10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☑	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2019
	OR
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to _________

Commission File Number 001‑36302

Sundance Energy Inc.

(Exact name of Registrant as specified in its Charter)

Delaware	61‑1949225
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1050 17th Street, Suite 700, Denver, CO	80265
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (303) 543‑5700

Securities Registered Pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of Exchange on Which Registered
Common Stock, par value $0.001 per share	SNDE	The Nasdaq Stock Market LLC

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES ☐ NO ☑

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. YES ☐ NO ☑

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES ☑ NO ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files). YES ☑ NO ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definition of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☑
Non-accelerated filer	☐	Smaller reporting company	☑
		Emerging growth company	☑

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES ☐ NO ☑

The aggregate market value of the registrant’s common stock held by non-affiliates, based on the closing price of the registrant’s common stock as of the last business day of the registrant’s most recently completed second fiscal quarter, was $131,992,965. The number of outstanding shares of the registrant’s common stock as of April 24, 2020 was 6,875,672.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s Definitive Proxy Statement on Schedule 14A relating to its 2020 annual meeting of stockholders to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended.

Table of Contents

PART I
Item 1.	Business	4
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	41
Item 2.	Properties	41
Item 3.	Legal Proceedings	41
Item 4.	Mine Safety Disclosures	41
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	41
Item 6.	Selected Financial Data	42
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 8.	Financial Statements and Supplementary Data	55
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	55
Item 9A.	Controls and Procedures	56
Item 9B.	Other Information	57
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	57
Item 11.	Executive Compensation	57
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	57
Item 13.	Certain Relationships and Related Transactions, and Director Independence	58
Item 14.	Principal Accounting Fees and Services	58
PART IV
Item 15.	Exhibits Financial Statement Schedules	58
Item 16	Form 10‑K Summary	58
EXHIBIT INDEX		101
SIGNATURES		105

i

Glossary of Selected Oil and Natural Gas Terms

All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this annual report on Form 10-K (this “annual report”). As used in this document:

Bbl.One stock tank barrel, or 42 U.S. gallons liquid volume, of oil or other liquid hydrocarbons.

Boe.Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Boe/d.Barrels of oil equivalent per day.

Completion. A process of treating a drilled well, including hydraulic fracturing among other stimulation processes, followed by the installation of permanent equipment for the production of oil or gas.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Held-by-production acreage. Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or gas.

Hydraulic fracturing or fracking. The technique of pumping a mixture of fluids into a well to rupture the rock, creating artificial channels. As part of this technique, sand or other material may also be injected into the formation to keep the channels open, so that fluids or natural gases may more easily flow through the formation.

MBoe. Thousand barrels of oil equivalent with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

MMBoe. Million barrels of oil equivalent with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Mcf. Thousand cubic feet of natural gas.

MMBtu. Million British Thermal Units.

Natural gas liquids or NGLs. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be. An owner who has 50% interest in 100 acres owns 50 net acres.

NYMEX. New York Mercantile Exchange.

Proved reserves. Those reserves 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, and under existing economic conditions, operating methods, and government regulation 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 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.

1

Proved undeveloped reserves or PUD. 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. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas regardless of whether or not such acreage contains proved reserves.

Working interest. A cost-bearing interest under an oil and gas lease that gives the holder the right to develop and produce the minerals under the lease.

Workover. The repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

WTI. means the West Texas Intermediate spot price.

Cautionary Statement Regarding Forward-Looking Statements

Certain statements contained in this annual report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements are identified by the use of the words “project,” “believe,” “estimate,” “expect,” “anticipate,” “intend,” “contemplate,” “foresee,” “would,” “could,” “plan,” and similar expressions that are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that are anticipated. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

· our assumptions about energy markets;

· our ability to execute our business strategies;

· the volatility of realized oil, natural gas and NGL prices;

· general economic, business and industry conditions;

· the overall supply and demand for oil and natural gas, and regional supply and demand factors, delays, or interruptions of production;

· our ability to replace our oil, natural gas and NGL reserves;

· our ability to identify, complete and integrate acquisitions;

· competition in the oil and natural gas industry;

· the ability to obtain capital or financing needed for development and exploration operations on favorable terms, or at all;

2

· title defects in our properties;

· uncertainties inherent in estimating oil, gas and NGL reserves;

· the extent to which we are successful in acquiring and discovering additional reserves;

· our ability to obtain permits and licenses;

· the availability or cost of rigs, equipment, raw materials, supplies, oilfield services or personnel;

· the potential impact of government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, oil and natural gas drilling, air emissions and climate change, conservation measures, regulatory determinations, litigation and competition;

· the availability of pipeline capacity and transportation facilities;

· operating hazards and other risks associated with oil and gas operations;

· the cost of inflation;

· impairments of proved or unproved properties or other long-lived assets;

· the impact of derivative instruments;

· our ability to realize the benefits of our redomiciliation from Australia to the United States;

· our dependence on our key personnel;

· the outbreak of communicable diseases, such as coronavirus (“COVID-19”);

· the effectiveness of our internal control over financial reporting;

· our ability to continue as a going concern;

· physical, digital, internal, and external security breaches;

· technological advances; and

· other factors discussed below and elsewhere in this annual report.

Known material factors that could cause actual results to differ materially from those in our expectations as it relates to our recent redomiciliation to the U.S. include, amongst other factors, changes in U.S. or non-U.S. laws that could reduce or eliminate the benefits expected to be achieved from our redomiciliation, an inability to realize expected benefits from the redomiciliation or the occurrence of difficulties that arise as a result, or in connection with, the redomiciliation. For additional information regarding known material factors that could cause our actual results to differ from our projected results, please read Part I, Item 1A. “Risk Factors” of this annual report.

Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those described in this annual report as anticipated, believed, estimated or expected. Accordingly, you should not place undue reliance on these forward-looking statements. These statements speak only as of the date of this annual report and will not be revised or updated to reflect events after the date of this annual report.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

3

Presentation of Information

On November 26, 2019, Sundance Energy Inc., a newly formed Delaware corporation, acquired all of the issued and outstanding ordinary shares of Sundance Energy Australia Limited, a public company incorporated under the laws of the State of South Australia (“SEAL”), and former parent company of the Sundance group of companies, pursuant to a Scheme of Arrangement under Australian law, which was approved by the Federal Court of Australia on November 14, 2019, and by SEAL shareholders at a meeting of shareholders, which approval was obtained on November 8, 2019 (the “Redomiciliation”). All of the issued and outstanding shares of SEAL were exchanged for newly issued shares of common stock of Sundance Energy Inc., on the basis of one share of common stock for every 100 ordinary shares of SEAL issued and outstanding. Holders of SEAL’s American Depository Shares (“ADSs”) (each of which represented 10 ordinary shares) received one share of common stock for every 10 ADSs held. Thereafter, SEAL distributed all of its assets to Sundance Energy Inc., and Sundance Energy Inc. assumed all of the liabilities of SEAL.

The purpose of the Redomiciliation was to reorganize the operations of SEAL into a structure whereby the ultimate parent company of the Sundance group of companies would be a Delaware corporation. In connection with the Redomiciliation, the ordinary shares of SEAL were delisted from the Australian Securities Exchange, and the common stock of Sundance Energy Inc. began trading on the Nasdaq Global Market on November 26, 2019 under the ticker symbol “SNDE”, the same symbol under which SEAL’s ADSs were traded on Nasdaq Global Market prior to the implementation of the Redomiciliation.

Sundance Energy, Inc., a Colorado corporation (“SEI”), a subsidiary of SEAL prior to the Redomiciliation, has historically been the U.S. operating company for the Sundance group of companies. Following the Redomiciliation, SEI will continue in the role of U.S. operating company as a subsidiary of Sundance Energy Inc.

Unless the context otherwise requires, references to “Sundance,” “we,” “us,” “our,” and the “Company” refer to (i) SEAL and its subsidiaries prior to the Redomiciliation and (ii) Sundance Energy Inc. and its subsidiaries upon completion of the Redomiciliation, as applicable.

PART I

Item 1. Business.

General

We are an onshore independent oil and natural gas company focused on the development, production and exploration of large, repeatable resource plays in North America. Our operations consist primarily of drilling and production from unconventional horizontal wells targeting the Eagle Ford formation in South Texas. 

Strategy

Our strategy is to acquire and/or develop assets where we are operator and have high working interests, positioning us to efficiently control the pace and scope of our development and the allocation of our capital resources. We also believe that serving as operator allows us to control the drilling, completion, operations and marketing of sold volumes.  We plan to continue to focus on developing high-return assets from our portfolio, while preserving an attractive oil-rich inventory.  We continue to realize cost improvement by reducing our operating costs and per well drilling and completion costs.  We intend to manage our liquidity by scaling our 2020 capital program to remain within our operating cash flow. We believe execution of each of these focus areas should increase long-term shareholder value. 

4

Oil and Natural Gas Properties

Description of Properties

All of our operations and assets are located in the Eagle Ford formation in South Texas. Since entering the Eagle Ford play in 2014, we have built a strong assets base that includes over 41,000 net acres targeting the Eagle Ford, through a combination of property acquisitions and development of proved reserves.  Our 2018 acquisition of approximately 21,900 net acres in the Eagle Ford in McMullen, Live Oak, Atascosa and La Salle counties, Texashas positioned us to compete more effectively in this market by offering economies of scale and positioning us to compete for further acquisition opportunities in this area. As of December 31, 2019, we operated 97% of our net producing wells and our average working interest in our operated wells was approximately 95%. 

Estimated Proved Reserves

The following table presents summary information regarding our estimated net proved oil, natural gas and NGL reserves as of the dates indicated. The estimates of our net proved reserves as of December 31, 2019 and 2018 are based on the reserve reports prepared by Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineers, in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting. For more information about our proved reserves as of December 31, 2019 and 2018, please see the reports to management prepared by Ryder Scott, which have been filed or incorporated by reference, as exhibits to this annual report.  All of reserves were located in the Eagle Ford.

	As of December 31,
	2019		2018
Estimated proved reserves:
Oil (MBbls)		62,788		58,629
Natural gas (MMcf)		120,904		108,841
NGL (MBbls)		18,134		16,472
Total estimated proved reserves (MBoe)		101,072		93,241
Estimated proved developed reserves:
Oil (MBbls)		16,101		16,742
Natural gas (MMcf)		26,930		33,169
NGL (MBbls)		4,022		4,927
Total estimated proved developed reserves (MBoe)		24,611		27,197
Estimated proved undeveloped reserves:
Oil (MBbls)		46,687		41,887
Natural gas (MMcf)		93,974		75,672
NGL (MBbls)		14,112		11,545
Total estimated proved undeveloped reserves (MBoe)		76,461		66,044
PV‑10 (in thousands)	$	752,593	$	1,109,847
Standardized Measure (in thousands)	$	675,099	$	952,625

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil, natural gas and NGLs that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers may vary and are subject to change with additional data. Furthermore, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas and NGLs that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, operational changes, regulatory changes, environmental protection, prices and costs, and reservoir performance. Please read Part I, Item IA. “Risk Factors” of this annual report.

5

Additional information regarding our proved reserves can be found in our Consolidated Financial Statements and Notes thereto included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report.

PV‑10

Certain of our oil and natural gas reserve disclosures included in this annual report are presented on a PV‑10 basis. PV‑10 is the estimated present value of the future cash flows less future development and production costs from our proved reserves before income taxes discounted using a 10% discount rate. PV‑10 may be considered a non-GAAP financial measure as defined by the SEC because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows (the “Standardized Measure”). We believe that PV‑10 is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe that the use of a pre-tax measure provides greater comparability of assets when evaluating companies.  Investors should be cautioned that neither PV‑10 nor Standardized Measure represents an estimate of the fair market value of our proved reserves.

The following table provides a reconciliation of Standardized Measure to PV-10 (in thousands):

	As of December 31,
	2019		2018
Standardized Measure	$	675,099	$	952,625
Present value of future income tax discounted at 10%		77,494		157,222
PV‑10 of proved reserves	$	752,593	$	1,109,847

Proved Undeveloped Reserves

Annually, management develops a five-year development plan based on our best available data at the time the plan is developed. Our five-year plan incorporates a development plan for converting PUD reserves to proved developed. The development plan includes only PUD reserves that we are reasonably certain will be spud within five years of initial booking based upon management’s evaluation of a number of qualitative and quantitative factors, including estimated risk-based returns, commodity prices and cost forecasts and recent drilling and well performance.   Our five-year development plan generally does not contemplate a uniform conversion of our PUD reserves to proved developed.  At December 31, 2019, our short-term strategy was to slow the pace of development in 2020 and 2021, which would allow cash flow to accumulate.  The accumulated cash flow would be used to fund an increased pace of development in later years, such that all remaining proved undeveloped locations would be developed within the five-year period.

Management reviews and revises the development plan throughout the year and may modify the development plan after evaluating the factors noted above, as well as realized commodity prices, cost and availability of services and equipment, acquisition and divestiture activity; and our current and projected financial condition and liquidity. If there are changes that result in certain PUD reserves no longer being scheduled for development within five years from the date of initial booking, we reclassify those PUD reserve locations to unproved reserve categories. In addition, PUD locations and reserves may be removed from the development plan prior to their five-year expiration as a result of changes in our development plan related to factors discussed above.

6

The following table summarizes our changes in PUDs during the years ended December 31, 2019:

	PUD Reserves
	(MBoe)
As of December 31, 2018	66,044
Extensions and discoveries	36,535
Sales of reserves in place	(1,736)
Revisions of prior estimates	(19,881)
Conversion of proved undeveloped to proved developed	(4,501)
As of December 31, 2019	76,461

During the year ended December 31, 2019, we incurred capital expenditures of approximately $69.5 million to convert proved undeveloped reserves to proved developed reserves. The remainder of capital expenditures for our proved properties for the period were related to wells in process, development of reserve locations that were not previously classified as proved, infrastructure and installation of artificial lift on proved developed producing reserves.

