or other determination date divided by (ii) (a) in the case of Series C-1 Preferred Stock, $4.42 (the closing price of the Common Stock on the NYSE American on January 30, 2018), and (b) in the case of Series C-2 Preferred Stock and Series D Preferred Stock, $4.41 (the closing price of the Common Stock on the NYSE American on October 9, 2018).
Description of the Series E Preferred Stock and Series F Preferred Stock
Ranking. The Series F Preferred Stock ranks senior to all of the other series of preferred stock of the Company, and the Series E Preferred Stock ranks senior to the Series D Preferred Stock and the Series C Preferred Stock, in each case with respect to dividends and rights on the liquidation, dissolution or winding up of the Company.
Stated Value. The Series E Preferred Stock and the Series F Preferred Stock have an initial per share stated value of $1,000, subject to increase in connection with the payment of dividends in kind as described below (the “Stated Value”).
Dividends. Holders of the Series E Preferred Stock and Series F Preferred Stock are entitled to receive cumulative preferential dividends, payable and compounded quarterly in arrears on January 1, April 1, July 1 and October 1 of each year, commencing April 1, 2019, at an annual rate of 8.25% of the Stated Value for the Series E Preferred Stock and at an annual rate of 9.00% of the Stated Value for the Series F Preferred Stock. However, if, on any dividend payment date occurring after April 26, 2021, dividends due on such dividend payment date on the Series E Preferred Stock or the Series F Preferred Stock are not paid in full in cash, the annual dividend rate for the dividends due on such dividend payment date (but not for any future dividend payment date on which dividends are paid in full in cash) will be 9.25% on the Series E Preferred Stock and 10.00% on the Series
F Preferred Stock. Dividends are payable, at the Company’s option, (i) in cash, (ii) in kind by increasing the Stated Value by the amount per share of the dividend or (iii) in a combination thereof.
In addition to these cumulative preferential dividends, holders of the Series E Preferred Stock and Series F Preferred Stock are entitled to participate in dividends paid on the Company’s common stock. For holders of the Series E Preferred Stock, such participation will be based on the number of shares of common stock such holders would have owned if all shares of Series E Preferred Stock had been converted to common stock at the Conversion Rate (as defined below) then in effect. For holders of the Series F Preferred Stock, such participation will be based on the dividends such holders would have received if, immediately prior to the applicable record date, each outstanding share of Series F Preferred Stock had been converted into a number of shares of common stock equal to the Series F Optional Redemption Price (as defined below) divided by $7.00, subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock (regardless of the fact that shares of the Series F Preferred Stock are not convertible into common stock).
Optional Redemption. Subject to the limitations described below and certain additional limitations on partial redemptions, the Company has the right to redeem the Series E Preferred Stock, in whole or in part, at a price per share equal to (i) the Stated Value then in effect multiplied by (A) 110% if the optional redemption date occurs on or prior to March 5, 2020, (B) 105% if the optional redemption date occurs after March 5, 2020 and on or prior to March 5, 2021 and (C) 100% if the optional redemption date occurs after March 5, 2021, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series E Optional Redemption Price”). However, for any optional redemption effected in connection with or following a Change of Control (as defined in the Series E Certificate of Designation) or any mandatory redemption in connection with a Change of Control as described below, the Series E Optional Redemption Price will be calculated under clause (C) above, regardless of when the redemption or Change of Control occurs.
Except in the case of a Change of Control Redemption (as defined in the Series E Certificate of Designation), the Company may not effect an optional redemption of the Series E Preferred Stock unless:
either (i) as of the optional redemption date, there are no shares of the Series F Preferred Stock outstanding or (ii) all outstanding shares of the Series F Preferred Stock are redeemed on such optional redemption date concurrently with such optional redemption of the Series E Preferred Stock in accordance with the terms of the Series F Certificate of Designation;
the aggregate Series E Optional Redemption Price for all shares of the Series E Preferred Stock to be redeemed pursuant to such optional redemption shall not exceed the aggregate amount of net cash proceeds received by the Company from a contemporaneous issuance of common stock issued for the purpose of redeeming such shares of Series E Preferred Stock; and
if the optional redemption date occurs prior to March 5, 2022, then (i) the VWAP for at least 20 trading days during the 30 trading day period immediately preceding the notice of the optional redemption has been at least 150% of the Conversion Price (as defined below) then in effect, and (ii) such optional redemption shall be for all (but not less than all) then-outstanding shares of Series E Preferred Stock.
The Series E Preferred Stock is not redeemable at the option of the holders except in connection with a Change of Control as described below and is perpetual unless converted or redeemed in accordance with the Series E Certificate of Designation.
The Company has the right to redeem the Series F Preferred Stock, in whole or in part (subject to certain limitations on partial redemptions), at a price per share equal to (i) the Stated Value then in effect, multiplied by 115.0%, plus (ii) accrued and unpaid dividends thereon and any other amounts payable by the Company in respect thereof (the “Series F Optional Redemption Price”).
The Series F Preferred Stock is not redeemable at the option of the holders except in connection with a Change of Control as described below and is perpetual unless converted or redeemed in accordance with the Series F Certificate of Designation.
Conversion. Each share of the Series E Preferred Stock is convertible at any time at the option of the holders thereofholder into the number of shares of common stock equal to (i) the applicable Series E Optional Redemption Price that would have been received by the holder upon the redemption of the applicable shares of Series E Preferred Stock as of the Conversion Date (as defined in the Series E Certificate of Designation) divided by (ii) the Conversion Price (as defined below) (the “Conversion Rate”). However, for purposes of determining the Conversion Rate, the Series E Optional Redemption Price will be calculated on the basis applicable to an optional redemption occurring after March 5, 2021 (i.e., multiplying the Stated Value by 100.0%), regardless of the timing or circumstances of the conversion. The “Conversion Price” for the Series E Preferred Stock is $2.50, subject to adjustment as described below. The Conversion Price will be subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock. Additionally, the Conversion Price will be adjusted, based on a broad-based weighted average formula, if the Company issues, or is deemed to issue, additional shares of
common stock for consideration per share that is less than the Conversion Price then in effect, subject to certain exceptions and to the Share Cap (as defined below).
To comply with the rules of the NYSE American, the Series E Certificate of Designation provides that the number of shares of common stock issuable on conversion of a share of Series E Preferred Stock may not exceed the Stated Value divided by $1.88 (which was the closing price of the common stock on the NYSE American on March 4, 2019) (the “Share Cap”), subject to proportionate adjustment in connection with stock splits and combinations, dividends paid in stock and similar events affecting the outstanding common stock (such price, as so adjusted, the “Initial Market Price”), prior to the receipt of stockholder approval of the issuance of shares of common stock in excess of the Share Cap upon conversion of shares of Series E Preferred Stock. The 2019 Transaction Agreement requires the Company to seek such shareholder approval at its next annual meeting of shareholders. Accordingly, the Company received shareholder approval at its 2019 annual meeting of shareholders held on May 20, 2019.
The Company does not have the right to force the conversion of shares of the Series E Preferred Stock based on the trading price of the common stock or otherwise.
The Series F Preferred Stock is not convertible into common stock.
Change of Control. Upon the occurrence of a Change of Control (as defined in the Series E Certificate of Designation and the Series F Certificate of Designation), each holder of shares of the Series E Preferred Stock and Series F Preferred Stock will have the option to: (i) cause the Company to redeem all of such holder’s shares of Series E Preferred Stock or Series F Preferred Stock for cash in an amount per share equal to the applicable Optional Redemption Price; (ii) in the case of the Series E Preferred Stock, convert all of such holder’s shares of Series E Preferred Stock into common stock at the Conversion Rate; or (iii) continue to hold such holder’s shares of Series E Preferred Stock or Series F Preferred Stock, subject to the Company’s or its successor’s optional redemption rights described above and, in the case of the Series E Preferred Stock, subject to any adjustments to the Conversion Price or the number and kind of securities or other property issuable upon conversion resulting from the Change of Control.
Liquidation Preference. Upon any liquidation, dissolution or winding up of the Company, holders of shares of Series F Preferred Stock will be entitled to receive, prior to any distributions on the Series E Preferred Stock, the Series D Preferred Stock, the Series C Preferred Stock, the common stock or other capital stock of the Company ranking junior to the Series F Preferred Stock, an amount per share equal to the greater of (i) the Series F Optional Redemption Price then in effect and (ii) the proceeds the holders of Series F Preferred Stock would be entitled to receive if, immediately prior to the payment of such amount, each then-outstanding share of the Series F Preferred Stock had been converted into a number of shares of common stock equal to the Series F Optional Redemption Price divided by the Participation Price (as defined in the certificate of designation for the Series F Preferred Stock), regardless of the fact that shares of the Series F Preferred Stock are not convertible into common stock.
Upon any liquidation, dissolution or winding up of the Company, holders of shares of Series E Preferred Stock will be entitled to receive, after any distributions on the Series F Preferred Stock and prior to any distributions on the Series D Preferred Stock, the Series C Preferred Stock, the common stock or other capital stock of the Company ranking junior to the Series E Preferred Stock, an amount per share of Series E Preferred Stock equal to the greater of (i) the Series E Optional Redemption Price then in effect and (ii) the amount such holder would receive in respect of the number of shares of common stock into which such share of Series E Preferred Stock is then convertible.
Board Designation Rights. The Series E Certificate of Designation provides that holders of the Series E Preferred Stock have the right, voting separately as a class, to designate one member of the Board for as long as the shares of common stock issuable on conversion of the outstanding shares of Series E Preferred Stock represent at least 5% of the outstanding shares of common stock (giving effect to conversion of all outstanding shares of the Series E Preferred Stock).
The Series F Certificate of Designation provides that holders of the Series F Preferred Stock have the right, voting separately as a class, to designate one member of the Board for as long as the aggregate Stated Value of all outstanding shares of the Series F Preferred Stock is at least equal to $13.8 million.
Voting Rights. In addition to the Board designation rights described above, holders of Series E Preferred Stock are entitled to vote with the holders of the common stock, as a single class, on all matters submitted for a vote of holders of the common stock. When voting together with the common stock, each share of Series E Preferred Stock will entitle the holder to a number of votes equal to the applicable Stated Value as of the applicable record date or other determination date divided by the greater of (i) the then-applicable Conversion Price and (ii) the then-applicable Initial Market Price.
Holders of shares of Series F Preferred Stock are not entitled to vote with the holders of the common stock as a single class on any matter.
Negative Covenants. The Series E Certificate of Designation and Series F Certificate of Designation contain customary negative covenants.
Transfer Restrictions. Shares of Series E Preferred Stock and Series F Preferred Stock and shares of common stock issued on conversion of shares of Series E Preferred Stock may not be transferred by the holder of such shares, other than to an affiliate of such holder, prior to September 5, 2019. After September 5, 2019, such shares will be freely transferable, subject to applicable securities laws.
NOTE 16 - STOCKHOLDERS' EQUITY
Issuance of Common Stock at a conversion price of $5.00. The Convertible Notes may be prepaid in whole or in part (but with payment of accrued interest
On March 5, 2019, pursuant to the date of prepayment) at any time at a premium of 103%2019 Transaction Agreement, as (i) partial consideration for the first 120 days and a premium of 105% thereafter, so long as no Senior Debt is outstanding. The Convertible Notes contain customary events of default, which, if uncured, entitle each noteholder to accelerate the due datesatisfaction in full of the unpaid principal amountSecond Lien Term Loan as discussed in Note 11 - Long-Term Debt and (ii) consideration for the amendment of and all accrued and unpaid interest, subject to certain subordination provisions.Additionally, on March 18, 2016, the Company issued an additional aggregate principal amount of $500,000 of Convertible Notes, which have the same terms and conditions as the Convertible Notes with the exception of the maturity date, which is April 1, 2017. The proceeds from these Convertible Notes were used to make advances to Brushy for payment of operating expenses pending completion of the Merger. These notes were fully converted following the consummation of the Merger.
In connection with the closing of the Merger, on June 23, 2016, certain holders of Convertible Notes in an aggregate principal amount of approximately $4.0 million entered into a Conversion Agreement with the Company (the "Note Conversion Agreement"). The terms of the Note Conversion Agreement provided that the Convertible Notes were automatically converted into Common Stock upon the closing of the Merger. Pursuant to the terms of the Series C Preferred Stock and the Series D Preferred Stock as discussed in
Note Conversion Agreement, in exchange for immediate conversion upon closing, the conversion price of the Convertible Notes was reduced to $1.10, which resulted in the issuance of 3,636,366 shares of Common Stock. The modification of such conversion rate resulted in a $3.4 million inducement charge recorded in other expense. Holders of these Convertible Notes waived and forfeited approximately $198,000 rights to receive accrued but unpaid interest.On August 3, 2016, the Company entered into the first amendment to the Convertible Notes with the remaining holders of approximately $1.8 million of Convertible Notes. Pursuant to the first amendment: (i) the maturity date was changed to January 2, 2017, (ii) the conversion price was adjusted to $1.10 and (iii) the coupon rate was increased to 15% per annum. All accrued and unpaid interest on the Convertible Notes would also be convertible in certain circumstances at the conversion price. Additionally, if the aggregate principal amount outstanding on the Convertible Notes was not either converted by the holder or repaid in full on or before the maturity date, the Company agreed to pay a 25% premium on the maturity date. The Company accounted for the reduction in the conversion price of remaining outstanding convertible notes as an inducement expense and recognized approximately $1.6 million in other income (expense). In exchange for the holders’ willingness to enter into the first amendment, the Company issued to the holders additional warrants to purchase up to approximately 1.65 million shares of Common Stock. The warrants issued were valued using the following variables: (i) stock price of $1.12; (ii) exercise price of $2.50; (iii) contractual life of 3 years; (iv) volatility of 203%; (v) risk free rate of 0.76% for a total value of approximately $1.63 million. This amount was recorded as an inducement expense and an increase to additional paid-in capital.
On September 29, 2016, in connection with the Company’s entry into the Credit and Guarantee Agreement the remaining holders of the Convertible Notes converted the outstanding principal amount of approximately $1.8 million and accrued and unpaid interest in an amount of approximately $138,000 into 1,772,456 shares of Common Stock.
Convertible Debentures
In numerous separate private placement transactions between February 2011 and October 2013,15 - Preferred Stock
, the Company issued an aggregate of approximately $15.6 million17,641,638 shares of Debentures, secured by mortgages on severalthe Company’s common stock, par value 0.0001 per share.
Warrants
The following table provides a summary of its properties. On Januarywarrant activity as of December 31, 2014,2019 and 2018:
|
| | | | | | |
| | Warrants | | Weighted- Average Exercise Price |
| Outstanding at Outstanding at January 1, 2018 | 11,882,800 |
| | $ | 3.34 |
|
| Exercised | (3,975,957 | ) | | 2.21 |
|
| Forfeited or expired | (2,889,514 | ) | | 3.35 |
| Outstanding at Outstanding at January 1, 2019 | 5,017,329 |
| | 3.83 |
| Forfeited or expired | (2,263,267 | ) | | 2.81 |
| Outstanding at December 31, 2019 | 2,754,062 |
| | $ | 4.67 |
|
The outstanding warrants at December 31, 2019 will expire as follows:
|
| | |
| Year | Warrants |
| 2020 | 174,642 |
|
| 2021 | — |
|
| 2022 | 2,579,420 |
|
| | 2,754,062 |
|
Common Stock Repurchase
In March 2018, the Company entered into a
debenture conversionshare-repurchase agreement (the
“First Conversion Agreement”“SRA”) with
allan investment brokerage company (“Broker”) to repurchase $1.0 million of the
holdersCompany’s common stock as part of the
Debentures.Pursuant to the terms of the First Conversion Agreement, $9.0 million in Debentures (approximately $8.73 million of principal and $270,000 in interest) was converted by the holders to shares of Common Stock at a conversion price of $20.00 per share. In addition, the Company issued warrants to the Debenture holders to purchase one share of Common Stock for each share issued in connection with the conversion of the Debentures, at an exercise price equal to $25.00 per share.
Share Repurchase Plan (the “Plan”). Under the terms of the First Conversion Agreement,SRA, the balance of the Debentures may be converted to Common Stock on the terms provided therein (including the terms relatedCompany paid cash directly to the warrants) at the electionBroker and received delivery of the holder, subject to receipt of stockholder approval as required by Nasdaq continued listing requirements.
On December 29, 2015, the Company entered into a second agreement with the holders of its Debentures, which provides for the full automatic conversion of Debentures into shares of the Company’s Common Stock at a price of $5.00 per share, upon the receipt of requisite stockholder approval and the consummationcommon stock. All of the Merger. If the Debentures are converted on these terms, it would result in the issuance of 1,369,293 shares of Common Stock and the elimination of $8.08 million in short-term debt obligations including accrued but unpaid interest which would be forfeited and cancelled upon conversion pursuant to the terms of the agreement.
On June 23, 2016, pursuant to the terms of the Debenture Conversion Agreement, dated December 29, 2015, the Company's remaining outstanding 8% Convertible Debentures (the “Debentures”) of approximately $6,846,000 converted automatically upon consummation of the Merger. The conversion price was modified from $20.00 per share to $5.00 per share, resulting in the issuance of 1,369,293 shares of Common Stock. In exchange for the reduction in conversion price, all accrued but unpaid interest of approximately $1,835,000 was forgivenacquired by the Debenture holders, resulting in a net gain onCompany under the modification and conversion of the Debentures of approximately $602,000 andSRA are recorded as other income and expenses intreasury stock. For the accompanying consolidated statements of operations. Upon the conversion of the Debentures, the associated conversion liability of approximately $43,000 was reclassified to additional paid-in capital. There were no unamortized deferred financing costs and debt discount at December 31, 2016 and 2015, respectively.
Interest Expense
Interest expense for the yearsnine months ended December 31, 2016 and 2015 was approximately $4.9 million and $1.7 million, respectively. The non-cash interest expense during2018 the years ended December 31, 2016 and 2015 was approximately $4.2 million and $1.3 million, respectively. The non-cash interest expenses consisted of non-cash interest expense and amortizationCompany purchased 253,598 shares of the deferred financing costs, accretion of the Debentures payable discount, and Debentures interest paid in Common Stock.
NOTE 9 – COMMITMENTS AND CONTINGENCIES
Environmental and Governmental Regulation
At December 31, 2016, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, land use, and various other matters including taxation. Oil and gas industry legislation and administrative regulations are periodically changedCompany’s common stock for a variety of political, economic, and other reasons. As of December 31, 2016 the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of the Company.
Legal Proceedings
The Company may from time to time be involved in various legal actions arising in the normal course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company.
The Company believes there is no litigation pending that could have, individually or in the aggregate, a material adverse effect on its results of operations or financial condition.
Operating Leases
The Company has a two-year operating lease for office space in San Antonio, Texas and various other operating leases on a month-to-month basis which include office leases in Denver, Colorado and New York City, New York and corporate apartment leases in San Antonio, Texas. Rent expense for the years ended December 31, 2016 and 2015, was approximately $201,000 and $73,000, respectively. As of December 31, 2016, the Company has approximately $0.4 million of minimum lease payments on its operating lease which consists of annual minimum lease payments of approximately $0.2 million in 2017 and $0.2 million in 2018.