As of December 31, 2019, our proved undeveloped reserves were approximately 76,461 MBoe, an increase of 10,417 MBoe over our December 31, 2018 proved undeveloped reserves estimate of approximately 66,044 MBoe.  The change primarily resulted from proved undeveloped locations added in 2019 as result of our technical evaluation of wells drilled and completed in late 2018 and in 2019 on properties acquired in 2018 (total extensions of 36,535 MBoe).  As of December 31, 2018, we were still in the process of evaluating many of the undeveloped locations acquired in 2018, and at that time approximately half of the undeveloped locations in our development plan were on acreage acquired in the 2018 Eagle Ford acquisition.  The remainder of the December 31, 2018 proved undeveloped locations were on properties that we owned prior to the 2018 acquisition.  As a result of our additional technical evaluation of the acquired properties during 2019, the focus of our development plan shifted to properties acquired in 2018 with higher projected returns, and we had revisions of 19,881 MBoe primarily associated with approximately 50 proved undeveloped locations on legacy properties that were removed because we expect them to be drilled outside the 5-year window. 

Independent Reserve Engineers

Our reserve estimates are calculated by Ryder Scott as of December 31, 2019 in accordance with SEC guidelines. The reserve estimates are based on, and fairly represent, information and supporting documentation prepared by, or under supervision of Mr. Stephen E. Gardner. Mr. Gardner is a Licensed Professional Engineer in the States of Colorado (Colorado No. 44720) and Texas (Texas No. 100578) with over 14 years of practical experience in estimation and evaluation of petroleum reserves. Mr. Gardner meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We believe that he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. Mr. Gardner consents to the inclusion in this report of the information and context in which it appears.

Internal Controls over Reserves Estimation Process 

The primary inputs into the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. Our technical team consists of an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates.

Our board of directors has also established a Reserves Committee to assist with monitoring (i) the integrity of our oil, natural gas, and NGL reserves, (ii) the independence, qualifications and performance of our independent reservoir engineers, and (iii) our compliance with legal and regulatory requirements. Prior to release of the reserve report prepared by our independent reserve engineers, the draft of the report is reviewed by the Reserves Committee, our internal petroleum engineers and management. 

7

Our senior reservoir engineer is the technical person primarily responsible for overseeing the preparation of our internal reserves estimates and year-end third-party report of our reserves estimates. He received his Masters of Science and Ph.D. in Petroleum Engineering from the Colorado School of Mines.  He is also a member of the Society of Petroleum Engineers and Society of Petroleum Evaluation Engineers.  The senior reservoir engineer currently reports directly to our Chief Executive Officer.

Technology Used to Establish Estimates of Proved Reserves

Under SEC rules, proved reserves are those quantities of oil and natural gas that 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. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, Ryder Scott employed or reviewed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data, well test data, simulation, and statistical methods. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using both volumetric estimates and performance from analogous wells in the surrounding area. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

Acreage

We had the following developed, undeveloped and total acres as of December 31, 2019:

	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
Eagle Ford (1)	21,869	19,652	35,501	26,776	57,370	46,428

(1) Includes 1,573 gross (1,438 net) developed acres and 7,617 gross (3,808 net) undeveloped acres located in Texas, targeting non Eagle Ford formations.

8

Production and Pricing

The following tables set forth information regarding our total production and average daily production for the periods indicated from our operating areas: 

	Year ended December 31,
	2019		2018		2017
Net Sales Volumes:
Oil (MBbls)		3,076.6		2,256.0		1,799.8
Natural gas (MMcf)		5,767.8		4,533.6		3,621.3
NGL (MBbls)		797.8		496.6		323.7
Oil equivalent (MBoe)		4,835.7		3,508.2		2,727.0
Average daily volumes (Boe/d)		13,248		9,612		7,471
Average Sales Price
Oil (per Bbl)	$	57.81	$	62.16	$	49.53
Natural gas (per Mcf)		2.18		2.65		2.41
NGL (per MBbls)		16.51		25.51		20.14
Average equivalent price (per Boe)		42.10		47.01		38.28
Expenses (per Boe):
Lease operating and workover expense	$	6.96	$	9.68	$	8.22
Gathering, processing and transportation expense		3.53		2.46		-
Production tax expense		2.37		2.64		2.30
Total operating expenses	$	12.86	$	14.78		10.52

Producing Wells

We had the following producing wells as of December 31, 2019:

			Natural Gas
	Oil Wells		Wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net
Eagle Ford	244.0	215.0	11	2.5	255.0	217.5

Drilling Activity

The following table summarizes our drilling activity for the fiscal years ended December 31, 2019, 2018 and 2017:

	Year ended December 31,
	2019		2018		2017
	Gross	Net	Gross	Net	Gross	Net
Development wells
Oil	27	22.3	23	23.0	14	13.8
Natural Gas	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total Wells	27	22.3	23	23.0	14	13.8

We did not drill any exploratory wells during the years ended December 31, 2019, 2018 and 2017.  As of December 31, 2019, we had 2 gross (2.0 net) wells waiting on completion and 3 gross (0.3 net) non-operated wells were being drilled.

9

Operations

General

We operated 97% of our production for the year ended December 31, 2019.  As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis.

Marketing and Customers

For the year ended December 31, 2019, purchases by two customers each accounted for over 10% of our total sales revenues. Our largest customer, a large midstream company and production purchaser accounted for approximately 60% of our 2019 revenue. We have a long-term contract in place with this customer, under which we are subject to minimum revenue commitments (“MRCs”) for gathering, processing, transportation and marketing services, with $54.3 million remaining through 2022 (described more below in Part I, Item 1. “Business” under “Delivery Commitments”). Our second largest customer, a large physical trading and logistics company, accounted for approximately 21% of our 2019 revenue. Our agreement with this purchaser ended in September 2019, and was replaced by a marketing agreement with another large physical trading company.  

The oil and natural gas that we sell are commodities for which there are a large number of potential buyers. Because of the adequacy of the infrastructure to transport oil and natural gas in the areas in which we operate, if we were to lose one or more customers, we believe that we could readily procure substitute or additional customers such that our production volumes would not be materially affected for any significant period of time.

The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include global economic and political conditions, the level of demand for oil and natural gas, the price and quantity of imports of foreign oil and natural gas, the level of global oil and natural gas exploration and production, global oil and gas inventories, weather conditions and natural disasters, the outbreak of pandemic or contagious disease, governmental regulations, oil and natural gas speculation, actions of the Organization of Petroleum Exporting Companies (“OPEC”), technological advances and the price and availability of alternative fuels. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months.

Delivery Commitments

In conjunction with our 2018 acquisition, we entered into contracts with a large midstream company to provide gathering, processing, transportation and marketing of hydrocarbon production for the acquired properties.  The contracts contain MRCs that requires us to pay minimum annual fees related to gathering, processing, transportation and marketing.  Volumetric fixed fees are expensed as incurred and settled with the midstream company on a monthly basis.The following table summarizes the remaining MRC (in thousands) by year:

	Year ending December 31,
	2020		2021		2022		Total
Hydrocarbon gathering and handling agreement	$	14,297	$	13,972	$	6,675	$	34,944
Crude oil and condensate purchase agreements		4,710		7,513		4,317		16,540
Gas processing agreement		2,017		-		-		2,017
Gas transportation agreements		783		-		-		783
Total MRC	$	21,807	$	21,485	$	10,992	$	54,284

10

If, at the end of any calendar year during the term of the contract, we fail to satisfy our MRC with the monthly settlements paid during the year, we are required to pay a deficiency payment equal to the shortfall.  If the volumes and associated fees exceed the MRC in any contractual year, the overage can be applied to reduce the future shortfalls, if any.  

The MRC for the years ended December 31, 2019 and 2018 totaled $15.8 million and $11.1 million, respectively, and we realized a shortfall of $2.3 million and $2.8 million, respectively.  Based on our 2019 development plan, we had anticipated an immaterial MRC shortfall, however, midstream constraints reduced our sales volumes, and increased the amount of the 2019 shortfall.  The 2018 commitment was measured on a calendar year basis; however, we did not own and operate the acquired assets until April 23, 2018.  Due to the timing of the acquisition, our development program was back-loaded in 2018, and we were unable to meet the 2018 MRC.   

Current production from the producing wells dedicated under these agreements is not sufficient to meet the MRC for the hydrocarbon gathering and handling agreement.  Based on our current 2020 development plan, we expect we will have a shortfall under the hydrocarbon gathering and handling agreement for the year ending December 31, 2020.  Our ability to meet our commitments in future periods will depend on our pace of development through the term of the contract.  Our development plan is subject to a number of risks, many of which are not within our control.

Competition

The oil and natural gas industry is highly competitive, and we compete with a substantial number of other companies that have greater resources than we do. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties and obtaining drilling rigs, completion crews and other services.  Our competitors may be able to pay more for productive crude oil and natural gas properties and undeveloped prospects, or bid for and purchase a greater number of properties and prospects than our financial resources permit.

There is also competition between producers of oil and natural gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by state, local and the U.S. government agencies. However, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to better absorb the burden of existing and changing federal, state or local laws and regulations than we can, which would adversely impact our competitive position.

Seasonality of Business

We do not believe that the pricing of our crude oil and NGL production is subject to any meaningful seasonal effects. Historically, the pricing of natural gas is seasonal, typically with higher pricing in the winter months.

Title to Properties

Title to our properties are subject to contractual arrangements customary in the oil and gas industry, liens for taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of properties or from the respective interests therein or materially interfere with their use in the operation of our business.

As is customary in the industry, a preliminary title investigation, typically consisting of a review of local title records, is made at the time of acquisitions of undeveloped properties. More thorough title investigations, which generally include a review of title records and the preparation of title opinions by outside legal counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

11

Government Regulations

Nearly every aspect of our business is subject to expansive federal, state, and local laws and governmental regulations. These laws and regulations frequently change in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations have the potential to increase our cost of doing business and consequently could affect our profitability. However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry.

Regulation of Production

The State of Texas, the state where we conduct operations and own nearly all of our oil and gas assets, has adopted laws and regulations governing the exploration for and production of oil, gas, and NGLs, including laws and regulations requiring permits for the drilling of wells, imposing bond requirements in order to drill or operate wells, governing the timing of drilling and 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. Our operations are also subject to Texas conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, and the unitization or pooling of oil and gas properties. In addition, Texas conservation laws establish maximum rates of production from oil and gas wells, generally limit or prohibit the venting or flaring of gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Our sales of gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of gas in interstate commerce.  FERC’s current regulatory framework generally provides for a competitive and open access market for sales and transportation of gas. However, FERC regulations continue to affect the midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for gas production.

Environmental, Health and Safety Matters

Oil, natural gas and NGL exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, including requirements to:

· obtain permits to conduct regulated activities;

· limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

· restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling and production activities;

· initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of drilling pits and plugging of abandoned wells;

· apply specific health and safety criteria addressing worker protection; and

· impose substantial liabilities for pollution resulting from operations.

12

Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of strict, joint and several liability, investigatory and remedial obligations and the issuance of injunctions limiting or prohibiting some or all of the operations on our properties. Moreover, these laws, rules and regulations may restrict the rate of oil, natural gas and NGL production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could increase the cost of developing our properties. Moreover, accidental releases or spills may occur in the course of operations on our properties, causing our operators to incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

Increased costs or operating restrictions on our properties as a result of compliance with environmental laws could result in reduced exploratory and production activities on our properties and, as a result, our revenues and results of operations. The following is a summary of certain existing environmental, health and safety laws and regulations, each as amended from time to time, to which operations on our properties are subject.

Hazardous Substances and Waste

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. CERCLA exempts “petroleum, including oil or any fraction thereof” from the definition of “hazardous substance” unless specifically listed or designated under CERCLA. While the Environmental Protection Agency (“EPA”) interprets CERCLA to exclude oil and fractions of oil, hazardous substances that are added to petroleum or that increase in concentration as a result of contamination of the petroleum during use are not considered part of the petroleum and are regulated under CERCLA as a hazardous substance. Comparable state statutes may include petroleum in the definition of hazardous substance.

Responsible persons under CERCLA include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances under CERCLA.

We also generate solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. RCRA imposes requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations, we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes under RCRA. RCRA regulations specifically exclude from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy.” However, legislation has been proposed in the U.S. Congress from time to time that would reclassify certain oil and natural gas exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and cleanup requirements. No such effort has been successful to date.

13

We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including groundwater contaminated by prior owners or operators) and to perform remedial operations to prevent future contamination.

Air Emissions

The Clean Air Act, as amended (“CAA”), and comparable state laws and regulations restrict the emission of air pollutants, including greenhouse gases, from many sources, including oil and natural gas operations, and impose various monitoring and reporting requirements. These laws and regulations may require us to obtain preapproval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with stringent air permit requirements, report emissions, or utilize specific equipment or technologies to control emissions. CAA rules may require us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment and implementing additional emissions testing and monitoring. These requirements have the potential to delay or increase the cost of the development of oil and natural gas projects. Moreover, changes in environmental laws and regulations occur frequently, and stricter laws, regulations or enforcement policies could significantly increase our compliance costs or negatively impact our production and operations. For example, in 2015, the EPA released a final rule tightening the primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion (“ppb”) to 70 ppb. If areas in which we operate are designated as nonattainment or if the EPA were to further reduce ozone standards, bringing areas in which we operate into nonattainment, states that contain any areas designated nonattainment, and any tribes that choose to do so, are required to develop state implementation plans demonstrating how the area will attain the standard within a prescribed period of time. These plans may require the installation of additional equipment to control emissions. Similar initiatives could lead to more stringent air permitting, increased regulation and possible enforcement actions at the local, state, and federal levels.

Additionally, the EPA has established new air emission control requirements for oil, natural gas and NGLs production, processing and transportation activities, including New Source Performance Standards (“NSPS”) to address emissions of sulfur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) to address hazardous air pollutants frequently associated with gas production and processing activities. Among other things, these rules require the reduction of volatile organic compound emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. In addition, gas wells are required to use completion combustion device equipment (i.e., flaring) by October 15, 2012, if emissions cannot be directed to a gathering line. Further, the final rules under NESHAPS include maximum achievable control technology standards for “small” glycol dehydrators that are located at major sources of hazardous air pollutants and modifications to the leak detection standards for valves.