NOTE 10 – RELATED PARTY TRANSACTIONSDuring the years ended December 31, 2016 and 2015, the Company has engaged in the following transactions with related party:
| | | | | December 31, | |
| Related Party | | Transactions | | 2016 | | | 2015 | |
| More than 5% Shareholder: | | | | (In thousands) | |
| T.R. Winston & Company LLC ("TRW") | | Cash paid for Series B Preferred Stock offering fees | | $ | 500 | | | $ | - | |
| | | Reinvest fee for 150 shares of Series B Preferred Stock and 68,182 warrants at exercise price of $2.50 | | | 150 | | | | - | |
| | | Cash paid for advisory fee on Convertible Notes | | | 350 | | | | - | |
| | | Sublet office space in New York to Lilis Energy, Inc for rent of $10,000 per month | | | 15 | | | | - | |
| | | Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 | | | 400 | | | | - | |
| | | Cashless net exercised warrants to purchase 80,000 shares of Common Stock at a reset exercise price of $0.10, resulting in the issuance of 75,820 shares. | | | - | | | | - | |
| | | Total: | | $ | 1,415 | | | $ | - | |
| | | | | | | | | | | |
| Steven B. Dunn and Laura Dunn Revocable Trust dated 10/28/10 | | Conversion of convertible debentures into common stock | | $ | 1,020 | | | $ | 1,017 | |
| | | | | | | | | | | |
| Bryan Ezralow (EZ Colony Partners, LLC) | | Conversion of convertible debentures into common stock | | $ | 1,540 | | | $ | - | |
| | | Participated in the Series B Preferred offering | | | 1,300 | | | | - | |
| | | Total: | | $ | 2,840 | | | $ | - | |
| | | | | | | | | | | |
| Pierre Caland (Wallington Investment Holdings, Ltd.) | | Conversion of convertible debentures into common stock | | $ | 2,090 | | | $ | 2,090 | |
| | | Participated in the Series B Preferred offering | | | 250 | | | | - | |
| | | Conversion of Series A Preferred stock into common stock | | | 125 | | | | - | |
| | | Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 | | | 300 | | | | - | |
| | | | | | | | | | | |
| | | Total: | | $ | 2,765 | | | $ | 2,090 | |
| | | | | | | | | | | |
| Directors and Officers: | | | | | | | | | | |
| Nuno Brandolini (Director) | | Conversion of Series A Preferred stock into common stock | | $ | 100 | | | $ | - | |
| | | Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 | | | 250 | | | | 150 | |
| | | Total: | | $ | 350 | | | $ | 150 | |
| General Merrill McPeak (Director) | | Conversion of Series A Preferred stock into common stock | | $ | 250 | | | $ | - | |
| | | Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 | | | 250 | | | | 250 | |
| | | Total: | | $ | 500 | | | $ | 250 | |
| | | | | | | | | | | |
| R. Glenn Dawson (Director) | | Participated in the Series B Preferred offering | | $ | 125 | | | $ | - | |
| | | Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 | | | 50 | | | | 50 | |
| | | Total: | | $ | 175 | | | $ | 50 | |
| | | | | | | | | | | |
| Ronald D Ormand (Executive Chairman) | | Participated in the Series B Preferred offering through Perugia Investments LP(1) | | $ | 1,000 | | | $ | - | |
| | | Conversion of convertible debentures into common stock through Perugia Investments LP | | | 500 | | | | - | |
| | | Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through Brian Trust(2) | | | 1,150 | | | | 1,150 | |
| | | Consulting fee paid to MLV & Co. LLC (“MLC”) which Mr. Ormand previously was the Managing Director and Head of the Energy Investment Banking Group at MLV | | | 100 | | | | 150 | |
| | | Total: | | $ | 2,750 | | | $ | 1,300 | |
| | | | | | | | | | | |
| Abraham Mirman (Chief Executive Officer and Director) | | Participated in the Series B Preferred offering through Bralina Group, LLC(3) | | $ | 1,650 | | | $ | - | |
| | | Conversion of Series A Preferred stock into common stock | | | 250 | | | | - | |
| | | Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through Bralina Group, LLC | | | 750 | | | | 1,000 | |
| | | Total: | | $ | 2,650 | | | $ | 1,000 | |
| | | | | | | | | | | |
| Kevin Nanken (former Executive Vice President and Chief Financial Officer) | | Participated in the Series B Preferred offering through KKN Holdings LLC(4) | | $ | 200 | | | $ | - | |
| | | Participated in Convertible Notes maturing on June 30, 2016 and April 1, 2017 through KKN Holdings LLC | | | 100 | | | | - | |
| | | Total: | | $ | 300 | | | $ | - | |
| (1) | Mr. Ormand is the manager of Perugia Investments L.P. ("Perugia") and has sole voting and dispositive power over the securities held by Perugia |
| (2) | An irrevocable trust managed by Jerry Ormand, Mr. Ormand's brother, as trustee and whose beneficiaries are adult children of Mr. Ormand |
| (3) | Mr. Mirman has shared voting and dispositive power over the securities held by The Bralina Group, LLC with Susan Mirman. |
| (4) | Mr, Nanke is the natural person with sole voting and dispositive power over the securities held by KKN Holdings LLC. |
NOTE 11 – INCOME TAXES
The income tax provision (benefit) for the years ended December 31, 2016 and 2015 consisted of the following:
| | | December 31, | |
| | | 2016 | | | 2015 | |
| | | (In thousands) | |
| U.S. Federal: | | | | | | | | |
| Current | | $ | - | | | $ | - | |
| Deferred | | | (2,971 | ) | | | (10,560 | ) |
| | | | | | | | | |
| State and local: | | | | | | | | |
| Current | | | - | | | | - | |
| Deferred | | | (124 | ) | | | (914 | ) |
| | | | (3,095 | ) | | | (11,474 | ) |
| Change in valuation allowance | | | 3,095 | | | | 11,474 | |
| Income tax provision | | $ | - | | | $ | - | |
The tax effects of temporary differences that give rise to the Company’s deferred tax asset as of December 31, 2016 and 2015 consisted of the following:
| | | December 31, | |
| | | 2016 | | | 2015 | |
| | | (In thousands) | |
| Deferred tax assets: | | | | | | | | |
| Oil and gas properties and equipment | | $ | 5,156 | | | $ | 3,848 | |
| Net operating loss carry-forward | | | 42,017 | | | | 41,389 | |
| Share based compensation | | | 2,135 | | | | 1,279 | |
| Abandonment obligation | | | 445 | | | | 77 | |
| Derivative instruments | | | - | | | | 21 | |
| Accrued liabilities | | | - | | | | 37 | |
| Debt conversion costs | | | 482 | | | | 488 | |
| Other | | | 28 | | | | 29 | |
| Total deferred tax asset | | | 50,263 | | | | 47,168 | |
| Valuation allowance | | | (50,263 | ) | | | (47,168 | ) |
| Deferred tax asset , net of valuation allowance | | $ | - | | | $ | - | |
| | | | | | | | | |
| Deferred tax liabilities: | | | | | | | | |
| Oil and gas properties and equipment | | $ | - | | | $ | - | |
| Total deferred tax liability | | | - | | | | - | |
| Net deferred tax asset (liability) | | $ | - | | | $ | - | |
Reconciliation of the Company’s effective tax rate to the expected U.S. federal tax rate is:
| | | For the Year Ended
December 31, | |
| | | 2016 | | | 2015 | |
| Effective federal tax rate | | | 34.00 | % | | | 34.00 | % |
| State tax rate, net of federal benefit | | | 1.42 | % | | | 2.94 | % |
| Change in fair value derivative liability | | | -1.32 | % | | | 1.42 | % |
| Debt discount amortization | | | -4.11 | % | | | -0.01 | % |
| Share based compensation differences and forfeitures | | | -2.28 | % | | | -4.18 | % |
| Change in rate | | | -5.90 | % | | | 2.34 | % |
| Other permanent differences | | | -12.29 | % | | | -1.07 | % |
| Other | | | -0.10 | % | | | 0.01 | % |
| Valuation allowance | | | -9.42 | % | | | -35.45 | % |
| Net | | | - | % | | | - | % |
The net operating losses for these years will not be available to reduce future taxable income until the returns are filed. Assuming these returns are filed, as of December 31, 2016 and 2015, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $118.6 million and $112.0 million, respectively, available to offset future taxable income. To the extent not utilized, the net operating loss carry-forwards as of December 31, 2016 will expire beginning in 2027 through 2036. The net operating loss carryovers may be subject to reduction or limitation by application of Internal Revenue Code Section 382 from the result of ownership changes. A full Section 382 analysis has not been prepared and the Company's net operating losses could be subject to limitation under Section 382.
In assessing the need for a valuation allowance on the Company’s deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative. Management had no positive evidence to consider. Negative evidence considered by management includes cumulative book and tax losses in recent years, forecasted book and tax losses, no taxable income in available carryback years, and no tax planning strategies contemplated to realize the valued deferred tax assets.
As of December 31, 2016 and 2015, management assessed the available positive and negative evidence to estimate if sufficient future taxable income would be generated to use the Company’s deferred tax assets and determined that it is not more-likely-than-not that the deferred tax assets would be realized in the near future. Therefore, the Company recorded a full valuation allowance of approximately $50. million and $47.2 million on its deferred tax assets as of December 31, 2016 and 2015, respectively.
NOTE 12 – STOCKHOLDERS’ EQUITY
May 2014 Private Placement17 - Series A 8% Convertible Preferred Stock
On May 30, 2014, the Company consummated a private placement of 7,500 shares of Series A Preferred Stock, along with detachable warrants to purchase up to 155,602 shares of Common Stock, at an exercise price of $28.90 per share, for aggregate gross proceeds of $7.50 million. The Series A Preferred Stock has a par value of $0.0001 per share, a stated value of $1,000 per share, a conversion price of $24.10 per share, and a liquidation preference to any junior securities. Except as otherwise required by law, holders of Series A Preferred Stock shall not be entitled to voting rights, except with respect to proposals to alter or change adversely the powers, preferences or rights given to the Series A Preferred Stock, authorize or create any class of stock ranking senior to the Series A Preferred Stock as to dividends, redemption or distribution of assets upon liquidation, amend its certificate of incorporation or other charter documents in any manner that adversely affects any rights of the Preferred Stock holder, or increase the number of authorized Series A Preferred Stock. The holders of the Series A Preferred Stock are entitled to receive a dividend payable, at the election of the Company (subject to certain conditions as set forth in the Certificate of Designations), in cash or shares of Common Stock, at a rate of 8% per annum payable a day after the end of each quarter. The Series A Preferred Stock is convertible at any time at the option of the holders, or at the Company’s discretion when the Common Stock trades above $75.00 for ten consecutive days with a daily dollar trading volume above $300,000. In addition, the Company has the right to redeem the shares of Series A Preferred Stock, along with any accrued and unpaid dividends, at any time, subject to certain conditions as set forth in the Certificate of Designations. In addition, holders of the Series A Preferred Stock can require the Company to redeem the Series A Preferred upon the occurrence of certain triggering events, including (i) failure to timely deliver shares of Common Stock after valid delivery of a notice of conversion by the holder; (ii) failure to have available a sufficient number of authorized and unreserved shares of Common Stock to issue upon conversion; (iii) the occurrence of certain change of control transactions; (iv) the occurrence of certain events of insolvency; and (v) the ineligibility of the Company to electronically transfer its shares via the Depository Trust Company or another established clearing corporation.