14

In 2016, the EPA published updates to new source performance standard requirements that would impose more stringent controls on methane and volatile organic compounds emissions from oil and gas development and production operations, including hydraulic fracturing and other well completion activity. Many of these requirements were rescinded in a proposed rule published by the EPA in August 2019, which has not yet been finalized. However, the 2016 rule currently remains in effect. Similarly in November 2016, the Bureau of Land Management (“BLM”) issued rules requiring additional efforts by producers to reduce venting, flaring, and leaking of natural gas produced on federal and Native American lands, though many of these regulations were later rescinded by a final rule published by the BLM in September 2018. Compliance with these or other future changes to regulations regarding air emission may require modifications to certain of our operations, including the installation of new equipment to control emissions at the well site that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

Climate Change

The U.S. is a party to the United Nations Framework Convention on Climate Change, an international treaty focused on stabilizing greenhouse gas (“GHG”) concentrations in the atmosphere at a level that would prevent serious damage to the climate system. In December 2015, the international community agreed upon a new climate change treaty, known as the Paris Agreement. The U.S. committed to a 26-28% reduction in its GHG emissions by 2025 against a 2005 baseline. This new agreement, which was legally effective in November 2016, incorporates actions taken by individual countries to reduce GHG on the national level. U.S. involvement in developing the new agreement creates significant international pressure for the U.S. to take responsive action to reduce GHG emissions. President Trump stated in June 2017 that he intends to withdraw the U.S. from the Paris Agreement and in November 2019, the U.S. submitted formal notification of its withdrawal from the Paris Agreement to the United Nations. Under the terms of the Paris Agreement, the earliest the U.S. could withdraw from the treaty is November 2020. The Trump administration may allow the U.S. to remain in the Paris Agreement, but soften the emission reductions that the U.S. implements to comply with the Paris Agreement. In general, implementation of the Paris Agreement would encourage a shift away from higher GHG emitting power sources like coal-fired power plants.

In the absence of comprehensive climate change legislation, regulatory action to regulate GHG emissions under the federal Clean Air Act occurred under the Obama administration. The Trump administration is in the process of narrowing, revising or attempting to repeal nearly all of the Obama-era climate regulations. Thus, no new federal climate regulations that impose additional requirements are likely in the near term in the U.S. and the focus will be on the state level with certain states like California taking significant actions to reduce GHG emissions.

The EPA requires the reporting of GHG emissions from specified large GHG emission sources, including GHG from petroleum and natural gas systems that emit more than 25,000 tons of GHG per year. Reporting is required from onshore and offshore petroleum and natural gas production, natural gas processing, transmission and distribution, underground natural gas storage and liquefied natural gas import, export and storage.

In 2015, the EPA released the final Clean Power Plan, which is a regulation designed to reduce carbon pollution from existing fossil fuel-fired power plants, including natural gas power plants. Upon finalization of the Clean Power Plan, over twenty states and industry groups challenged the rule in the D.C. Circuit court and requested a stay of the rule. In 2019, the EPA replaced the Clean Power Plan with the more narrowly-scoped Affordable Clean Energy rule. The rule is currently being litigated by public health groups, certain states and environmental groups.

In 2016, the EPA issued a suite of proposed regulations that would reduce methane emissions from the oil and gas industry, including proposed updates to the NSPS for new and modified sources in the oil and gas industry, a clarification of the source determination rule as applied to the oil and natural gas industry and a proposed Federal Implementation Plan for new oil and gas sources in Indian Country. These regulations could affect us indirectly by affecting our customer base or by directly regulating our operations. In either case, increased costs of operation and exposure to liability could result. In 2019, the EPA proposed to replace existing NSPS methane limits with a narrower rule and to amend the Federal Implementation Plan for oil and gas production activities in Indian Country. The EPA is currently reviewing public comments on the proposed rules.

15

In 2017, President Trump signed an executive order to rescind President Obama’s climate-related executive orders and climate action plans and to direct the EPA to review and revise the Clean Power Plan, the standards for new power plants and other climate regulations. The executive order sets in motion a process that will take several years to fully implement. Because the EPA climate regulations are final regulations, the EPA will have to go through a notice and comment rulemaking process to modify or revoke them and such actions are expected to be litigated by environmental groups and states supportive of the regulations. Even if the carbon regulations are ultimately revoked or weakened under the Trump administration, we may continue to incur compliance costs and we may incur new costs associated with transitioning to the new requirements.

 The EPA’s GHG rules are being reviewed pursuant to President Trump’s executive order and many are being challenged in court proceedings. Depending on the outcome of such proceedings, the rules may be modified or rescinded or the EPA could develop new rules. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require us to incur costs to reduce emissions of GHG associated with our operations or could adversely affect demand for the oil and natural gas we produce.

While new legislation requiring GHG controls is not expected at the national level in the near term, almost one-half of the states have taken actions to monitor and/or reduce emissions of GHG, including obligations on utilities to purchase renewable energy and participate in GHG cap and trade programs. Although most of the state level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future.

Climate change regulatory and legislative initiatives could have a material adverse effect on our business, results of operations and financial condition. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources, such as coal, our products could become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources, such as solar and wind, our products could become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Finally, 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, floods and other climatic events. Such effects could adversely affect or delay demand for the oil or natural gas we produce or otherwise cause us to incur significant costs in preparing for or responding to those effects.

Water Discharges

The Federal Water Pollution Control Act, as amended, or the Clean Water Act (“CWA”), and analogous state laws impose restrictions and controls regarding the discharge of pollutants into waters of the U.S. Pursuant to the CWA and analogous state laws, permits must be obtained from the EPA or analogous state agency to discharge pollutants into state waters or waters of the U.S. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of stormwater runoff from certain types of facilities. Currently, storm water discharges from oil and natural gas exploration, production, processing or treatment operations, or transmission facilities are exempt from regulation under the CWA. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as other enforcement mechanisms for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

16

Endangered Species Act

The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Employee Health and Safety

We are subject to a number of federal and state laws and regulations regulating employee health and safety, including the federal Occupational Safety and Health Act, as amended (the “OSH Act”), and comparable state statutes. In addition, the OSH Act’s hazard communication standard, the EPA’s “community right-to-know” regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used, produced or released in our operations and that this information be provided to employees, state and local government authorities and the public. OSH Act regulates worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids. The key provisions of the rule: (i) reduce the permissible exposure limit (PEL) for respirable crystalline silica to 50 micrograms per cubic meter of air, averaged over an 8‑hour shift; (ii) require employers to: use engineering controls (such as water or ventilation) to limit worker exposure to the PEL; provide respirators when engineering controls cannot adequately limit exposure; limit worker access to high exposure areas; develop a written exposure control plan, offer medical exams to highly exposed workers, and train workers on silica risks and how to limit exposures; (iii) provide medical exams to monitor highly exposed workers and gives them information about their lung health; and (iv) provide flexibility to help employers protect workers from silica exposure. Workers at well sites may be exposed to excessive levels of respirable silica sand, which can cause lung disease and cancer. Increasing concerns about worker safety at well sites may lead to increased regulation and enforcement or related tort claims by our employees. Implementation of engineering and workplace controls to comply with the rule may require significant investment.

Hydraulic Fracturing

The Safe Drinking Water Act (“SDWA”) and comparable state statutes may restrict the disposal, treatment or release of water produced or used during oil and natural gas development. Subsurface emplacement of fluids (including disposal wells) is governed by federal or state regulatory authorities that, in some cases, include the state oil and gas regulatory authority or the state’s environmental authority. We utilize hydraulic fracturing in our operations as a means of maximizing the productivity of our wells and operate saltwater disposal wells to dispose of produced water. The federal Energy Policy Act of 2005 amended the Underground Injection Control (“UIC”) provisions of the SDWA to expressly exclude hydraulic fracturing without diesel additives from the definition of “underground injection.” However, the U.S. Senate and House of Representatives have considered several bills in recent years to end this exemption, as well as other exemptions for oil and gas activities under U.S. environmental laws. The Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”), first introduced in 2011, would amend the SDWA to repeal the exemption from regulation under the UIC program for hydraulic fracturing. This bill has been reintroduced in each congressional session since it was initially proposed but has not yet garnered enough support to be put to a vote. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, to adhere to certain construction specifications, to fulfill monitoring, reporting and recordkeeping obligations and to meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process. Note that each of the above components of the FRAC Act have become increasingly common in state laws since the FRAC Act was first introduced. Other bills that have been introduced in recent years in the U.S. House of Representatives would end certain exemptions for oil and natural gas operations related to permitting requirements for multiple commonly owned and adjacent sources of hazardous air pollutants under the CAA and permitting requirements for stormwater discharges under the CWA. If the exemptions for hydraulic fracturing are removed from U.S. environmental laws, or if the FRAC Act or other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition and results of operations.

17

Federal agencies have also begun to directly regulate hydraulic fracturing. The EPA has asserted federal regulatory authority over, and issued permitting guidance for, hydraulic fracturing involving diesel additives under the SDWA’s UIC Program. As a result, service providers or companies that use diesel products in the hydraulic fracturing process are expected to be subject to additional permitting requirements or enforcement actions under the SDWA. The EPA has promulgated pretreatment standards for oil and gas extraction category under the CWA that prohibit the discharge of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly owned treatment works. The EPA also has been conducting a study of private wastewater treatment facilities accepting oil and gas extraction wastewater. The EPA collected data and information related to the extent to which such wastewater is accepted, available treatment technologies, discharge characteristics and other information. The EPA is currently reviewing comments on the draft study report. The use of surface impoundments (i.e., pits or surface storage tanks) for the temporary storage of hydraulic fracturing fluids for re-use or prior to disposal may also be regulated. The EPA also completed a multi-year study about the effects of hydraulic fracturing on drinking water. Although the regulations for hydraulic fracturing on federal land that were promulgated by the U.S. Department of the Interior in 2015 were rescinded in 2017, that 2017 rulemaking is the subject of ongoing litigation. These regulatory developments have the potential to create additional permitting, technology, recordkeeping and site study requirements, among others, for our business. However, under the Trump administration, we expect no new significant requirements on hydraulic fracking.

Several state governments in the areas where we operate have adopted or are considering adopting additional requirements relating to hydraulic fracturing that could restrict its use in certain circumstances or make it more costly to utilize. Such measures may address any risk to drinking water, the potential for hydrocarbon migration and disclosure of the chemicals used in fracturing. For example, several states have implemented rules requiring hydraulic fracturing operators to sample ground and surface waters near proposed well sites before operations can begin, and to sample the same sites again after fracturing operations are complete. A majority of states around the country, including Texas, have also adopted some form of fracturing fluid disclosure law to compel disclosure of fracturing fluid ingredients and additives that are not subject to trade secret protection. Other states, such as Ohio and Texas, have begun to study potential seismic risks related to underground injection of fracturing fluids. Any enforcement actions or requirements of additional studies or investigations by governmental authorities where we operate could increase our operating costs and cause delays or interruptions of our operations.

At this time, it is not possible to estimate the potential impact on our business of these state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing.

Insurance Matters

As is common in the oil and gas industry, we do not insure fully against all risks associated with our business, either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations or cash flows.

Employees

As of December 31, 2019, we had 79 employees (all employed full-time). None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

We also contract for the services of independent consultants involved in land, engineering, regulatory, accounting and other disciplines as needed.

18

Available Information

Our website address is www.sundanceenergy.net. We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Nominating and Corporate Governance Committee, Compensation Committee and Reserves Committee, and our Code of Ethics and Business Conduct are available through our website, and we also intend to disclose any amendments to our Code of Ethics, or waivers to such code on behalf of our Chief Executive Officer or Chief Financial Officer, on our website. The contents of our website are not intended to be incorporated by reference into this annual report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only.  Information is also available on the SEC website at www.sec.gov.

Item 1A. Risk Factors.

We are subject to various risks and uncertainties in the course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. When considering an investment in our securities, you should carefully consider the risk factors included below as well as those matters referenced in this report under “Cautionary Statement Regarding Forward-Looking Statements” and other information included and incorporated by reference into this annual report.

Risks Related to Our Business

Oil, natural gas and NGL prices are volatile. A substantial or extended decline in the price of these commodities may adversely affect our business, results of operations or financial condition and our ability to meet our capital expenditure obligations and financial commitments.

Our revenues, profitability, liquidity, ability to access capital and future growth prospects are highly dependent on the prices we receive for our oil, natural gas and NGLs. The prices of these commodities are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and we expect this volatility to continue. For example, average daily prices for NYMEX-WTI crude oil ranged from a high of $66.24 per barrel to a low of $46.31 per barrel during 2019.  In March 2020, oil prices dropped sharply to under $20 per barrel, and in April 2020, oil prices dropped further and, for a short period of time, were negative. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include:

· general worldwide and regional economic and political conditions;

· the domestic and global supply of, and demand for, oil, natural gas and NGLs;

· the actions of OPEC and the ability of OPEC and other producing nations, including Russia, to agree to and maintain production levels;

· the cost of exploring for, developing, producing and marketing oil, natural gas and NGLs;

· the proximity, capacity, cost and availability of oil, natural gas and NGL pipelines and other transportation facilities;

· the price and quantity of imports of foreign and exports of domestic oil, natural gas and NGLs;

· the level of global oil, natural gas and NGL exploration and production;

· the level of global oil, natural gas and NGL inventories;

· future regulations prohibiting or restricting our ability to apply hydraulic fracturing to our wells;

· weather conditions and natural disasters;

· global or national health concerns, including the outbreak of pandemic or contagious disease, such as COVID-19, which may reduce the demand for oil, gas and NGL because of reduced global or national economic activity;

· domestic and foreign governmental laws, regulations and taxes;

· volatile trading patterns in commodities futures markets;

19

· price and availability of competitors’ supplies of oil, natural gas and NGLs;

· shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas and related infrastructure;

· technological advances affecting energy consumption; and

· the price and availability of alternative fuels.

Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relationship to each other. Because approximately 62% and 18% of our estimated proved reserves as of December 31, 2019 were attributed to oil and NGLs, respectively, our financial results are more sensitive to movements in oil prices. The price of oil has been extremely volatile, and we expect this volatility to continue for the foreseeable future. Substantially all of our oil production is sold to purchasers under contracts at market-based prices.

Any prolonged substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition and results of operations. We may use various derivative instruments in connection with anticipated oil, natural gas and NGL sales to minimize the impact of commodity price fluctuations. However, we cannot always hedge the entire exposure of our operations from commodity price volatility. We currently have oil derivatives in place covering the expected 2020 production from our proved developed producing reserves as of January 1, 2020.  To the extent we are unhedged, we have significant exposure to adverse changes in the prices of oil, natural gas and NGLs that could materially and adversely affect our business and results of operations.

In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that can be produced economically. This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. We might also elect during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, we could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, we may abandon any well if we reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.

There can be no assurance that we will be able to comply with the terms of our credit facilities.

Our credit facilities require us to maintain compliance with certain financial and other covenants.  Our ability to comply with these covenants is uncertain and will be affected by our results of operations and financial condition, and events or circumstances beyond our control, including sustained low commodity prices. Absent a waiver or amendment, a breach of any of these covenants contained in our credit facilities could result in an event of default under these facilities. 

Specifically, due to the recent sharp decline in commodity prices and expectations for commodity prices in 2020, there is uncertainty as to our ability to remain in compliance with certain of the financial covenants and ratios throughout 2020 and early 2021. If we violate these financial covenants and ratios, or any other covenant in our credit facilities, our indebtedness may become immediately due and payable, the interest rates under our credit facilities may increase and the lenders’ commitment, if any, to make further loans to us may terminate. In the event that some or all of the amounts outstanding under our credit facilities are accelerated and become immediately due and payable, we may not have the funds to repay, or the ability to refinance, such outstanding amounts and our lenders could foreclose upon critical assets. Any of these outcomes would have an adverse effect on our business and financial condition.

20

In addition, our credit facilities contain reporting covenants that requires delivery of audited consolidated financial statements and related reports and certificates on or before certain deadlines provided for in our credit facilities.  Additionally, our financial statements must be delivered without a going concern or like qualification or exception.  Failure to comply with these covenants would constitute a default under our credit facilities.  On May 8, 2020 and May 11, 2020, we entered into waivers with our lenders to waive any potential default arising from the failure to deliver audited consolidated financial statements and related reports and certificates by the applicable deadlines, and with respect to inclusion of the going concern explanatory paragraph included in our audit report for the fiscal year ended December 31, 2019.  These waivers were effective April 29, 2020, subject to the conditions set forth in the waivers, which included delivery of our audited consolidated financial statements for the fiscal year ended December 31, 2019 and related reports and certificates, and payment of the fees and expenses of the administrative agent incurred in connection with such waivers.  In consideration for the waiver under our senior secured revolving credit facility (“Revolving Facility”), we agreed to certain limitations on our ability to effect draws under the Revolving Facility until such time as the second quarter 2020 borrowing base redetermination has been completed.   In addition, in consideration for waiver with respect to our second lien term loan facility (“Term Loan”), we agreed to amend certain covenants in the Term Loan, as to be mutually agreed with the Term Loan lenders, within 15 days from the execution date.  The waiver under our Revolving Facility also provides for a right to require corresponding amendments of that facility manner, as requested by the administrative agent in its discretion. Failure to enter into such amendment with respect to our Term Loan within 15 days (or a similar amendment with respect to our Revolving Facility on the date the Term Loan is amended) would constitute an event of default under our credit facilities, in which case the amounts outstanding under our credit facilities could be accelerated and become immediately due and payable. If this occurs, we may not have the funds to repay or ability to refinance such outstanding amounts and our lenders could foreclose upon critical assets.  Although we have entered into these waivers, there is no guarantee that our lenders will agree to waive events of default or potential events of default in the future.  Failure to obtain such waivers in the future would have an adverse effect on our business and financial condition.  For more information on the covenants under our credit facilities and the potential impact of the explanatory paragraph in the audit report, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under “Credit Facilities”.  

Our future revenues are dependent on our ability to successfully replace our proved producing reserves.

Our business strategy is to generate profit through the acquisition, exploration, development and production of oil and natural gas reserves. Proved reserves generally decline as they are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves or both. We may not be able to find, develop or acquire additional reserves on an economically viable basis. Furthermore, if oil and natural gas prices increase, the cost of finding, developing or acquiring additional reserves could also increase.

Development and exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could materially and adversely affect our business, results of operations or financial condition. In addition, the future cost and timing of drilling, completing and operating wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

· lack of prospective acreage available on acceptable terms;

· unexpected or adverse drilling conditions;

· elevated pressure or irregularities in geologic formations;

· equipment failures or accidents;

· adverse weather conditions;

· title problems;

· limited availability of financing upon acceptable terms;

· reductions in oil, natural gas and NGL prices;

· compliance with governmental requirements; and

· shortages or delays in the availability of drilling rigs, equipment and personnel.

21

Even if our exploration, development and drilling efforts are successful, our wells, once completed, may not produce reserves of oil, natural gas or NGLs that are economically viable or that meet our prior estimates of economically recoverable reserves. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial position by reducing our available cash and liquidity. In addition, the potential for production decline rates for our wells could be greater than we expect. Because of the risks and uncertainties inherent to our businesses, our future drilling results may not be comparable to our historical results described elsewhere in this annual report.

Development of our PUDs may take longer than expected and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

As of December 31, 2019, approximately 76% of our total proved reserves were undeveloped. These reserve estimates reflected our plans to make significant capital expenditures to convert our proved undeveloped reserves into proved developed reserves. Based on our December 31, 2019 reserve report, it will require an estimated $1.2 billion of capital to develop approximately 76.5 MMBoe of our estimated proved undeveloped reserves over the next five years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our proved undeveloped reserves to unproved reserves.

Further, our reserve estimates assume that we can and will make these expenditures and that these operations will be conducted successfully. However, these assumptions may not prove correct. If our plans change and we choose not to spend the capital (or are unable to generate adequate cash flow or obtain the necessary capital under our credit facilities or from other sources) to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to remove these reserves from future reserve estimates.  Any such removal of our existing reserves could reduce our ability to borrow and adversely affect our liquidity and available capital.

Our development and exploration projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves with resulting adverse effects on our cash flow and liquidity.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil, natural gas and NGL reserves. We expect our 2020 capital program to be in the range of $40 - $45 million.  However, we plan to respond flexibly to market conditions to protect our balance sheet and retain liquidity.  

The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, regulatory, and technological and competitive developments. We intend to finance our development plan in 2020 primarily with cash flows from operations, but we may also finance our future capital expenditures through a variety of other sources, including available borrowings under our Revolving Facility, through additional asset sales, or through the issuance of debt and/or equity, which may alter or increase our capitalization substantially.

Our cash flows from operations and access to capital are subject to a number of variables, including:

· our proved reserves;

· the volume of oil, natural gas and NGLs we are able to produce and sell from existing proved developed wells;

· the prices at which our oil, natural gas and NGLs are sold;

· the cost at which our oil, natural gas and NGLs are extracted;

· global credit and securities markets;

· our ability to acquire, locate and produce new reserves and the cost of such reserves; and

· the ability of our lenders to provide us with credit or additional borrowing capacity.

22

If our revenues or the amounts we can borrow under available credit facilities decrease as a result of lower oil, natural gas or NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, or at all. If cash generated by operations or cash available under our credit facilities is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our locations, which in turn could lead to a decline in our oil, natural gas and NGL reserves and production levels, and could materially and adversely affect our business, results of operations and financial condition.

Any significant reduction in our borrowing base under our Revolving Facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our Revolving Facility generally limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually on May 1 and November 1 of each year. Our Revolving Facility has a borrowing base of $210.0 million ($190 million elected commitment), of which $115.0 million was outstanding as of December 31, 2019. Our next borrowing base redetermination is the second quarter of 2020. Redeterminations are based upon a number of factors, including commodity prices and reserve levels. In addition, our lenders have substantial flexibility to reduce our borrowing base due to subjective factors. Upon a redetermination, we could be required to repay a portion of the debt owed under our Revolving Facility to the extent our outstanding borrowings at such time exceeds the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of our Revolving Facility and an acceleration of the loans outstanding under our Revolving Facility and our other credit facilities. Failure to timely pay these debt obligations when due could cause us to lose our assets through mortgage foreclosure, which would materially and adversely affect our business, results of operations and financial condition.

Additionally, in the future we may not have access to adequate funding under our Revolving Facility as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of our lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover any defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans or make required repayments under the Revolving Facility or our other credit facilities, which would materially and adversely affect our business, results of operations and financial condition.

Effective April 29, 2020, we entered into a waiver with respect to any potential default arising from the reporting covenant under our Revolving Facility that requires delivery of audited consolidated financial statements on or before the deadline provided for in the Revolving Facility, and to deliver such financial statements without a going concern or like qualification or exception for the year ended December 31, 2019.  In consideration for the waiver, we agreed to certain limitations on our ability to effect draws under the Revolving Facility until such time as the second quarter 2020 borrowing base redetermination has been completed.   See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under “Credit Facilities”.

The current outbreak of COVID-19 has adversely impacted our business, financial condition and results of operations and is likely to have a continuing adverse impact for a significant period of time.

The COVID-19 pandemic has caused a rapid and precipitous drop in demand for oil, which in turn has caused oil prices to plummet since the first week of March 2020, negatively affecting the Company’s cash flow, liquidity and financial position.  Moreover, the uncertainty about the duration of the COVID-19 pandemic has caused storage constraints in the United States resulting from over-supply of produced oil, which is expected to significantly decrease our realized oil prices in the second quarter of 2020 and potentially beyond. Oil prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 outbreak, and as changes in oil inventories, oil demand and economic performance are reported. We cannot predict when oil prices will improve and stabilize.

23

The current pandemic and uncertainty about its length and depth in future periods has caused the realized oil prices we have received since February 2020 to be significantly reduced, adversely affecting our operating cash flow and liquidity. While we continue to flexibly manage our operations, including capital expenditure levels, based on existing and expected market conditions, our lower levels of cash flow could affect our borrowing capacity and may require us to shut-in production that has become uneconomic. These conditions may also increase the difficulty in repaying, refinancing or restructuring our long-term debt.

The COVID-19 pandemic is rapidly evolving, and the ultimate impact of this pandemic is highly uncertain and subject to change. The extent of the impact of the COVID-19 pandemic on our operational and financial performance will depend on future developments, including the duration and spread of the pandemic, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, and the duration, timing and severity of the impact on domestic and global oil demand.

Changes in the differential between benchmark prices of oil and natural gas and the reference or regional index price used to price our actual oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.

The reference or regional index prices that we will use to price our oil and natural gas sales sometimes will reflect a discount to the relevant benchmark prices. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict oil and natural gas differentials. Changes in differentials between the benchmark price for oil and natural gas and the reference or regional index price we reference in our sales contracts could materially and adversely affect our business, results of operations and financial condition.

Our level of indebtedness may reduce our financial flexibility.

We intend to fund our capital expenditures primarily through cash flow from operations and, if necessary borrowings under available credit facilities and alternative debt or equity financings. If we obtain alternative debt or equity financing for these or other purposes, the related risks that we now face could intensify. Our level of debt could materially and adversely affect our business, results of operations and financial condition in several important ways, including the following:

· a portion of our cash flow from operations would be used to pay interest on borrowings;

· the covenants contained in available credit facilities limit our ability to borrow additional funds, pay dividends, dispose of assets or issue shares of preferred stock and otherwise may affect our flexibility in planning for, and reacting to, changes in general business and economic conditions;

· a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes;

· a leveraged financial position would make us more vulnerable to economic downturns and decreases in commodity prices and could limit our ability to withstand competitive pressures; and

· the debt we currently hold, as well as any debt that we incur under our existing Revolving Facility will be at variable rates which could make us vulnerable to an increase in interest rates.

24

The interest rates under our credit facilities may be impacted by the phase-out of LIBOR.

The London Interbank Offered Rate (“LIBOR”) is the basic rate of interest used in lending between banks on the London interbank market and is widely used as a reference for setting the interest rates on loans globally. We generally use LIBOR as a reference rate to calculate interest rates under our credit facilities. In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. It is unclear if LIBOR will cease to exist at that time or if new methods of calculating LIBOR will be established such that it continues to exist after 2021. If LIBOR ceases to exist or replaced with an alternative reference rate, we may need to renegotiate our credit agreements to replace LIBOR with an agreed upon replacement index, and certain of the interest rates under our credit agreements may change. The new rates may not be as favorable to us as those in effect prior to any LIBOR phase-out. We may also find it desirable to engage in more frequent interest rate hedging transactions.

Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.

The oil and natural gas business involves operating hazards such as:

· well blowouts;

· mechanical failures;

· fires and explosions;

· pipe or cement failures and casing collapses, which could release natural gas, oil, drilling fluids or hydraulic fracturing fluids;

· uncontrollable flows of oil, natural gas or well fluids;

· geologic formations with abnormal pressures;

· handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids;

· pipeline ruptures or spills;

· inclement weather, including flooding, hurricanes or other severe weather events;

· releases of toxic gases; and

· other environmental hazards and risks (including groundwater contamination).

Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims, regulatory investigation, penalties and suspension of operation and other damage to our properties and the property of others.

We maintain insurance against losses and liabilities in accordance with customary industry practices and in amounts that our management believes to be prudent. However, insurance against all operational risks is not available to us. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented.

In addition, losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot insure fully against pollution and environmental risks. We cannot assure investors that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

25

We depend upon several significant customers for the sale of most of our oil, natural gas and NGL production.