In connection with issuance of the Series A Preferred Stock, the beneficial conversion feature (“BCF”) was valued at $2.21 million and the fair value of the warrant was valued at $1.35 million. The aggregate value of the Series A Preferred Stock and warrant, valued at $3.56 million, was considered a deemed dividend and the full amount was expensed immediately. The Company determined the transaction created a beneficial conversion feature which is calculated by taking the net proceeds of $6.79 million and valuing the warrants as of May 2014, utilizing a Black Scholes option pricing model. The inputs for the pricing model are: $24.80 market price per share; exercise price of $28.90 per share; expected life of 3 years; volatility of 70%; and risk free rate of 0.20%. The Company calculated the total consideration given to be $8.40 million comprised of $6.80 million for the Series A Preferred and $1.6 million for the warrants. The Company deemed the value of the beneficial conversion feature to be $2.21 million and immediately accreted that amount as a deemed dividend. As of December 31, 2015, the Company has accrued a cumulative dividend for approximately $0.6 million.
On June 23, 2016, in connection with the completion of the Merger, each outstanding share of the Company’s Series A Preferred Stock (the “Series A Preferred Stock”) automatically converted into Common Stock at a conversion price of $5.00, resulting in the issuance of 1,500,000 shares of Common Stock with a market value of $1.20 per share. As consideration for the automatic conversion, the Company reduced the conversion price on the Series A Preferred Stock from $24.10 to $5.00. The modification of such conversion price and forgiveness of accrued but unpaid dividend of approximately $0.9 million resulted in a net loss on the conversion of the Series A Preferred Stock of approximately $0.5 million.
Conditionally Redeemable 6% Preferred Stock
In August 2014, the Company designated 2,000 shares of its authorized preferred stock as Conditionally Redeemable 6% Preferred Stock, or the Redeemable Preferred. All 2,000 shares of Redeemable Preferred were issued in September 2014, pursuant to the Settlement Agreement with Hexagon. The Redeemable Preferred has the same par value and stated value characteristics as the Series A Preferred Stock, yet the Conditionally Redeemable 6% Preferred Stock is not convertible into Common Stock or any other securities of the Company. Except as otherwise required by law, holders of the Redeemable Preferred shall not be entitled to voting rights.
The Redeemable Preferred Stock bears a 6% dividend per annum, payable quarterly, and is redeemable at face value (plus any accrued and unpaid dividends) at any time at the Company’s option, or at the Holders option upon the Company’s achievement of certain production and reserves thresholds. These thresholds include, the Company’s annualized gross production average for 90 consecutive days at 2,500 BOE per day or higher or the Company’s PV-10 value of its producing developed properties filed with the Securities and Exchange Commission exceeds $50 million. As of December 31, 2016 and 2015, the Company has accrued a cumulative dividend of $240,000 and $120,000, respectively. The total outstanding Redeemable Preferred was valued at approximately $1.9 million and $1.2 million at December 31, 2016 and 2015, respectively.
Series B 6% Convertible Preferred Stock
On June 15, 2016, the Company entered into a purchase agreement for the private placement of 20,000 shares of its Series B Preferred Stock, along with detachable warrants to purchase up to 9,090,926 shares of Common Stock, at an exercise price of $2.50 per share, for aggregate gross proceeds of $20 million.
Each share of Series B Preferred Stock is convertible, at the option of the holder, subject to adjustment under certain circumstances into shares of Common Stock of the Company at a conversion price of $1.10. Except as otherwise required by law, holders of the Series B Preferred Stock shall not be entitled to voting rights. The Series B Preferred Stock is convertible at any time, subject to certain conditions, at the option of the holders, or at the Company’s discretion when the Company’s Common Stock trades above $10.00 (subject to any reverse or forward stock splits and the like) for ten consecutive days. In addition, the Company has the right to redeem the shares of Series B Preferred Stock, along with any accrued and unpaid dividends, at any time, subject to certain conditions as set forth in the Certificate of Designation. The holders of the Series B Preferred Stock are entitled to receive a dividend payable (subject to certain conditions as set forth in the Certificate of Designation), in cash or shares of Common Stock of the Company, at the election of the Company, at a rate of 6% per annum.
The Series B Preferred Stock is classified as equity based on the following criteria: i) the redemption of the instrument at the control of the Company; ii) the instrument is convertible into a fixed amount of shares at a conversion price of $1.10; iii) the instrument is closely related to the underlying Company’s Common Stock; iv) the conversion option is indexed to the Company’s stock; v) the conversion option cannot be settled in cash and only can be redeemed at the discretion of the Company; vi) and the Series B Preferred Stock is not considered convertible debt.
Shares of the Series B Preferred Stock and related warrants were valued using the relative fair value method. The Company determined the transaction created a beneficial conversion feature of $7.9 million, which was expensed immediately and was calculated by taking the net proceeds of approximately $15.2 million and valuing the warrants as of June 15, 2016, utilizing a Black Scholes option pricing model. The inputs for the pricing model are: $1.20 market price per share; exercise price of $2.50 per share; contractual life of 2 years; volatility of 238%; and risk free rate of 0.78%. As of December 31, 2016, the total value of the issued and outstanding shares of Series B Preferred Stock was approximately $13.4 million.
As of December 31, 2016, approximately 3,000 shares of the Series B Preferred Stock plus approximately $0.6 million of cumulative dividend payable were converted into approximately 2.7 million shares of the Company’s Common Stock at conversion price of $1.10 per share. As of December 31, 2016, the Company accrued approximately $0.6 million of cumulative dividend for Series B Preferred Stock.
Warrants
A summary of warrant activity for the twelve months ended December 31, 2016 and 2015 (adjusted to reflect 1-for10 reverse stock split on June 23, 2016):
| | | Warrants | | | Weighted-
Average
Exercise Price | |
| Outstanding at January 1, 2015 | | | 1,700,707 | | | $ | 1.76 | |
| Warrants issued to consultants | | | 60,000 | | | | 16.30 | |
| Warrants issued to Heartland | | | 22,500 | | | | 8.70 | |
| Warrants issued with Convertible Notes | | | 1,180,000 | | | | 2.50 | |
| Exercised, forfeited, or expired | | | (484,891 | ) | | | (61.30 | ) |
| Outstanding at December 31, 2015 | | | 2,478,316 | | | $ | 14.80 | |
| Warrants issued to Series B Preferred Stock | | | 9,090,926 | | | | 1.54 | |
| Warrants issued for fees | | | 1,272,727 | | | | 1.30 | |
| Warrants issued with Convertible Notes | | | 1,145,238 | | | | 2.47 | |
| Warrants issued to amend Convertible Notes | | | 1,648,267 | | | | 2.50 | |
| Additional warrants issued to Bristol | | | 541,026 | | | | 3.12 | |
| Warrants issued to SOS in connection with the Merger | | | 200,000 | | | | 2.50 | |
| Exercised, forfeited, or expired | | | (460,989 | ) | | | (34.74 | ) |
| Outstanding at December 31, 2016 | | | 15,915,511 | | | $ | 3.34 | |
The aggregate intrinsic value associated with outstanding warrants was approximately $18.3 million and zero at December 31, 2016 and 2015, respectively, as the strike price of all warrants exceeded the market price for Common Stock, based on the Company’s closing Common Stock price of $3.10 and $2.10, respectively. The weighted average remaining contract life was 1.64 years and 2.13 years as of December 31, 2016 and 2015.
During the year ended December 31, 2016, the Company issued approximately 13.16 million warrants to purchase shares of Common Stock to Purchasers of the Convertible Notes, Purchasers of Series B Preferred Stock and placement agent fees in connection with the Series B Preferred Stock Offering. The Company also issued a warrant to purchase 200,000 shares of Common Stock to Brushy's subordinated lender in exchange for extinguishment of certain debt owed by Brushy.
The fair value of each stock warrant issued is determined using the Black-Scholes-Merton pricing model based on the following variables as summarized in the table below(fair value in thousands):
| | | Fair Value
of Warrants | | | Number
of
Warrants | | | Stock Price | | | Exercise
Price | | | Expected
Volatility | | | Risk Free
Rate | | | Contractual
Life |
| As of December 31, 2016: | | | | | | | | | | | | | | | | | | | | |
| Warrants issued for Series B Preferred Stock | | $ | 9,486 | | | | 9,090,926 | | | $ | 1.30 | | | $ | 2.50 | | | | 238 | % | | | 0.78 | % | | 2 years |
| Warrants issued for Series B Preferred Stock offering fees | | $ | 1,590 | | | | 1,272,724 | | | $ | 1.30 | | | $ | 1.30 | | | | 238 | % | | | 0.92 | % | | 3 years |
| Warrants issued with Convertible Notes | | $ | 1,446 | | | | 975,051 | | | $ | 1.70 | | | $ | 1.00 | | | | 245 | % | | | 0.75 | % | | 2 years |
| Warrants issued with Convertible Notes | | $ | 277 | | | | 170,187 | | | $ | 1.70 | | | $ | 1.10 | | | | 245 | % | | | 0.75 | % | | 3 years |
| Warrants issued to amend convertible debts | | $ | 1,625 | | | | 1,648,270 | | | $ | 1.12 | | | $ | 2.50 | | | | 203 | % | | | 0.76 | % | | 3 years |
| Warrants issued to SOS | | $ | 170 | | | | 200,000 | | | $ | 1.20 | | | $ | 25.00 | | | | 199 | % | | | 0.76 | % | | 3 years |
| Additional warrants issued to Bristol | | $ | 1,214 | | | | 541,026 | | | $ | 3.10 | | | $ | 3.12 | | | | 101 | % | | | 1.38 | % | | 3 years |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2015: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Warrants issued for bridge term loan | | $ | 1,222 | | | | 1,180,000 | | | $ | 2.48 | | | $ | 2.89 | | | | 170 | % | | | 0.20 | % | | 3 years |
| Warrants issued for consultants | | $ | 425 | | | | 60,000 | | | $ | 23.30 | | | $ | 42.50 | | | | 99 | % | | | 1.29 | % | | 5 years |
| Warrants issued for Heartland Bank | | $ | 56 | | | | 22,500 | | | $ | 25.00 | | | $ | 25.00 | | | | 99 | % | | | 1.29 | % | | 5 years |
In connection with the May Financing, in exchange for additional consideration in the form of participation in the May Convertible Notes offering, certain Purchasers received amended and restated warrants to purchase approximately 620,000 shares of Common Stock, which reduced the exercise price of the warrants issued to these Purchasers in each of the prior two Convertible Notes issuances from $2.50 to $0.10, 80,000 of which were subsequently exercised. Additionally, during the three months ended June 30, 2016, in exchange for several offers to immediately exercise a portion of each investor’s outstanding warrants issued between 2013 and 2014, the Company reduced the exercise price on warrants to purchase a total of 416,454 shares of Common Stock ranging from $42.50 to $25.00 per share to $0.10 per share, of which a total of 315,990 were subsequently exercised, resulting in the issuance of an aggregate amount of 300,706 shares of Common Stock due to certain cashless exercises. The Company accounted for the reduction in the exercise price as an inducement expense and recognized $1.72 million in other income (expense).
Additionally, in connection with the Credit and Guarantee Agreement, as partial consideration to the Lenders, the Company also amended certain warrants issued in the Series B private placement held by the Lenders to purchase up to an aggregate amount of approximately 3.5 million shares of Common Stock to date, such that the exercise price per share was lowered from $2.50 to $0.01 on such warrants. The number of warrants amended for each Lender was based on the amount of each Lender’s respective participation in the initial Term Loan relative to the amount invested in the Series B private placement. All of the amended warrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions. For a more detailed description of the terms of the Credit and Guarantee Agreement and the warrant reprice see “Note 8—Loan Agreements—Credit and Guarantee Agreement.”
NOTE 13 – SHARE BASED AND OTHER COMPENSATION
Share-Based Compensation
On April 20, 2016, the Company’s Board and the Compensation Committee of the Board approved the Company’s 2016 Omnibus Incentive Plan (the “2016 Plan”). On November 3, 2016, the Company’s stockholders voted to increase numberAs of December 31, 2019, 5.4 million shares of Common Stockthe 18 million shares of the Company’s
common stock authorized for
issuanceawards under the 2016 Plan
remained available for future issuances. The Company generally issues new shares to
10.0 million.Duringsatisfy awards under employee stock based payment plans. The Company no longer grants any awards under the Lilis 2012 Omnibus Incentive Plan (the “2012 Plan”).
The following table sets forth the stock based compensation expense recognized during the years ended December 31, 2019 and 2018 and the unamortized portion of the stock based compensation expense and weighted average amortization period of the remaining vesting period for the year ended December 31, 2016,2019 and 2018, the Company’s share-based compensation consisted of the following (dollars in thousands):
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| | Stock Options | | Restricted Stock | | Total | | Stock Options | | Restricted Stock | | Total |
| Share based compensation expensed | $ | 317 |
| | $ | 6,189 |
| | $ | 6,506 |
| | $ | 2,158 |
| | $ | 6,842 |
| | $ | 9,000 |
|
| Unrecognized share-based compensation costs | $ | 100 |
| | $ | 1,228 |
| | $ | 1,328 |
| | $ | 487 |
| | $ | 3,501 |
| | $ | 3,988 |
|
| Weighted average amortization period remaining (in years) | 1.55 |
| | 1.05 |
| |
|
| | 0.03 |
| | 0.50 |
| |
|
|
Restricted Stock
Employees may be granted restricted stock in the form of restricted stock awards or restricted stock units. Restricted stock is subject to forfeiture restrictions and cannot be sold, transferred, or disposed of during the restriction period. The holders of restricted stock awards have the same rights as a stockholder of the Company
granted 120,000with respect to such shares,
including the right to vote and receive dividends or other distributions paid with respect to the shares. Restricted stock vests over service periods ranging from the date of grant generally up to two or three years. The company expenses the grant date fair value of restricted
Common Stockshares, determined to
certain nonemployee directors in connection with eachbe share price on the date of
their appointment anniversaries pursuant to each director's nonemployee director award agreement and 85,000 shares of restricted Common Stock as Board fees for the quarter ended December 31, 2015, paid in stock in lieu of cash. During the year ended December 31, 2016, the Company also issued (i) 10,000 restricted stock units and options to purchase 45,000 shares of Common Stock under the 2016 Plan to a newly appointed director pursuant to his nonemployee director award and 32,052 shares of restricted common stock as compensation for consulting services. Additionally, during the year ended December 31, 2016, the Company granted options to purchase a total of 5,683,500 shares of Common Stock to management and employees under the 2016 Plan.During the year ended December 31, 2016, certain of the Company's employees, directors and consultants forfeited 26,483 restricted stock units and 335,000 options to purchase Common Stock previously granted in connection with various terminations and forfeitures.
As a result, as of December 31, 2016, the Company had 149,584 restricted stock units, 1,068,305 restricted shares, and 5,956,833 options to purchase shares of Common Stock outstanding to employees and directors. Options issued to employees vest in equal installmentsgrant, ratably over specified time periods during the service period or upon achievement of certain performance based operating thresholds.
The Company requires that employees and directors pay the tax on equity grants in order to issue the shares and there is currently no cashless exercise option. As of December 31, 2016, 149,584 restricted stock units and 1,780,052 restricted shares have been granted, but have not been issued.
Compensation Costs (in thousands)
| | | As of December 31, 2016 | | | As of December 31, 2015 | |
| | | Stock
Options | | | Restricted
Stock | | | Total | | | Stock
Options | | | Restricted
Stock | | | Total | |
| Stock-based compensation expensed | | $ | 4,475 | | | $ | 2,398 | | | $ | 6,873 | | | $ | 2,191 | | | $ | 469 | | | $ | 2,660 | |
| Unamortized stock-based compensation costs | | $ | 5,200 | | | $ | 1,249 | | | $ | 6,449 | | | $ | 2,091 | | | $ | 266 | | | $ | 2,357 | |
| Weighted average amortization period remaining* | | | 1.68 | | | | 1.45 | | | | | | | | 2.18 | | | | 1.05 | | | | | |
* Only includes directors and employees which the options vest over time instead of performance criteria which the performance criteria have not been met as of December 31, 2016 and 2015.
Restricted Stock
Summary of non-cash compensation in Statement of Changes in Stockholders’ Equity:
| | | As of December 31, | |
| | | 2016 | | | 2015 | |
| | | (In thousands) | |
| Statement of Stockholder’s Equity: | | | | | | | | |
| Common stock issued for directors’ fees | | $ | 85 | | | $ | 215 | |
| Common stock issued for officer and Board compensation | | | 120 | | | | - | |
| Stock based compensation for vesting of restricted stock | | | - | | | | 469 | |
| Stock based compensation for issuance of stock options | | | 4,475 | | | | 2,191 | |
| Stock based compensation for issuance of restricted stock | | | 2,398 | | | | - | |
| Common stock issued for professional services | | | - | | | | 150 | |
| Fair value of warrants issued for professional services | | | - | | | | 425 | |
| Total non-cash compensation in Statement of Changes in Stockholders’ Equity | | $ | 7,078 | | | $ | 3,450 | |
A summary of restricted stock grant activity pursuant to the
2012 Plan and the 2016 Plan for the year ended December 31,
20162019, is presented below:
| | | Number of
Shares | | | Weighted
Average Grant
Date Price | |
| Outstanding at January 1, 2016 | | | - | | | $ | - | |
| Granted | | | 1,780,052 | | | | 1.54 | |
| Vested and issued | | | (711,747 | ) | | | (1.75 | ) |
| Forfeited | | | - | | | | - | |
| Outstanding at December 31, 2016 | | | 1,068,305 | | | $ | 1.55 | |
There was no restricted
|
| | | | | | |
| | Number of Shares | | Weighted Average Grant Date Price |
| Outstanding at January 1, 2018 | 2,475,266 |
| | $ | 4.22 |
|
| Granted | 1,194,944 |
| | $ | 4.59 |
|
| Vested and issued | (1,436,146 | ) | | $ | 2.38 |
|
Forfeited or canceled (1) | (1,280,480 | ) | | $ | 4.44 |
|
| Outstanding at December 31, 2018 | 953,584 |
| | $ | 4.85 |
|
| Granted | 3,684,372 |
| | $ | 1.46 |
|
| Vested and issued | (2,341,269 | ) | | $ | 2.39 |
|
Forfeited or canceled (1) | (894,512 | ) | | $ | 2.94 |
|
| Outstanding at December 31, 2019 | 1,402,175 |
| | $ | 1.26 |
|
(1) Forfeitures are accounted for as and when incurred.
Stock Options
Employees may be granted incentive stock
options to purchase shares of the Company’s common stock with an exercise price equal to, or greater than, the fair market value of the Company’s common stock on the date of grant. These stock options generally vest over two years from the date of grant
activity forand terminate at the earlier of the date of exercise or ten years from the date of grant. During the year ended December 31,
2015.2018, the Company received cash proceeds of approximately $2.6 million from the exercise of vested stock options. There were no stock options exercised during the year ended December 31, 2019.