For the year ended December 31, 2019, purchases by two customers each accounted for over 10% of our total sales revenues. The loss of one or more of these customers or the inability or failure of either of these customers to meet their obligations to us or their insolvency or liquidation could adversely affect our revenues in the short term. While we believe that we can procure substitute or additional customers to offset the loss of one or more of our current customers, there is no assurance that we would be successful in doing so on terms acceptable to us or at all. The availability of a ready market for any oil, natural gas or NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil, natural gas and NGL production and federal regulation of oil, natural gas and NGL in interstate commerce.

SEC rules could limit our ability to book additional PUDs in the future.

SEC rules require that, subject to limited exceptions, our PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement limits our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write-down our PUDs if we do not drill those wells within the required five-year time frame, or if oil and natural gas prices decrease, making the PUDs uneconomic. Lower PV‑10 value, resulting from fewer PUDs, may negatively impact our investor perception.

Our planned drilling involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques, which are subject to risks. As a result, drilling results may not meet our expectations for reserves or production.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to:

· landing our well bore in the desired formation;

· staying in the desired formation while drilling horizontally through the formation;

· running our casing the entire length of the well bore; and

· being able to run tools and other equipment consistently through the well bore.

Risks that we face while completing our wells include, but are not limited to:

· being able to fracture stimulate the planned number of stages;

· being able to run tools the entire length of the well bore during completion operations;

· successfully cleaning out the well bore after completion of the final fracture stimulation stage; and

· negatively impacting offset producing wells through subsurface communication during fracture stimulation.

The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling does not meet our anticipated results 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 oil and natural gas prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

26

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

Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:

· ongoing review and analysis of geologic and engineering data;

· the availability of sufficient capital resources to us and the other participants for drilling and completing of the locations;

· the approval of the locations by other participants once additional data has been compiled;

· economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability and prices of drilling rigs and personnel;

· the ability to maintain, extend or renew leases and permits on reasonable terms for the locations;

· additional due diligence;

· regulatory requirements and restrictions; and

· the opportunity to divert our drilling budget to preferred locations.

Although we have identified or budgeted for numerous drilling locations, we may not be able to lease or drill those locations within our expected time frame or at all. Wells that are currently part of our capital plan may be based on results of drilling activities in other areas that we believe are geologically similar to a location rather than on analysis of seismic or other data in the location area, in which case actual drilling and results are likely to vary, possibly materially, from results in other areas. In addition, our drilling schedule may vary from our expectations because of future uncertainties, and our ability to produce oil, natural gas and NGLs may be significantly affected by the availability and prices of equipment and personnel.

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing properties. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce oil, natural gas or NGLs from these or any other potential locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in the addition of proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

27

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which the oil and gas industry has historically increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, and the costs for those items also increased. We cannot predict the future availability or costs of these items. However, any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to maintain or increase our development activities, could result in 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 cash flow and profitability. Furthermore, if we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.

Certain of our undeveloped leasehold acreage is subject to leases expiring over the next several years unless production is established on units containing the acreage.

Certain of our undeveloped leasehold acreage is subject to leases that will expire unless production is established. For these properties, if production in commercial quantities has not been established on the leased property or units that include the leased property containing these leases, our leases will expire and we will lose our right to develop the related properties. As of December 31, 2019, 2,118 net acres of our total acreage position were not held by production.  For the acreage underlying such properties, if production in paying quantities is not established on units containing these leases, or extensions are not successfully obtained, 1,927 net acres will expire in 2020, and approximately 191 net acres will expire in 2021 and 2022. In addition, approximately 4,500 net acres is currently held by production, but is subject to future drilling obligations. 

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

In accordance with our business strategies, we periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

· recoverable reserves;

· future oil and natural gas prices and their appropriate differentials;

· timing of development;

· development and operating costs; and

· potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us 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.

28

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;

· the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;

· difficulty associated with coordinating geographically separate organizations; and

· the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is 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.

In addition, even if we successfully integrate an acquisition, it may not be possible to realize the full benefits we may expect, including with respect to estimated proved reserves, production volume or cost savings from operating synergies, within our expected time frame. Anticipated benefits of an acquisition may also be offset by operating losses relating to changes in commodity prices in oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. Failure to realize the benefits we anticipate from an acquisition may materially and adversely affect our business, results of operations and financial condition.

Our producing properties are located primarily in the Eagle Ford, making us vulnerable to risks associated with operating in a limited number of geographic areas.

All of our producing properties are geographically concentrated in the Eagle Ford area. 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 these areas caused by governmental regulation (including any proration and production restrictions in light of the COVID-19 pandemic or otherwise), processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs, any of which could materially and adversely affect our business, results of operations and financial condition.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate and any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves.

The reserve data in this annual report represent only estimates. There are uncertainties inherent in estimating oil and natural gas reserves and their estimated value, including many factors beyond our control. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and is based on assumptions that may vary considerably from actual results. Reservoir engineering also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Accordingly, actual production, oil and natural gas prices, revenue, taxes, operating expenses, expenditures and quantities of recoverable oil and natural gas reserves will likely vary, possibly materially, from estimates. Any significant variance in our estimates or the accuracy of our assumptions could materially affect the estimated quantities and present value of reserves shown in this annual report, which could materially and adversely affect our business, results of operations and financial condition.

29

Our derivative activities could result in financial losses or could reduce our income.

Because oil and natural gas prices are subject to volatility, we regularly enter into price-risk-management transactions such as fixed-rate swaps, costless collars, puts, calls and basis differential swaps to reduce our exposure to price declines associated with a portion of our oil and natural gas production and thereby achieve a more predictable cash flow. The use of these arrangements limits our ability to benefit from increases in the prices of oil and natural gas. Our derivative arrangements may apply to only a portion of our production, thereby providing only partial protection against declines in oil and natural gas prices.

These arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase contracted quantities of oil and natural gas or a sudden, unexpected event that materially impacts oil or natural gas prices. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us.

If the recent decline in oil and natural gas prices is sustained or prices decline further, we may be required to write-down the carrying values of our oil and natural gas properties.

Accounting rules require that we periodically review the carrying value of our producing oil and gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews (which may include depressed oil, natural gas and NGL prices and the continuing evaluation of development plans, production data, economics, possible asset sales and other factors), we may be required to write-down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. For example, we incurred impairment of oil and gas properties held for sale of $10.0 million and $43.0 million during 2019 and 2018, respectively.

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

The discounted future net cash flows in this annual report are not necessarily the same as the current market value of our estimated oil and natural gas reserves. In accordance with SEC regulations, the estimated discounted future net cash flows from proved reserves are based on the average of the historical sales price on the first day of each month in the applicable year, with costs determined as of the date of the estimate. Actual future net cash flows also will be affected by various factors, including:

· the actual prices we receive for oil and natural gas;

· our actual operating costs in producing oil and natural gas;

· the amount and timing of actual production;

· supply and demand for oil and natural gas;

· increases or decreases in consumption of oil and natural gas; and

· changes in governmental regulations or taxation.

In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements 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 oil and gas industry in general.

Our inability to market our oil and natural gas could adversely affect our business.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and gathering facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on favorable terms could materially and adversely affect our business, results of operations and financial condition.

30

Our productive properties may be located in areas with limited or no access to pipelines, thereby requiring compression facilities or delivery by other means, such as trucking and train. Such restrictions on our ability to sell our oil or natural gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we are unable to market and sustain production from a particular lease for an extended period of time, possibly resulting in the loss of a lease due to the lack of commercially established production.

We generally deliver our oil and natural gas production through gathering systems and pipelines that we do not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our oil and natural gas production may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system or for other reasons as dictated by the particular agreements. We may also enter into firm transportation arrangements for additional production in the future. Because we are obligated to pay fees on minimum volumes to our service providers under these agreements regardless of actual volume throughput, these firm transportation agreements may be significantly more costly than interruptible or short-term transportation agreements, which could adversely affect our business and results of operations.

A portion of our oil and natural gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of adverse weather conditions or natural disasters, accidents, loss of pipeline or gathering system access, or field personnel issues or strikes. We may also voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted or curtailed, it could adversely affect our business and results of operations.

Our credit facilities have substantial restrictions and financial covenants that restrict our business and financing activities.

Our credit facilities contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability, subject to satisfaction of certain conditions, to:

· incur additional indebtedness and guarantee indebtedness;

· pay dividends or make other distributions or repurchase or redeem capital stock;

· enter into hedging agreements covering volumes above specified ceilings or below specified floors;

· prepay, redeem or repurchase certain debt;

· issue certain preferred stock or similar equity securities;

· make loans and investments;

· sell assets;

· incur liens;

· enter into transactions with affiliates;

· alter the businesses we conduct;

· enter into agreements restricting our subsidiaries’ ability to pay dividends; and

· consolidate, amalgamate, merge or sell all or substantially all of our assets.

As a result, we may be limited in how we conduct our business, unable to raise additional debt or equity financing to operate during general economic or business downturns or unable to compete effectively or to take advantage of new business opportunities. These restrictions may further affect our ability to grow in accordance with our strategy. In addition, our financial results, our substantial indebtedness and our credit ratings could adversely affect the availability and terms of our current and future financing.

31

Increased costs of capital could adversely affect our business.

Our business and operating results can be adversely affected by factors such as the availability, terms and cost of capital and increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Disruptions in the global financial markets may lead to an increase in interest rates or a contraction in credit availability, which would impact our ability to finance our operations. We will require continued access to capital for the foreseeable future. A significant reduction in the availability of credit could materially and adversely affect our business, results of operations and financial condition.

Competition in the oil and natural gas industry is intense and many of our competitors have resources that are greater than ours.

The oil and natural gas industry is highly competitive. Public integrated and independent oil and natural gas

companies, private equity backed and private operators are all active bidders for desirable oil and natural gas properties as well as the equipment and personnel required to operate those properties. Many of these companies have substantially greater financial resources, staff and facilities than we do. There is a risk that increased industry competition will adversely impact our ability to purchase assets or secure services at prices that will allow us to generate sufficient returns on investment in the future.

We may not be able to keep pace with technological developments in our 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 may be forced by competitive pressures 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 that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

The loss of any of our key personnel could adversely affect our business the results of operations, financial condition and future growth.

We are reliant on a number of key members of our executive management team. Loss of such personnel may have an adverse effect on our performance. We operate in a highly competitive environment and competition for qualified personnel is intense. We may be unable to hire suitable field personnel for our technical team or there may be periods of time where a particular position remains vacant while a suitable replacement is identified and appointed. Our ability to sustain current operations or manage our growth will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel. We may not be successful in attracting and retaining the personnel required to grow or operate our business profitably.

Our ability to manage growth will have an impact on our business, results of operations and financial condition.

Our growth historically has been achieved through the acquisition of leaseholds and the expansion of our drilling programs. Future growth may place strains on our financial, technical, operational and administrative resources and cause us to rely more on project partners and independent contractors, potentially adversely affecting our financial position and results of operations. Our ability to grow will depend on a number of factors, including:

· our ability to obtain leases or options on properties;

· our ability to identify and acquire new exploratory prospects;

· our ability to develop existing prospects;

· our ability to continue to retain and attract skilled personnel;

32

· our ability to maintain or enter into new relationships with project partners and independent contractors;

· the results of our drilling programs;

· commodity prices; and

· our access to capital.

We may not be successful in upgrading our technical, operational and administrative resources or increasing our internal resources sufficiently to provide certain of the services currently provided by third parties, and we may not be able to maintain or enter into new relationships with project partners and independent contractors on financially attractive terms, if at all. Our inability to achieve or manage growth may materially and adversely affect our business, results of operations and financial condition.

We may incur losses as a result of title deficiencies.

We may lose title to, or interests in, our leases and other properties if the conditions to which those interests are subject are not satisfied or if insufficient funds are available to meet the commitments.

The existence of title deficiencies with respect to our oil and natural gas properties could reduce their value or render such properties worthless, which would have a material adverse effect on our business and financial results. We do not obtain title insurance and have not necessarily obtained drilling title opinions on all of our oil and natural gas properties. As is customary in the industry in which we operate, we generally rely upon the judgment of oil and natural gas lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract, and we generally make title investigations and receive title opinions of local counsel before we commence drilling operations. In some cases, we perform curative work to correct deficiencies in the marketability or adequacy of the title assigned to us. In cases involving more serious title problems, the amount paid for affected oil and natural gas leases can be lost, and the target area can become undrillable. While we undertake to cure all title deficiencies prior to drilling, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease, our investment in the well and the right to produce all or a portion of the minerals under the property. A significant portion of our acreage is undeveloped leasehold, which has a greater risk of title defects than developed acreage.

Our operations are subject to health, safety and environmental laws and regulations that may expose us to significant costs and liabilities.

Oil and gas operations are subject to various federal, state, local and foreign laws and government regulations that may change from time to time. Matters subject to regulation include discharge permits for drilling operations, well testing, plug and abandonment requirements and bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. Other federal, state, local and foreign laws and regulations relating primarily to the protection of human health and the environment apply to the development, production, handling, storage, transportation and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and gas operations, including drilling fluids and wastewater. Compliance with existing, new or modified laws and regulations could result in substantial costs, delay our operations or otherwise have a material adverse effect on our business, results of operations and financial condition. We may not be able to recover some or any of these costs from insurance. Federal and state regulators are increasingly targeting GHG emissions from oil and gas operations. While these regulatory efforts are evolving, they may require the installation of emission controls or mandate other action that may result in increased costs of operation, delay, uncertainty or exposure to liability.

33

There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we may be liable, regardless of whether we were at fault, for the full cost of removing or remediating contamination, even when multiple parties contributed to the release and the contaminants were released in compliance with all applicable laws. In addition, accidental spills or releases on our properties may expose us to significant liabilities that could have a material adverse effect on our financial condition and results of operations. Aside from government agencies, the owners of properties where our wells are located, the operators of facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal and other private parties may be able to sue us to enforce compliance with environmental laws and regulations, as well as collect penalties for violations or obtain damages for any related personal injury or property damage. Some sites we operate are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours.