A summary of restricted stock unit grantoption activity pursuant to the 20122016 Plan for the years ended December 31, 20162019 and 20152018, is presented below. Share activitiesbelow:
|
| | | | | | | | | | | |
| | Number of Options | | Weighted Average Exercise Price | | Number of Options Vested/ Exercisable | | Weighted Average Remaining Contractual Life (Years) |
| Outstanding at January 1, 2018 | 7,305,000 |
| | $ | 3.74 |
| | 3,534,484 |
| | 8.9 |
| Granted | 352,500 |
| | $ | 4.07 |
| | | | |
| Exercised | (1,024,877 | ) | | $ | 2.67 |
| | | | |
| Forfeited or canceled | (1,601,045 | ) | | $ | 4.20 |
| | | | |
| Outstanding at December 31, 2018 | 5,031,578 |
| | $ | 3.81 |
| | 5,035,317 |
| | 7.9 |
| Granted | 135,000 |
| | $ | 2.17 |
| |
| |
|
| Exercised | — |
| | $ | — |
| |
| |
|
Forfeited or canceled (1) | (1,578,228 | ) | | $ | 3.14 |
| |
| |
|
| Outstanding at December 31, 2019 | 3,588,350 |
| | $ | 4.05 |
| | 4,125,842 |
| | 7.2 |
During the year ended December 31,
2015 have been adjusted for 1-for-10 reverse stock split on June 23, 2016.| | | Number of
Shares | | | Weighted
Average Grant
Date Price | |
| Outstanding at January 1, 2015 | | | 163,067 | | | $ | 24.40 | |
| Granted | | | 114,501 | | | | 9.00 | |
| Vested and issued | | | (77,835 | ) | | | 6.60 | |
| Forfeited | | | (12,833 | ) | | | 22.70 | |
| Outstanding at December 31, 2015 | | | 186,900 | | | | 12.29 | |
| Granted | | | - | | | | - | |
| Vested and issued | | | (10,834 | ) | | | (18.75 | ) |
| Forfeited | | | (26,482 | ) | | | (16.15 | ) |
| Outstanding at December 31, 2016 | | $ | 149,584 | | | $ | 10.56 | |
As of December 31, 2016, the total unrecognized compensation costs related to 1,217,889 unvested shares of restricted stock was approximately $1.2 million, which is expected to be recognized over a weighted-average remaining services period of 0.8 year. As of December 31, 2015, the Company had 151,900 shares vested but unissued and total unrecognized compensation cost related to the 34,999 unvested shares of restricted stock was approximately $266,000, which is expected to be recognized over a weighted-average remaining service period of 1.05 years.
Stock Options
A summary of stock2019, options activity for the years ended December 31, 2016 and 2015 is presented below:
| | | | | | | | | Stock Options Outstanding and
Exercisable | |
| | | Number
of Options | | | Weighted
Average
Exercise
Price | | | Number
of Options
Vested/
Exercisable | | | Weighted
Average
Remaining
Contractual Life
(Years) | |
| Outstanding at January 1, 2015 | | | 358,333 | | | $ | 21.60 | | | | 138,333 | | | | 4.24 | |
| Granted | | | 480,000 | | | $ | 12.60 | | | | | | | | | |
| Exercised | | | - | | | | | | | | | | | | | |
| Forfeited or cancelled | | | (230,000 | ) | | $ | (24.60 | ) | | | | | | | | |
| Outstanding at December 31, 2015 | | | 608,333 | | | $ | 14.60 | | | | 296,666 | | | | 4.10 | |
| Granted | | | 5,683,500 | | | | 2.14 | | | | | | | | | |
| Exercised | | | - | | | | | | | | | | | | | |
| Forfeited or cancelled | | | (335,000 | ) | | | (5.34 | ) | | | | | | | | |
| Outstanding at December 31, 2016 | | | 5,956,833 | | | $ | 2.04 | | | | 2,208,757 | | | | 1.68 | |
During 2016, option to purchase 5,683,500135,000 shares of the Company’s common stock were granted under the 2016 Plan. The weighted average fair valuesvalue of these options was $1.47 utilizing the weighted average expected term of $1.38. The fair values were determined using the Black-Scholes-Merton option valuation method assuming10 years, expected volatility of 30%, no expected dividends, aand risk-free interest rate of 1.08%,2.67%.
The Company estimates expected volatility based on an analysis of its historical stock prices since the initial public offering date in 2007. The Company estimates the expected term of its option awards based on the vesting period. The Company uses this method to provide a
weighted averagereasonable basis for estimating its expected
life of 4.12 years and weighted-average volatility of 152%As of December 31, 2016, total unrecognized compensation costs relatingterm due to the outstanding options was $5.2 million, which is expected to be recognized overlack of sufficient historical employee exercise data on stock option awards.
NOTE 18 - INCOME (LOSS) PER COMMON SHARE
The following table shows the
remaining vesting periodcomputation of
approximately 3.68 years.The outstanding options have an intrinsic value of approximately $12.3 million at December 31, 2016.
During the year ended December 31, 2016basic and 2015, the Company issued options to purchase shares of Common Stock to certain officers and directors. The options are valued using a Black Scholes model and amortized over the life of the option. Duringdiluted net loss per share for the years ended December 31, 20162019 and 2015,2018 (in thousands):
|
| | | | | | | |
| | 2019 | | 2018 |
| Net loss | $ | (272,121 | ) | | $ | (4,143 | ) |
| Dividends on preferred stock | (25,397 | ) | | (10,687 | ) |
| Unallocated net loss | $ | (297,518 | ) | | $ | (14,830 | ) |
| | | | |
| Numerator for basic loss per share: | | | |
| Net loss attributable to common stockholders | $ | (297,518 | ) | | $ | (14,830 | ) |
| | | | |
| Denominator for basic loss per share: | | | |
| Basic weighted average common shares outstanding | 87,912,362 |
| | 62,854,214 |
|
| | | | |
| Net loss per share: | | | |
| Basic attributable to common stockholders | $ | (3.38 | ) | | $ | (0.24 | ) |
| | | | |
| Numerator for diluted loss per share: | | | |
| Net loss attributable to common stockholders | $ | (297,518 | ) | | $ | (14,830 | ) |
| Add: interest expense on convertible Second Lien Term Loan | — |
| | 13,429 |
|
| Less: gain on fair value change of embedded derivatives associated with Second Lien Term Loan | — |
| | (35,471 | ) |
| Net loss attributable to common stockholders | $ | (297,518 | ) | | $ | (36,872 | ) |
| | | | |
| Denominator for diluted net loss per share: | | | |
| Basic weighted average common shares outstanding | 87,912,362 |
| | 62,854,214 |
|
| Dilution effect of if-converted Second Lien Term Loan | — |
| | 15,597,127 |
|
| Diluted weighted average common shares outstanding | 87,912,362 |
| | 78,451,341 |
|
| | | | |
| Net loss per share - diluted: | | | |
| Common shares (diluted) | $ | (3.38 | ) | | $ | (0.47 | ) |
The Company excluded the following shares from the diluted loss per share calculations above because they were anti-dilutive at December 31, 2019 and 2018:
|
| | | | | |
| | December 31, |
| | 2019 | | 2018 |
| Stock Options | 3,588,350 |
| | 5,031,578 |
|
| Series C Preferred Stock | — |
| | 26,295,616 |
|
| Series D Preferred Stock | — |
| | 8,543,670 |
|
| Stock Purchase Warrants | 2,754,062 |
| | 5,017,329 |
|
| Series E Preferred Stock | 25,667,871 |
| | — |
|
| Conversion of term loans | — |
| | — |
|
| | 32,010,283 |
| | 44,888,193 |
|
NOTE 19 - SUPPLEMENTAL NON-CASH TRANSACTIONS
The following table presents the supplemental disclosure of cash flow information for the years ended December 31, 2019 and 2018:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| | (in thousands) |
| Non-cash investing and financing activities excluded from the statement of cash flows: | | | |
| Issued shares of common stock and preferred stock upon extinguishment of debt and modification of Series C Preferred Stock and Series D Preferred Stock | $ | 141,787 |
|
| $ | 64,504 |
|
| Common stock issued for acquisition of oil and natural gas properties | — |
| | 24,778 |
|
| Cashless exercise of warrants | — |
| | 359 |
|
| Deferred revenue realized upon purchase option exercise | 16,700 |
| | — |
|
| Right of use assets obtained in exchange for operating lease obligations | 7,500 |
| | — |
|
| Change in capital expenditures for drilling costs in accrued liabilities | 2,010 |
| | 7,850 |
|
| Accrued cumulative paid in kind dividends on preferred stock | 25,397 |
| | 10,687 |
|
| Change in asset retirement obligations | 546 |
| | 1,495 |
|
| Reduction of fair value for converted embedded derivatives | — |
| | 12,406 |
|
| Transfer of warrant derivative instruments to equity | — |
| | 223 |
|
NOTE 20 - SEGMENT INFORMATION
Operating segments are defined as components of an entity that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and are regularly evaluated by the chief operating decision maker for the purposes of allocating resources and assessing performance. The Company currently has only one reportable operating segment, which is oil and natural gas development, exploration and production, for which the Company
amortized $4.5 millionhas a single management team that allocates capital resources to maximize profitability and
$2.19 million, respectively relating to options outstanding.measures financial performance as a single entity.
NOTE 14 –21 - COMMITMENTS AND CONTINGENCIES
ARM Sales Agreement
On August 2, 2018, the Company executed a five-year agreement with SCM Crude, LLC, an affiliate of SCM, to secure firm takeaway pipeline capacity and pricing on a long-haul pipeline to the Gulf Coast region commencing July 1, 2019. On March 11, 2019, the agreement was replaced with a five-year agreement between the Company and ARM, a related company to SCM. The new agreement accelerated the start date to March 2019 and guarantees firm takeaway capacity on a long-haul pipeline to Corpus Christi, Texas, once completed, at a specified price. Under the terms of the new contract, the Company received pricing differentials on the crude oil sales contract subject to minimum quantities of crude oil to be delivered as follows:
|
| |
| Date | Quantity (Barrels per Day) |
| March 2019 - June 2019 | 5,000 |
| July 2019 - December 2019 | 4,000 |
| January 2020 - June 2020 | 5,000 |
| July 2020 - June 2021 | 6,000 |
July 2021 - December 2024 (1) | 7,500 |
Supplemental Non-cash Transactions(1) Extending to the later of December 2024 or 5 years from the EPIC Crude Oil pipeline in-service date (February 2025).