In addition, our operations and financial performance may be adversely affected by governmental action, including delay, inaction, policy change or the introduction of new, or amendment of or changes in interpretation of existing legislation or regulations, particularly in relation to foreign ownership, access to infrastructure, environmental regulation (including in respect of carbon emissions and management), royalties and production and exploration licensing.

The conduct of exploration for, and production of, hydrocarbons may expose our staff to potentially harmful working environments. Occupational health and safety legislation and regulations differ in each jurisdiction. In March 2016, the Occupational Safety and Health Administration issued a final rule related to worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids. Compliance with the rule may require significant investment in engineering and workplace controls. If any of our employees suffer injury or death, compensation payments or fines may have to be paid, and such circumstances could result in the loss of a license or permit required to carry on the business, or other legislative sanction, all of which have the potential to materially and adversely affect our business, results of operations and financial condition.

We have entered into physical delivery contracts that will require further development in order to deliver all the oil required under such contracts.

We entered into midstream contracts with a large pipeline company and production purchaser to provide gathering, processing, transport and marketing of production for the Eagle Ford assets acquired in 2018. The contracts contain minimum revenue commitments, a portion of which is secured by letters of credit and performance bonds. If the planned development program is not executed to the extent projected, we may not produce sufficient quantities of hydrocarbons to meet the minimum revenue commitments and may be required to make cash deficiency payments. The deficiency payments would reduce liquidity to invest in growing the business and profitability. If we are unable to make the deficiency payments, the letters of credit and performance bonds may be drawn causing an increase in our level of indebtedness and potentially result in a default under our loan covenants.

Hydraulic fracturing, which is the process used for releasing hydrocarbons from shale rock, has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development.

Hydraulic fracturing is an important and commonly used process in the completion of unconventional oil and natural gas wells. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into deep rock formations to stimulate oil or natural gas production. Currently, hydraulic fracturing is primarily regulated in the U.S. at the state level, which generally focuses on regulation of well design, pressure testing and other operating practices. However, some states and local jurisdictions across the U.S., including states in which we operate, have begun adopting more restrictive regulations, including measures such as:

· required disclosure of chemicals used during the hydraulic fracturing process;

· restrictions on wastewater disposal activities;

34

· required baseline and post-drilling sampling of water supplies in close proximity to hydraulic fracturing operations;

· new municipal or state land use regulations, such as changes in setback requirements, which may restrict drilling locations or related activities;

· financial assurance requirements, such as the posting of bonds, to secure site restoration obligations; and

· local moratoria or even bans on oil and natural gas development utilizing hydraulic fracturing in some communities.

In addition, the federal government has the authority to regulate hydraulic fracturing on federal and tribal lands. Under the Obama administration, the Bureau of Land Management (“BLM”) issued its final regulations for hydraulic fracturing on federal and tribal lands that 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 regulations are the subject of litigation, which is still pending. At the U.S. federal level, hydraulic fracturing that does not involve the use of diesel fuels is exempt from regulation under the Safe Drinking Water Act (“SDWA”). However, the U.S. Congress (“Congress”) has considered and may continue to consider eliminating this regulatory exemption, which could subject hydraulic fracturing activities to regulation and permitting by the Environmental Protection Agency (“EPA”) under the SDWA. On June 28, 2016, the EPA issued final pre-treatment standards prohibiting the disposal of wastewater pollutants from on-shore unconventional oil and gas extraction facilities to publicly owned treatment works. The EPA’s regulation of hydraulic fracturing may result in our incurring additional costs to comply with such requirements that may be significant in nature. Such regulation may result in our experiencing delays or curtailment in the pursuit of exploration, development, or production activities, and we could even be prohibited from drilling and/or completing certain wells.

Despite the existing regulatory exemption, the EPA has begun utilizing other legal authorities in various ways to regulate portions of the hydraulic fracturing process, exemplified by its issuance of regulations under the Clean Air Act limiting emission of pollutants during the hydraulic fracturing process, as well as its recent initiation of a proposed rulemaking under the Toxic Substances Control Act to obtain data on chemical substances and mixtures used in hydraulic fracturing. In addition, the U.S. Department of the Interior has proposed comprehensive regulations governing the use of hydraulic fracturing on federally managed lands. Under the current administration, many of these regulations are under review and may be repealed or revised.

These efforts by Congress, federal regulators, states and local governments could result in additional costs, delay and operational uncertainty that could limit, preclude or add costs to use of hydraulic fracturing in our drilling operations.

Conservation measures and technological advances could reduce demand for crude oil, natural gas and NGLs.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to crude oil, natural gas and NGLs, technological advances in fuel economy and energy generation devices could reduce demand for crude oil, natural gas and NGLs. The impact of the changing demand for crude oil, natural gas and NGL services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

35

Increasing trends of opposition to oil and gas development activity and negative public perception regarding us and/or our industry could have an adverse effect on our operations.

In recent years, we have seen significant growth in anti-oil and gas development activity both in the U.S. and globally. Companies in our industry can be the target of opposition to hydrocarbon development. This opposition is focused on attempting to limit or stop hydrocarbon development in certain areas. Examples of such opposition include efforts to reduce access to public and private lands, restriction of exploration and production activities within government-owned and other lands, delaying or canceling permits for drilling or pipeline construction, limiting or banning industry techniques such as hydraulic fracturing and/or adding restrictions on the use of water and associated disposal, imposition of set-backs on oil and gas sites, delaying or denying air-quality or siting permits, advocating for increased regulations, punitive taxation, or citizen ballot initiatives or moratoriums on industry activity, and the use of social media channels to cause reputational harm.

Our need to incur costs associated with responding to these anti-development efforts, including legal challenges, or complying with any new legal or regulatory requirements resulting from these efforts, could have a material adverse effect on our business, results of operations or financial condition.

Our ability to produce oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Drilling activities require the use of water. For example, the hydraulic fracturing process that we employ to produce commercial quantities of oil and natural gas from many reservoirs, including the Eagle Ford, requires the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must be obtained from other sources and transported to the drilling site. The effects of climate change may further exacerbate water scarcity in certain regions.

Our inability to timely secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of oil and natural gas. In particular, regulatory focus on disposal of produced water and drilling waste through underground injection has increased because of alleged links between such injection and regional seismic impacts in disposal areas.

Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could materially and adversely affect our business, results of operations and financial condition.

36

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other

“greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA have allowed the agency to proceed with the adoption and implementation of regulations restricting emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Among other things, EPA regulations now require specified large greenhouse gas emitters in the U.S., including companies in the energy industry, to annually report those emissions. New major sources or significant modifications of existing sources of traditional air pollutants are required to obtain permits and to use best available control technology to control those emissions pursuant to the Clean Air Act as a prerequisite to the development of that emissions source. In addition, sources subject to best available control technology for traditional air pollutants are now also required to use best available control technology to control significant greenhouse gas emissions. While these regulations have not to date materially affected us, such regulations may over time require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce.

In May 2016, the EPA issued final regulations intended to reduce methane emissions from the oil and gas sector by 40% to 45% from 2012 levels by 2025. On October 20, 2016, the EPA issued final Control Techniques Guidelines for reducing smog-forming VOC emissions from existing oil and natural gas equipment and processes in certain states and areas with smog problems. The Obama-era methane regulations are currently under review by the Trump administration and a rule proposing to significantly revise and rescind these requirements was published by the EPA in August 2019. The methane regulations could affect us indirectly by affecting our customer base or by directly regulating our operations.

In addition, Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane that are understood to contribute to global warming. While comprehensive climate legislation will likely not be passed by either house of Congress in the near future, energy legislation and other initiatives continue to be proposed that may be relevant to greenhouse gas emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions such as electric power plants, smaller sources could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

37

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 (in the form of physical attacks or cyber-attacks) on our facilities, customer facilities, and 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.

General economic conditions could adversely affect our business and future growth.

Instability in the global financial markets may have a material impact on our liquidity and financial condition, and we may ultimately face major challenges if conditions in the financial markets were to materially change or worsen. Our ability to access the capital markets or to borrow money may be restricted or may be more expensive at a time when we would need to raise capital, which could have an adverse effect on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. Such economic conditions could have an impact on our customers, causing them to fail to meet their obligations to us. In addition, it could have an impact on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments.

Also, market conditions could have an impact on our oil and natural gas derivative instruments if our counterparties are unable to perform their obligations or seek bankruptcy protection, which could lead to reductions in the demand for oil and natural gas, or reductions in the prices of oil and natural gas or both, which could have an adverse impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of changing economic conditions cannot be predicted, they may materially and adversely affect our business, results of operations and financial condition.

Federal legislation could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.

The Dodd-Frank Act, enacted in 2010, establishes federal oversight and regulation of the OTC derivatives market and entities, like us, that participate in that market. Among other things, the Dodd-Frank Act required the Commodity Futures Trading Commission to promulgate a range of rules and regulations applicable to OTC derivatives transactions, and these rules may affect both the size of positions that we may enter or the ability and willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, such changes could materially reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices. While many Dodd-Frank Act regulations are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business remains uncertain.

In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may become subject to or otherwise impacted by such regulations. At this time, the impact of such regulations is not clear.

Our business could be adversely impacted by security threats, including cyber-security threats, and other disruptions.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, as well as conduct reservoir modeling and reserve estimation for compliance reporting.

38

We are dependent on digital technologies including information systems and related infrastructure, to process and record financial and operating data, communicate with our employees, business partners, and stockholders, analyze seismic and drilling information, estimate quantities of oil and natural gas reserves as well as other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production and financial institutions are also dependent on digital technology. The technologies needed to conduct oil and natural gas exploration, development and production activities make certain information the target of theft or misappropriation.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for the purposes of misappropriating assets or sensitive information, corrupting data, causing operational disruption, or result in denial-of-service on websites.

Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period of time. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations.

Our ability to use our net operating loss carryforwards could be limited.

As of December 31, 2019, we had approximately $292.4 million NOLs that we are allowed to carryforward for U.S. federal income tax purposes. Our NOLs begin to expire in 2033. Utilization of these NOLs depends on many factors, including our future income, which cannot be assured. In addition, Section 382 of the Code generally imposes an annual limitation on the amount of taxable income that may be offset by NOLs when a corporation has undergone an “ownership change” (as determined under Section 382 of the Code). Generally, a change in more than 50% of the ownership of a corporation’s stock, by value, over a three-year period constitutes an ownership change for U.S. federal income tax purposes. Any unused limitation may be carried forward to future taxable years. We believe that $206.2 million of our NOLs will expire unused as a result of the Section 382 limitation that resulted from a change in ownership occurring in conjunction with to our 2018 equity issuance. In addition, future ownership changes or regulatory changes could further limit our ability to utilize any NOLs. To the extent we are not able to offset our future income with NOLs, this could adversely affect our operating results and cash flows.

Ineffective internal controls could impact our business and financial results.

We are subject to Section 404(a) of the Sarbanes-Oxley Act, which requires that our management assess and report annually on the effectiveness of our internal controls over financial reporting and identify any material weaknesses in our internal controls over financial reporting. Although Section 404(b) of the Sarbanes-Oxley Act requires our independent registered public accounting firm to issue an annual report that addresses the effectiveness of our internal controls over financial reporting, we have opted to rely on the exemptions provided in the Jumpstart Our Business Startups Act (the “JOBS Act”), and consequently will not be required to comply with SEC rules that implement Section 404(b) of the Sarbanes-Oxley Act until such time as we are no longer an emerging growth company.

In connection with the preparation of this annual report, management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2019 and concluded that there was a material weakness related to deferred tax assets and the related valuation allowance, specifically related to the conversion of our historical financial statements from International Financial Reporting Standards (“IFRS”) to U.S. GAAP as a result of our Redomiciliation to the U.S.  For additional information regarding the material weakness identified please see “Part II, Item 9A — Controls and Procedures” of this annual report. 

If additional material weaknesses in internal control over financial reporting are discovered or occur in the future, it could lead to errors in our financial reports and/or delays in our financial reporting, which could require us to restate our operating results and investors may lose confidence in our operating results, the price of our shares could decline and we may be subject to litigation or regulatory enforcement actions.

39

We might not identify one or more material weaknesses in our internal controls in connection with evaluating our compliance with Section 404(a) of the Sarbanes-Oxley Act. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal controls over financial reporting, we will need to expend significant resources and provide significant management oversight. Implementing any appropriate changes to our internal controls may require specific compliance training of our directors and employees, entail substantial costs in order to modify our existing accounting systems, take a significant period of time to complete and divert management’s attention from other business concerns. These changes may not, however, be effective in maintaining the adequacy of our internal control.

We are an emerging growth company, and we cannot be certain if the reduced reporting requirements applicable to emerging growth companies will make our common stock less attractive to investors.

We are an emerging growth company, as defined in the JOBS Act. For as long as we continue to be an emerging growth company, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We expect to continue to take advantage of some or all of the available exemptions.

Risks Related with the Redomiciliation

The expected benefits of the Redomiciliation may not be realized.

We cannot be assured that the anticipated benefits of the Redomiciliation will be achieved, particularly those subject to factors beyond our control. These factors include such things as the reactions of third parties with whom we do business and the reactions of investors, analysts and Australian and U.S. taxing authorities. If events or changes in circumstances occur affecting the aforementioned factors, we may not be able to continue to realize the expected logistical and operational benefits of the Redomiciliation.

We have incurred additional costs as a result of the Redomiciliation and we expect to continue to do so.

The Redomiciliation has resulted in an increase in some of our ongoing expenses and may require us to incur some new expenses, including professional fees, to comply with applicable U.S. corporate and tax laws.

Risks Related to Our Common Stock

The price of our common stock has been and may continue to be highly volatile, which may make it difficult for stockholders to sell our common stock when desired or at attractive prices.

Following our Redomiciliation, the trading price of our common stock has been volatile, and could be subject to fluctuations in response to various factors, some of which are beyond our control. Factors such as announcements of variations in our quarterly financial results and fluctuations in revenue could also cause the market price of our common stock to fluctuate. Additionally, the stock markets have at times experienced price and volume fluctuations that have affected and might in the future affect the market prices of equity securities of many companies. These fluctuations have, in some cases, been unrelated or disproportionate to the operating performance of these companies. Further, the trading prices of publicly traded shares of companies in our industry have been particularly volatile and may be very volatile in the future. These broad market and industry fluctuations, as well as general economic, political and market conditions such as recessions, interest rate changes, international currency fluctuations or political unrest, may negatively impact the market price of our common stock. If the price of our common stock declines, our ability to raise funds through the issuance of equity or otherwise use our common stock as consideration will be reduced. A low price for our equity may negatively impact our ability to access additional debt capital. These factors may limit our ability to implement our operating and growth plans.

40

We have never declared or paid dividends on our common stock and we do not anticipate paying dividends in the foreseeable future.

We have never declared or paid cash dividends on our common stock. For the foreseeable future, we currently intend to retain all available funds and any future earnings to support our operations and to finance the growth and development of our business. Any future determination to declare cash dividends will be made at the discretion of our board of directors, subject to compliance with applicable laws and covenants under current or future credit facilities, which may restrict or limit our ability to pay dividends, and will depend on our financial condition, operating results, capital requirements, general business conditions and other factors that our board of directors may deem relevant. We do not anticipate paying any cash dividends on our common stock in the foreseeable future. As a result, a return on your investment will only occur if the price of our common stock appreciates.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Information regarding our oil and gas properties is included in Part I, Item 1. “Business” under “Oil and Natural Gas Properties”.  We also lease approximately 19,000 square feet of office space at 1050 17th Street, Suite 700, Denver, Colorado 80265, where our principal offices are located. We also have various operating leases for rental of field office space, office and field equipment, and vehicles.See Note 6 to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” for the future minimum rental payments. Such information is incorporated herein by reference.

Item 3. Legal Proceedings.

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other oil and natural gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety, and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on our financial position, cash flows or results of operations. 

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.

Market

Our common stock is traded on the Nasdaq Global Market under the symbol “SNDE”. As of April 24, 2020, there were 4,169 holders of record of our common stock.

41

Dividend Policy

We currently intend to retain any earnings to fund the operation and expansion of our business and do not anticipate paying any cash dividends on our common stock for the foreseeable future. The declaration and payment of any dividends in the future by us will be subject to the sole discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with certain of our debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our board of directors. Moreover, if we determine to pay any dividend on common stock in the future, there can be no assurance that we will continue to pay such dividends. In addition, under our debt agreements, we are not permitted to pay cash dividends on our common stock without the prior written consent of our lenders.

Item 6. Selected Financial Data.

Not applicable.

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

The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Part I, Item 1A. “Risk Factors” along with “Cautionary Statement Regarding Forward-Looking Statements” on page 2 of this annual report for information on the risks and uncertainties that could cause our actual results to be materially different from our forward-looking statements.

Overview and Executive Summary

We are an onshore independent oil and natural gas company focused on the development, production and exploration of large, repeatable resource plays in North America. Our operations are located in the Eagle Ford formation in south Texas.  Our strategy is to acquire and/or develop assets where we are operator and have high working interests, positioning us to efficiently control the pace and scope of our development and the allocation of our capital resources. We also believe that serving as operator allows us to control the drilling, completion, operations and marketing of sold volumes.  In 2019, we continued to focus on developing high-return assets from our portfolio while reducing our operating costs and per well drilling and completion costs. 

We took the following actions during 2019 in support of our corporate strategy:

· On November 26, 2019, we successfully redomiciled to the U.S. from Australia, and our common stock began trading on the Nasdaq Global Market, under the ticker symbol “SNDE”. 

· We completed and had initial production from 22 net operated wells (two of which were subsequently sold during October 2019), which increased our average daily net production 38% from 2018 to 13,248 Boe/d. 

· In October 2019, we completed the divestiture of 19 gross producing wells located on approximately 6,100 net acres located in Dimmit County, Texas for proceeds of $21.5 million, including effective date to closing date adjustments, less transaction costs of $0.5 million. Sales volumes from these wells was approximately 1,153 Boe/d during the first nine months of 2019.  The divesture provided additional liquidity to allow development of our higher return assets. 

· In January 2020, we amended our Revolving Facility to increase the overall facility from $250 million to $500 million, and to increase our borrowing base to $210 million (with initial elected borrowing commitments of $190 million). We are currently restricted in our ability to make draws until the finalization of our second quarter borrowing base redetermination.  See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under “Credit Facilities” for additional information regarding our credit facilities. 

42

Business and Industry Outlook

Market prices for crude oil, natural gas and NGLs are inherently volatile. In 2019, WTI oil prices averaged approximately $56.98 per Bbl versus $65.23 per Bbl in 2018. Despite price support in the first half of 2019 driven by supply tightness, geopolitical tensions, 2019 WTI oil prices overall were negatively impacted by trade concerns and economic slowdown fears. In March 2020, NYMEX WTI oil prices declined sharply to less than $20 per Bbl and in April 2020, for a short period of time were negative, primarily due to drastic price cutting and increased production by Saudi Arabia coupled with an expected demand reduction caused by the global COVID-19 outbreak. The U.S. domestic natural gas market remains oversupplied as production has continued to grow due to drilling efficiencies, higher incremental volumes of associated gas from oil wells and de-bottlenecking of transportation infrastructure. Henry Hub gas prices averaged approximately $2.56 per MMBtu in 2019 versus $3.15 per MMBtu in 2018. Natural gas and NGL prices faced strong headwinds in 2019 due to U.S. supply growth far outpacing demand for both commodities domestically and internationally. These factors continue to weigh on natural gas and NGL prices. To mitigate our exposure to commodity price volatility and ensure our financial strength, we continue to execute a hedging program.

We expect capital expenditures to be in the range of $40 - $45 million for 2020. However, we intend to flexibly manage our operations, including capital expenditure levels, based on existing and expected market conditions to protect our balance sheet and retain liquidity.  We expect to be able to fund our planned capital program for 2020 with cash flow generated from operating activities (which includes proceeds from settlements of hedging contracts) and cash on hand.  As of the date of this annual report, we also had $58.6 million available under our Revolving Facility. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under “Cash flows used in investing activities” for further discussion of our capital expenditures.

Year Ended December 31, 2019 Compared to the Year Ended December 31, 2018

Revenues and Sales Volume. The following table provides the components of our revenues for the years ended December 31, 2019 and 2018, as well as each period’s respective sales volumes:

	Year ended
	December 31,
Revenue (In $ ’000s):	2019		2018		Change in $		Change as %
Oil sales	$	177,853	$	140,240	$	37,613	27
Natural gas sales		12,553		12,025		528	4
NGL sales		13,174		12,668		506	4
Product revenue	$	203,580	$	164,933	$	38,647	23

	Year ended
	December 31,
Net sales volumes:	2019	2018	Change in Volume	Change as %
Oil (Bbls)	3,076,582	2,256,043	820,539	36
Natural gas (Mcf)	5,767,779	4,533,604	1,234,175	27
NGL (Bbls)	797,784	496,624	301,160	61
Oil equivalent (Boe)	4,835,663	3,508,268	1,327,395	38
Average daily production (Boe/d)	13,248	9,612	3,636	38

Boe and average net daily production. Sales volumes increased by 1,327,395 Boe (3,636 Boe/d) to 4,835,663 Boe (13,248 Boe/d) for the year ended December 31, 2019 compared to 3,508,268 Boe (9,612 Boe/d) for the prior year primarily due to our 2019 and 2018 drilling programs, which was back-loaded in the second half of 2018, partially offset by normal field production declines and downtime resulting from midstream capacity constraints, well equipment failure and simultaneous operations.  We had initial production from 22 net operated wells in 2019 and 20 net operated wells in the second half of 2018.

43

Beginning in the fourth quarter of 2018 through May 2019, we experienced capacity constraints at a midstream facility.  We and our midstream partner completed the first phase of a capacity expansion of the gas processing plant through the installation of two additional compressors in May 2019.  In the fourth quarter of 2019, our midstream partner commenced an additional expansion project to ensure capacity for future development.  The second phase of the expansion project was completed in the first quarter of 2020. 

Our sales volume is oil‐weighted, with oil representing 64% of total sales volume for both the years ended December 31, 2019 and 2018, and liquids (oil and NGLs) representing 80% and 78% of total sales volumes for the years ended December 31, 2019 and 2018, respectively.  Our oil sales and liquid sales volumes as a percentage of total sales volumes was lower in 2019 than what we expect it to be prospectively primarily due to the gassier sales volumes produced from our Dimmit County assets, which were divested in October 2019.  

Oil sales. Oil sales increased by $37.6 million (27%) to $177.9 million for the year ended December 31, 2019 from $140.2 million for the prior year. The increase in oil revenue was driven by higher sales volumes ($51.0 million), offset by lower product pricing ($13.4 million).  The average realized price on the sale of our oil decreased by 7% to $57.81 per Bbl for the year ended December 31, 2019 (a $0.83 premium to the average WTI price for the same period) from $62.16 per Bbl for the prior year. We are able to sell oil at a premium to WTI due to our proximity to Gulf Coast refining and export markets.  Oil sales volumes increased 36% to 3,076,582 Bbls for the year ended December 31, 2019 compared to 2,256,043 Bbls for the prior year.

Natural gas sales. Natural gas sales increased by $0.5 million (4%) to $12.6 million for the year ended December 31, 2019 from $12.0 million for the prior year. The increase in natural gas revenues was the result of higher sales volumes ($3.2 million), partially offset by lower product pricing ($2.7 million). Natural gas sales volumes increased 27% to 5,767,779 Mcf for the year ended December 31, 2019 compared to 4,533,604 Mcf for the prior year. The average realized price on the sale of our natural gas decreased by 18% to $2.18 per Mcf (net of certain transportation and marketing costs) for the year ended December 31, 2019 from $2.65 per Mcf for the prior year.

NGL sales. NGL sales increased by $0.5 million (4%) to $13.2 million for the year ended December 31, 2019 from $12.7 million for the prior year. The increase in NGL revenues was the result of higher sales volumes ($7.7 million), offset by lower product pricing ($7.2 million). NGL sales volumes increased 301,160 Bbls (61%) to 797,784 Bbls for the year ended December 31, 2019 compared to 496,624 Bbls for the prior year. The average realized price on the sale of our NGLs decreased by 35% to $16.51 per Bbl for the year ended 31 December 2019 from $25.51 per Bbl for the prior year. 

The following table provides a summary of our operating expenses on a per BOE basis:

	Year ended December 31,
Selected per Boe metrics	2019		2018		Change		Change as %
Total oil, natural gas and NGL revenues	$	42.10	$	47.01	$	(4.91)	(10)
Lease operating expense (1)		(5.85)		(8.04)		2.19	27
Workover expense (1)		(1.11)		(1.64)		0.53	32
Gathering, processing and transportation expense		(3.53)		(2.46)		(1.07)	(44)
Production taxes		(2.37)		(2.64)		0.27	10
Depreciation, depletion and amortization (2)		(18.96)		(17.78)		(1.18)	(7)
General and administrative expense		(4.61)		(8.70)		4.09	47

(1) Lease operating expense and workover expense are included together in lease operating and workover expenses on the consolidated statement of operations.

(2) Excludes depreciation related to corporate assets.

44

Lease operating expense. Our LOE increased by $0.1 million (less than 1%) to $28.3 million for the year ended December 31, 2019 from $28.2 million in the prior year, and decreased $2.19 per Boe to $5.85 per Boe from $8.04 per Boe. In addition to realizing economies of scale on some of our fixed LOE costs, we implemented several cost saving initiatives in early 2019 primarily focused on labor, automating measurements through supervisory control and data acquisition (“SCADA”) and compression, which have resulted in lower LOE on a per Boe basis.

Workover expense. Our workover expenses decreased $0.4 million to $5.4 million for the year ended December 31, 2019, as compared to $5.8 million for the year ended December 31, 2018.  Workover expense per Boe decreased $0.53 to $1.11 per Boe for the year ended December 31, 2019 as compared to the prior year.  The increased sales volumes have diluted the workover costs on a per unit basis due to the wells being brought online recently having higher production, but requiring less workovers. 

Gathering, processing and transportation expense (“GP&T”). GP&T increased by $8.5 million (98%) to $17.1 million ($3.53 per Boe) for the year ended December 31, 2019 as compared to $8.6 million ($2.46 per Boe) for the year ended December 31, 2018. GP&T fees are primarily incurred on production from the properties we acquired in April 2018.  Approximately $14.7 million and $5.9 million of the GP&T expense was incurred in normal course under various midstream agreements for the years ended December 31, 2019 and 2018, and the remainder of the expense was related to MRC shortfalls, as discussed below. Through our development, sales volumes from the acquired assets have increased 140% in 2019 as compared to 2018. 

Certain of our midstream agreements contain MRCs related to fees due on oil, natural gas and NGL volumes gathered, processed and/or transported. Under the terms of the contracts, if we fail to pay fees equal to or greater than the MRC under any of the contracts, we are required to pay a deficiency payment equal to the shortfall.  Our MRC commitment totaled $15.8 million and $11.1 million for the years ended December 31, 2019 and 2018, respectively.  The shortfall totaled $2.3 million ($0.49 per Boe) and $2.8 million ($0.79 per Boe) for the years ended December 31, 2019 and 2018, respectively.  We do not expect to meet the minimum revenue commitment in 2020 at the current pace of drilling. See Part I, Item 1. “Business” under “Delivery Commitments”  for additional information. 

Production taxes. Our production taxes increased by $2.2 million (24%) to $11.5 million for the year ended December 31, 2019 from $9.3 million for the prior year, which was driven by our overall increase in production.  Production taxes were 5.6% of total revenue for both the years ended December 31, 2019 and 2018.     