Further, ARM has agreed to purchase crude from the Company based upon Magellan East Houston pricing with a fixed “differential basis”. As of December 31, 2019, the agreement no longer meets the criteria for the “normal purchase normal sales” exception under ASC 815, “Derivatives and Hedging”, due to the Company not meeting the minimum quantities deliverable under the contract and the net settlement criteria being met. See Note 9 - Derivatives for information regarding the recognition of the net settlement mechanism as an embedded derivative over the remainder of the contract.
Environmental and Governmental Regulation
As of December 31, 2019, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and natural gas industry are extensively regulated by federal, state, and local governments and regulatory agencies in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, land use, taxation, and various other matters. Oil and natural gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2019, the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect on the financial condition of the Company.
Legal Proceedings
The Company may from time to time be involved in various legal actions arising in the ordinary course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company.
The Company believes there is no litigation pending that could have, individually or in the aggregate, a material adverse effect on its results of operations or financial condition.
Liens
As of the most recent date available, statutory mechanic's and materialman’s liens which remain unpaid in the amount of $8.7 million have been filed against the related assets.
NOTE 22 - SUBSEQUENT EVENTS
COVID-19
On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency due to the COVID-19 outbreak, which originated in Wuhan, China, and the risks to the international community as the virus spreads globally beyond its point of origin. In March 2020, the WHO classified the COVID-19 outbreak as a pandemic, based on the rapid increase in exposure globally.
In addition, in March 2020, members of OPEC failed to agree on production levels which has caused an increased supply and has led to a substantial decrease in oil prices and an increasingly volatile market. The oil price war ended with a deal to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand. There has been an increase in supply which has pushed prices down further since March. If the depressed pricing continues for an extended period it will lead to i) additional reductions in the borrowing base under our credit facility which would require us to make additional borrowing base deficiency payments, ii) reductions in reserves, and iii) additional impairment of proved and unproved oil and gas properties. We also expect disclosures of supplemental oil and gas information to be impacted by price declines.
In response to recent commodity prices and our efforts to strengthen our capital through reducing operating costs, during April 2020 the Company elected to shut-in 12 wells which were identified as uneconomic as a result of the continued decline in commodity prices in 2020 and 19 additional wells have been identified for short term shut-in through May and June. The 19 wells identified for short term shut-in are naturally flowing wells and could be turned back to sales quickly as market conditions dictate. The Company has also implemented an employee furlough program to further reduce general and administrative costs. The furloughed employees will not receive compensation from the Company during the furlough period; however, subject to local regulations, these employees will be eligible for unemployment benefits. The furlough period is uncertain at this time and will be reassessed as business conditions dictate.
The full impact of the COVID-19 outbreak and the decline in oil prices continues to evolve as of the date of this Annual Report. As such, it is uncertain as to the full magnitude that they will have on the Company’s financial condition, liquidity, and future results of operations.
Management is actively monitoring the global situation on its financial condition, liquidity, operations, suppliers, industry, and workforce. Given the daily evolution of the COVID-19 outbreak and the global responses to curb its spread, the Company is not able to estimate the effects of the COVID-19 outbreak on its results of operations, financial condition, or liquidity for fiscal year 2020.
These matters could have a continued material adverse impact on economic and market conditions and trigger a period of global economic slowdown, which may impair the Company’s asset values, including reserve estimates. Further, consumer demand has decreased since the spread of the outbreak and new travel restrictions placed by governments in an effort to curtail the spread of the coronavirus. Although the Company cannot estimate the length or gravity of the impacts of these events at this time, if the pandemic and/or decreased oil prices continue, they will have a material adverse effect on the Company’s results of future operations, financial position, and liquidity in fiscal year 2020.
Coronavirus Aid, Relief, and Economic Security Act
On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations, increased limitations on qualified charitable contributions, and technical corrections to tax depreciation methods for qualified improvement property.
It also appropriated funds for the SBA Paycheck Protection Program loans that are forgivable in certain situations to promote continued employment, as well as Economic Injury Disaster Loans to provide liquidity to small businesses harmed by COVID-19. There is no assurance we are eligible for these funds or will be able to obtain them.
We continue to examine the impact that the CARES Act may have on our business. Currently, we are unable to determine the impact that the CARES Act will have on our financial condition, results of operations, or liquidity.
Lilis Energy, Inc. and Subsidiaries
Supplementary Information on Oil and Natural Gas Exploration,
Development and Production Activities
(Unaudited)
The Company’s oil and natural gas reserves are attributable solely to properties within the United States, which constitutes one cost center.
Costs Incurred for Oil and Natural Gas Producing Activities
The following table presents information about supplemental cash flowssets forth the costs incurred in the Company’s oil and natural gas acquisition, exploration and development activities and includes costs whether capitalized or expensed as well as revisions and additions to the estimated future asset retirement obligations:
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| | (In thousands) |
| Acquisition costs: | |
| | |
|
| Unproved properties | $ | 1,644 |
| | $ | 93,926 |
|
| Proved properties | — |
| | 22,356 |
|
| Exploration costs | 40,284 |
| | 89,351 |
|
| Development costs | 51,198 |
| | 78,103 |
|
| Total | $ | 93,126 |
| | $ | 283,736 |
|
Results of Operations for Oil and Natural Gas Producing Activities
The following table sets forth the results of operations for oil and natural gas producing activities:
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| | (In thousands) |
| Revenues | $ | 66,063 |
| | $ | 70,216 |
|
| Production costs | (16,127 | ) | | (13,843 | ) |
| Production taxes | (3,302 | ) | | (3,709 | ) |
| Accretion of asset retirement obligation | (433 | ) | | (85 | ) |
| Depletion, depreciation and amortization | (33,071 | ) | | (25,159 | ) |
| Full cost ceiling impairment | (228,324 | ) | | — |
|
| Total | $ | (215,194 | ) | | $ | 27,420 |
|
Reserves Quantity Information
The following table provides a roll forward of the total proved reserves for the years ended December 31, 20162019 and 2015(in thousands);| | | 2016 | | | 2015 | |
| Non-cash investing and financing activities excluded from the statement of cash flows: | | | | | | | | |
| Common stock issued for Series A Preferred Stock and accrued dividends | | | 7,682 | | | | - | |
| Common stock issued for convertible notes and accrued interest | | | 14,872 | | | | - | |
| Common stock issued for Brushy’s common stock | | | 7,111 | | | | - | |
| Common stock issued for Series B Preferred Stock and accrued dividends | | | 3,230 | | | | - | |
| Warrants issued for fees associated with Series B Preferred Stock issuance | | | 1,590 | | | | - | |
| Warrants issued for Series B Preferred Stock issuance and recorded as a deemed dividend | | | 7,879 | | | | - | |
| Fair value of warrants issued as debt discount and financing costs | | | 2,192 | | | | 1,222 | |
| Disposition of oil and gas assets for elimination of accrued expense for drilling | | | - | | | | 5,198 | |
NOTE 15 – SUBSEQUENT EVENTS
Credit Agreement Drawdown
On February 7, 2017, pursuant to2018, as well as proved developed and proved undeveloped reserves at the terms of the Credit Agreement, we exercised the accordion advance feature, increasing the aggregate principal amount outstanding under the term loan from $31 million to $38.1 million. The total availability for borrowing remaining under the Credit Agreement is $11.9 million. We intend to use the proceeds to fund its drillingbeginning and development program, for working capital and for general corporate purposes.
As partial consideration, we also amended certain warrants issued in the June 2016 private placement held by the Lenders to purchase up to an aggregate amount of approximately 738,638 shares of common stock such that the exercise price per share was lowered from $2.50 to $0.01 on such warrants The number of warrants amended for each Lender was based on the amountend of each Lender’s respective participation inyear:
|
| | | | | | | | |
| | Crude Oil (Bbls) | | Natural Gas (Mcf) | | NGLs (Bbls) |
| January 1, 2018 | 7,171,339 |
| | 16,059,926 |
| | 1,604,570 |
|
| Extensions and discoveries | 15,881,727 |
| | 38,957,588 |
| | 4,565,994 |
|
| Purchase of reserves | 1,883,047 |
| | 8,897,115 |
| | 682,964 |
|
| Revisions of previous estimates | (2,641,353 | ) | | 17,690,723 |
| | 1,769,448 |
|
| Production | (1,089,724 | ) | | (2,855,739 | ) | | (246,425 | ) |
| December 31, 2018 | 21,205,036 |
| | 78,749,613 |
| | 8,376,551 |
|
| Extensions and discoveries | 856,838 |
| | 2,477,061 |
| | 190,203 |
|
| Revisions of previous estimates | (15,596,115 | ) | | (48,718,235 | ) | | (6,067,700 | ) |
| Production | (1,130,855 | ) | | (3,063,927 | ) | | (220,832 | ) |
| December 31, 2019 | 5,334,904 |
| | 29,444,512 |
| | 2,278,222 |
|
| |
| |
| |
|
| Proved Developed Reserves, included above: |
| |
| |
|
| Balance, January 1, 2018 | 2,531,397 |
| | 6,594,446 |
| | 644,102 |
|
| Balance, December 31, 2018 | 6,278,036 |
| | 27,046,195 |
| | 2,653,908 |
|
| Balance, December 31, 2019 | 5,334,904 |
| | 29,444,512 |
| | 2,278,222 |
|
| Proved Undeveloped Reserves, included above: |
| |
| |
|
| Balance, January 1, 2018 | 4,639,942 |
| | 9,465,480 |
| | 960,468 |
|
| Balance, December 31, 2018 | 14,927,000 |
| | 51,703,418 |
| | 5,722,643 |
|
| Balance, December 31, 2019 | — |
| | — |
| | — |
|
Extensions and discoveries of 1.5 MBOE during the
initial Term Loan relative to the amount invested in the June 2016 private placement. All of the amended warrants are immediately exercisable from the original issuance date, for a period of two years, subject to certain conditions.March 2017 Private Placement
On February 28, 2017, we entered into a Securities Subscription Agreement (the “Subscription Agreement”) with certain institutional and accredited investors in connection with a private placement (the “March 2017 Private Placement”) to sell 5.2 million units, consisting of approximately 5.2 million shares of common stock and warrants to purchase approximately an additional 2.6 million. Each unit consists of one share of common stock and a warrant to purchase 0.50 shares of common stock (each, a “Unit”), at a price per unit of $3.85. Each warrant has an exercise price of $4.50 and may be subject to redemption by the Company, upon prior written notice, if the price of the Company’s common stock closes at or above $6.30 for twenty trading days during a consecutive thirty trading day period. The closing of the Offering is subject to the satisfaction of customary closing conditions.
We expect to use the net proceeds from the Offering to support our planned 2017 capital budget, and for general corporate purposes including working capital.
The securities to be sold in the private placement have not been registered under the Securities Act or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from registration. However, in conjunction with the closing of the March 2017 Private Placement, we have also entered into a registration rights agreement whereby we agreed to use our reasonable best efforts to register, on behalf of the investors, the shares of common stock underlying the Units and the shares of common stock underlying the warrants no later than April 1, 2017.
Our 2017 capital budget may require additional financing above the level of cash generated by our operations and proceeds from recent financing activities. We can provide no assurance that additional financing would be available to us on acceptable terms, if
NOTE 16 – SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The following table sets forth information for the yearsyear ended December 31, 2016 and 2015 with respect to changes2019, resulted from the drilling of exploratory wells during the year that are included in the Company's proved (i.e. proved developed and undeveloped) reserves:
| | | Crude Oil
(Bbls) | | | Natural Gas
(Mcf) | |
| December 31, 2014 | | | 899,727 | | | | 4,237,241 | |
| Purchase of reserves | | | - | | | | - | |
| Revisions of previous estimates | | | (859,230 | ) | | | (4,063,500 | ) |
| Extensions, discoveries | | | - | | | | - | |
| Sale of reserves | | | - | | | | - | |
| Production | | | (7,067 | ) | | | (32,291 | ) |
| December 31, 2015 | | | 33,430 | | | | 141,450 | |
| Purchase of reserves | | | 93,972 | | | | 292,018 | |
| Revisions of previous estimates | | | 455,202 | | | | 3,506,794 | |
| Extensions, discoveries | | | | | | | | |
| Sale of reserves | | | | | | | | |
| Production | | | (31,899 | ) | | | (68,756 | ) |
| December 31, 2016 | | | 550,705 | | | | 3,871,506 | |
| | | | | | | | | |
| Proved Developed Reserves, included above: | | | | | | | | |
| Balance, December 31, 2014 | | | 50,185 | | | | 197,146 | |
| Balance, December 31, 2015 | | | 33,430 | | | | 141,450 | |
| Balance, December 31, 2016 | | | 550,705 | | | | 3,871,506 | |
| Proved Undeveloped Reserves, included above: | | | | | | | | |
| Balance, December 31, 2014 | | | 849,542 | | | | 4,040,095 | |
| Balance, December 31, 2015 | | | - | | | | - | |
| Balance, December 31, 2016 | | | - | | | | - | |
As of December 31, 2016 and December 31, 2015, the Company had estimated proved reserves of 550,705 and 33,430 barrels of oil, respectively and 3,871,506 and 141,450 thousand cubic feet (“MCF”) of natural gas, respectively. The Company’s reserves are comprised of 46% and 59% crude oil and 54% and 41% natural gas on an energy equivalent basis,productive wells as of December 31, 20162019.
Revisions of previous reserves estimates decreased 2019 proved reserves by 29.8 MBOE. Reserves decreased by approximately 8.3 MBOE as a result of lower SEC pricing and costs for 2019 compared to 2018, as well as operational factors. The remaining revisions of 21.5 MBOE were the result of reclassification of all PUD reserves to unproved because of the uncertainty regarding the availability of capital to us for development these reserves as of December 31, 2015, respectively.2019.
Standardized Measure of Discounted Future Net Cash Flows
The following valuesstandardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the properties. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties and consideration of expected future economic and operating conditions.
The estimates of future cash flows and future production and development costs as of December 31, 2019 and 2018 are based on the unweighted arithmetic average first-day-of-the-month price for the
December 31, 2016preceding 12-month period. Estimated future production of proved reserves and
December 31, 2015 oilestimated future production and
gasdevelopment costs of proved reserves are based on
current costs and economic conditions which are held constant throughout the
12 month arithmetic average firstlife of
month price January through December 31; resulting in a natural gas price of $2.05 and $2.79 per MMBtu (NYMEX price), respectively, and crude oil price of $37.30 and $42.59 per barrel (West Texas Intermediate price), respectively.the properties. All
wellhead prices are
held flat over the forecast period for all reserves categories. The estimated future net cash flows are then
further adjusted for transportation, quality and basis differentials.discounted at a rate of 10%.
The following summary sets forth the Company'sstandardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves is as follows:
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| | (In thousands) |
| Future cash inflows | $ | 358,127 |
| | $ | 1,500,263 |
|
| Future production costs | (176,498 | ) | | (414,117 | ) |
| Future development costs | (7,284 | ) | | (346,225 | ) |
| Future income tax expense | — |
| | (62,842 | ) |
| Future net cash flows | 174,345 |
| | 677,079 |
|
| 10% discount to reflect timing of cash flows | (54,171 | ) | | (384,345 | ) |
| Total | $ | 120,174 |
| | $ | 292,734 |
|
In the foregoing determination of future cash inflows, sales prices used for oil, natural gas and NGLs for December 31, 2019 and 2018, were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved natural gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions.
At December 31, 2019, the tax basis of our oil and gas
reserves(properties exceeded the pre-tax cash inflows; therefore, in thousands):| | | For the Year Ended
December 31, | |
| | | 2016 | | | 2015 | |
| Future oil and gas sales | | $ | 28,514 | | | $ | 1,819 | |
| Future production costs | | | (15,939 | ) | | | (983 | ) |
| Future development costs | | | (3,388 | ) | | | - | |
| Future income tax expense (1) | | | - | | | | - | |
| Future net cash flows | | | 9,187 | | | | 836 | |
| 10% annual discount | | | (2,531 | ) | | | (228 | ) |
| Standardized measure of discounted future net cash flows | | $ | 6,656 | | | $ | 608 | |
the preparation of the Standardized Measure no future taxable income is expected to be generated from our oil and natural gas properties, primarily due to the reclassification of all PUD reserves to unproved because of the uncertainty regarding the availability of capital for developing those reserves. The principal sourcesCompany cautions that the disclosures shown are based on estimates of changeproved reserves quantities and future production schedules which are inherently imprecise and subject to revision and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations and no value may be assigned to probable or possible reserves.
Changes in the standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves are( as follows:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| | (In thousands) |
| Balance at beginning of period | $ | 292,734 |
| | $ | 68,812 |
|
| Net changes in prices and production costs (1) | (275,539 | ) | | 24,261 |
|
| Sales of oil and natural gas produced during the year, net | (42,442 | ) | | (49,271 | ) |
| Changes in estimated future development costs (2) | 272,579 |
| | (39,938 | ) |
| Net change due to extensions and discoveries | 18,044 |
| | 161,785 |
|
| Net change due to purchases of minerals in place | — |
| | 55,278 |
|
| Previously estimated development costs incurred during the year | 36,298 |
| | 68,349 |
|
| Net changes due to revision of previous quantity estimates (3) | (255,125 | ) | | 28,350 |
|
| Accretion of discount | 29,273 |
| | 6,881 |
|
| Other - unspecified (4) | 9,327 |
| | 3,252 |
|
| Net change in income taxes | 35,025 |
| | (35,025 | ) |
| Balance at end of period | $ | 120,174 |
| | $ | 292,734 |
|
(1) Net changes from prices and production costs were primarily the result of a 19% decrease in thousands):| | | 2016 | | | 2015 | |
| Balance at beginning of period | | $ | 608 | | | $ | 23,254 | |
| Sales of oil and gas, net | | | (1,989 | ) | | | (146 | ) |
| Net change in prices and production costs | | | (309 | ) | | | (26,115 | ) |
| Net change in future development costs | | | 4,617 | | | | 20,626 | |
| Extensions and discoveries | | | - | | | | - | |
| Acquisition of reserves | | | 7,919 | | | | - | |
| Sale / conveyance of reserves | | | - | | | | - | |
| Revisions of previous quantity estimates | | | 1,087 | | | | (19,336 | ) |
| Previously estimated development costs incurred | | | (8,942 | ) | | | - | |
| Net change in income taxes | | | - | | | | - | |
| Change in timing and other | | | 3,630 | | | | - | |
| Accretion of discount | | | 35 | | | | 2,325 | |
| Balance at end of period | | $ | 6,656 | | | $ | 608 | |
(1) | Calculations of the standardized measure of discounted future net cash flows include the effect of estimated future income tax expenses for all years reported. The Company expects that all of its Net Operating Loss’ (“NOL”) will be realized within future carry forward periods. All of the Company's operations, and resulting NOLs, are attributable to its oil and gas assets. |
A varietyoil and natural gas prices and 45% increase in production costs from December 31, 2018 to December 31, 2019.
(2) Future development costs decreased $272.6 million from December 31, 2018 to December 31, 2019. Our December 31, 2019 proved reserves report reflects the reclassification of methodologiesall PUD reserves to unproved because of the uncertainty regarding the availability of capital for developing those reserves. Our December 31, 2018 proved reserves report included future development costs of $329.5 million associated with PUD reserves not included in our December 31, 2019 proved reserves report.
(3) Negative revisions for 2019 are usedprimarily the result of the reclassification of proved undeveloped reserves to determineunproved as reflected in our December 31, 2019 reserves report.
(4) Other changes are the
Company’sresult of significant changes to our proved
reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysisreserves from December 31, 2018 to December 31, 2019 and
analogy. Some combinationinclude significant estimates of
these methods is usedthe effects of changes in the economic lives of producing wells and reclassification of proved undeveloped reserves to
determine reserve estimatesunproved as reflected in
substantially all of our
fields.December 31, 2019 reserves report.