Depletion, depreciation and amortization expense (“DD&A”).Our DD&A expense related to proved oil and natural gas properties increased by $29.3 million (47%) to $91.7 million for the year ended December 31, 2019 from $62.4 million for the prior year.  On a per Boe basis, DD&A increased to $18.96 per Boe for the year ended December 31, 2019 compared to $17.78 per Boe in 2018. 

Impairment expense.  We recorded impairment expense of $10.0 million and $43.8 million for the years ended December 31, 2019 and 2018, respectively related to our Dimmit County oil and gas properties, which were classified as held for sale through 2018 until they were divested in October 2019.  Impairment expense was recorded to reduce the carrying value to the estimated net sales proceeds, less the costs to sell the assets. We continued to extract oil and gas from the assets while held for sale, although in accordance with accounting standards, we did not record DD&A for assets classified as held for sale.

General & Administrative expense (“G&A”). G&A decreased by $8.3 million (27%) to $22.3 million for the year ended December 31, 2019 as compared to $30.5 million for the prior year. 2018 G&A included one-time transaction costs related to our Eagle Ford acquisition totaling $12.4 million, or $3.53 per Boe.  During 2019, we incurred one-time costs, primarily legal and accounting fees, to complete our redomiciliation to the U.S of $2.7 million, or $0.55 per Boe.  G&A, excluding the costs associated with these discrete transaction, increased on an absolute basis as compared to prior year primarily due to higher salary and salary-related expense ($1.2 million), as we have increased our in-house technical staff since our Eagle Ford acquisition in 2018.  G&A on a per Boe basis, excluding the discrete transactions discussed above, decreased to $4.05 per Boe for the year ended December 31, 2019 as compared to $5.17 per Boe for the year ended December 31, 2018.

45

Gain/loss on commodity derivative financial instruments. Our commodity derivative contracts are marked to market at the end of each reporting period with the changes in fair value being recognized as gain (loss) on commodity derivative financial instruments, net.  Cash flow, however, is only impacted by the monthly settlements paid to or received by the counterparty, which are also recorded as gain(loss) on commodity derivative financial instruments, net. We had a loss on derivative financial instruments of $20.5 million for the year ended December 31, 2019 as compared to a $40.2 million gain in the prior year. In 2019, the loss on commodity hedging consisted of $31.6 million of unrealized losses on commodity derivative contracts and $11.1 million of realized gains on commodity derivative contracts.  The prior year gain on commodity hedging consisted of $40.8 million of unrealized gains on commodity derivative contracts and $0.6 million of realized losses on commodity derivative contracts.

Interest expenses, net of amounts capitalized. The components of interest expense, net of amounts capitalized was as follows (in thousands):

	Year ended December 31,
Interest Expense	2019	2018	Change in $	Change as %
Interest expense on Term Loan, Revolving Facility and other	32,720	24,264	8,456	35
Amortization of debt issuance costs	3,351	2,281	1,070	47
Expense incurred with debt modification	—	1,121	(1,121)	(100)
Loss on interest rate swap	4,270	2,435	1,835	75
Capitalized interest	(2,283)	(1,470)	(813)	55
Total	38,058	28,631	9,427	33

The increase in interest expense on our Term Loan, Revolving Facility and other for the year ended December 31, 2019 as compared to the year ended December 31, 2018 was driven by the increase in the average amount of outstanding debt, slightly offset by a decrease in market interest rates.  Our weighted average debt outstanding during 2019 was $347 million versus $250 million for 2018.  Our weighted average effective cash interest rate was 9.2% during 2019 compared to 9.7% during 2018.

In April 2018, contemporaneous with the closing of our Eagle Ford acquisition, we entered into our Revolving Facility and Term Loan, and used a portion of the proceeds to repay the previous credit facilities.  The refinance of the Term Loan was accounted for as a debt modification under ASC 470.  As a result, we recognized expense of $0.9 million for third party legal fees.  The remaining fees paid of $15.8 million were deferred and are being amortized over the life of the Term Loan. 

We recognized a loss on our interest rate swap of $4.3 million and $2.4 million for the years ended December 31, 2019 and 2018, respectively.  Our interest rate swaps are marked to market at the end of each reporting period, with the changes in fair value being recognized as interest expense.  Cash settlements paid to or received by our counterparty are also recorded as interest expense.  In 2019, the loss on the interest rate swap consisted of $3.6 million of unrealized losses and $0.6 million of realized cash settlements.  In 2018, the loss on the interest rate swap consisted of $2.1 million of unrealized losses and $0.3 million of realized cash settlements. 

Gain on foreign currency derivative financial instruments. We did not have any foreign currency derivatives in place during the year ended December 31, 2019. During the year ended December 31, 2018, we realized a gain of $6.8 million related to derivative contracts put into place to protect the capital commitments made by investors as part of our 2018 equity raise.  At the time of the equity raise, our shares were traded on the ASX, and the derivative instruments provided protection from changes in the AUD to USD exchange rate during the period from launch of equity raise to receipt of funds.  

46

Income Tax Expense (Benefit). The components of our provision for income tax expense (benefit) and our effective income tax rates were as follows (in thousands):

	Year ended December 31,
Income tax expense (benefit)	2019	2018	Change in $
Current tax expense	—	2,301	(2,301)
Deferred tax expense/(benefit)	(4,518)	11,656	(16,174)
Total income tax (benefit) expense	(4,518)	13,957	(18,475)
Effective tax rate	10.2%	-155.5%

Our effective income tax rate, as shown above, differs from the statutory rate (21%) primarily due to our valuation allowance.  See Note 9 to the consolidate financial statements for more information.

Other income (expense). During the year ended December 31, 2019, other income (expense) was primarily comprised of expense of $0.7 million for a litigation settlement related to a historical sale of non-operated North Dakota properties in 2013 and expense of $0.9 million for early termination of our drilling rig.  Other income (expense) was not material for the year ended December 31, 2018.

Adjusted EBITDAX. Management has historically used both GAAP and certain non-GAAP measures to assess our performance.  Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by our management and certain external users of our consolidated financial statements, such as investors, industry analysts and lenders.

We define “Adjusted EBITDAX” as earnings before interest expense, income taxes, DD&A, property impairments, gain/(loss) on sale of non-current assets, exploration expense, stock-based compensation, gains and losses on commodity hedging, net of settlements of commodity hedging and certain other non-cash or non-recurring income/expense items.

Our management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance, identify operating trends (which may otherwise be masked by the excluded items) and compare the results of our operations from period to period without regard to our financing policies and capital structure. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP, or as an indicator of our operating performance or liquidity.

	Year Ended December 31,
Reconciliation of Net Loss to Adjusted EBITDAX (in thousands)	2019		2018
Net loss	$	(39,590)	$	(22,933)
Add back:
Current and deferred income tax expense (benefit)		(4,518)		13,957
Interest expense		38,058		28,631
(Gain) loss on commodity derivative financial instruments, net		20,542		(40,216)
Settlement of commodity derivatives financial instruments		11,094		(599)
Depreciation, depletion and amortization expense		92,334		62,814
Impairment expense		9,990		43,828
Exploration expense		337		3,339
Noncash stock-based compensation expense		504		515
Transaction-related expenses included in general and administrative expenses		2,677		12,396
Gain on foreign currency derivatives		-		(6,838)
Minimum revenue commitment deficiency fees (1)		-		2,757
Other expense (income), net (2)		769		(237)
Adjusted EBITDAX	$	132,197	$	97,414

47

(1) Management has excluded the MRC shortfall incurred in 2018 from Adjusted EBITDAX.  The MRC is calculated on a calendar year basis, however, we did not operate the related assets until the 2018 Eagle Ford acquisition closed on April 23, 2019.  Due to the timing of the closing, our development plan was back-loaded into 2018, and we were unable to meet the MRC under the midstream agreements. 

(2) In 2019, other items of expense, net, was primarily related to litigation settlement expense of $0.8 million. In 2018, other items of expense, net, included litigation settlements of $(0.1) million and other non cash gains of $0.3 million. 

Liquidity and Capital Resources

Our primary sources of liquidity to date have been borrowings under our credit facilities, cash flow from operations, and strategic dispositions of non-core oil and gas properties.  From time to time we have also raised additional equity from investors.  Our primary use of capital has been for the acquisition and development of oil and natural gas properties. Our future ability to grow our reserves and production will be highly dependent on the capital resources available to us.

We and our wholly owned subsidiary, SEI, are parties to the syndicated $250.0 million Term Loan with Morgan Stanley Capital Administrators Inc., as administrative agent, and the Revolving Facility, which is a syndicated reserve-based revolver with Toronto Dominion (Texas) LLC, as administrative agent.  The Revolving Facility has a borrowing base of $210.0 million (with a $190 million elected commitment), of which $115.0 million was outstanding as of December 31, 2019.  As of the date of this annual report, $58.6 million was undrawn (net of $16.4 million of outstanding letters of credit), although we are currently restricted from making any new draws under the Revolving Facility until completion of the borrowing base redetermination to be completed in the second quarter of 2020.  The Revolving Facility matures October 23, 2022, and the Term Loan matures on April 23, 2023.  Our Term Loan and Revolving Facility require us to maintain a variety of financial ratios. Of the financial ratio requirements under our credit facilities, our business is generally most sensitive to the Current Ratio.  At times, it may be necessary to slow our development pace in order to maintain the required ratio.  In addition, as a result of the recent sharp decrease in oil prices, our business is sensitive to the Asset Coverage ratio, particularly in the near-term.  See “Credit Facilities” below for a description of the material terms of our credit facilities, financial ratio requirements, and our compliance with these requirements.

At December 31, 2019, our cash balance totaled $12.4 million and we had a working capital deficit of $34.0 million.  Due to the amounts that we incur related to our drilling and completion program and the timing of such expenditures, we may continue to incur working capital deficits at times in the future.

As a result of the decline in commodity prices since December 31, 2019, we expect our 2020 capital program to be in the range of $40 - $45 million.  However, we plan to respond flexibly to market conditions to protect our balance sheet and retain liquidity. We believe that our cash flow generated from operating activities (which includes proceeds from settlements of hedging contracts) and cash on hand at December 31, 2019 will be sufficient to execute this plan.    

Our liquidity is highly dependent on prices we receive for the sale of oil, gas, and NGLs we produce.  Prices we receive are determined by prevailing market conditions and greatly influence our revenue, cash flow, profitability, ability to comply with financial and other covenants in our credit facilities, access to capital and future rate of growth.  We expect that in the future, our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas.  However, in a portion of our current positions, our hedging activity may also reduce our ability to benefit from increases in oil and natural gas prices. We may realize losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will realize gains to the extent our derivatives contract prices are higher than market prices. At times, we may choose to liquidate derivative positions before the contract ends in order realize the current value of our existing positions, to the extent permitted by our credit facilities. Please see Note 10 to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report for a summary of our outstanding derivative positions as of December 31, 2019.

48

Similar to what we have experienced in previous periods of sustained low commodity prices, the prevailing market price for oil and gas services has also decreased, including the types of costs included in our lease operating expenses, drilling costs, completion costs and costs to equip our wells.  Since the sharp decline in oil pricing in March 2020, we have renegotiated pricing with a number of our vendors and we have secured contractual arrangements with drilling and completion service providers at reduced costs relative to those in place during 2019 and the assumed cost structure used in our year-end reserve report.  Additionally, we have changed our field operating procedures in response to the material drop in oil prices which further serves to reduce our cost structure relative to that assumed in the Company’s year-end reserve report.  We are actively working to secure additional cost savings and if commodity prices remain low for a sustained period of time, we expect further reductions to our costs. 

If commodity prices remain depressed for an extended period of time or the capital/credit markets become constrained, the borrowing capacity under our Revolving Facility could be adversely affected. In the event of a reduction in the borrowing base under our Revolving Facility, we may be required to prepay some or all of our indebtedness prior to maturity, which would adversely affect our capital expenditure program. 

The amount, timing and allocation of these and other future expenditures is largely discretionary. As a result, the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects and market conditions.

Cash Flows

Our cash flows for the years ended December 31, 2019 and 2018 are as follows:

	Year ended December 31,
(In $ ’000s)	2019		2018
Net cash provided by operating activities	$	111,229	$	43,814
Net cash used in investing activities	$	(149,989)	$	(386,788)
Net cash provided by financing activities	$	49,581	$	338,817

Cash flows provided by operating activities. Cash provided by operating activities for the year ended December 31, 2019 was $111.2 million, an increase of $67.4 million compared to the prior year ($43.8 million). This increase was primarily due to higher revenues resulting from an increase in production volumes, partially offset by lower pricing.  Including the impact of derivative settlements, our realized price per Boe decreased 5% to $44.39 per Boe as compared to $46.84 per Boe.  During 2019, we had cash settlements from our derivative contracts of $11.3 million, of which $3.6 million was generated from unwound derivative contracts.  Despite our 38% increase in production volumes, we have been able to realize lower LOE and workover and G&A costs on a per Boe basis due to economies of scale and internal cost saving initiatives, which increased our operating margin in 2019.  

Due to payment timing, our cash flows from operations for the year ended December 31, 2019 included three quarterly interest payments on our Term Loan, whereas, the year ended December 31, 2018 included four quarterly interest payments, which resulted in higher cash flows in 2019 of $6.5 million.  During 2018, we paid federal withholding taxes of $2.3 million related to a U.S. tax restructuring for our subsidiaries. 

Cash flows used in investing activities. Cash used in investing activities for the year ended December 31, 2019 decreased to $150.0 million as compared to $386.8 million in prior year. In 2019 net cash flows used in investing activities was primarily for development of proved properties ($166.7 million), partially offset by the sale of our Dimmit County, Texas, oil and gas assets in October 2019 ($17.3 million).  We expect to receive the additional proceeds from the sale of $4.2 million in 2020.  Net cash used in investing activities in 2018 included $215.8 million for the Company’s Eagle Ford acquisition and $169.0 million for development of our oil and gas properties.  See Capital Expenditures below for additional information regarding our investment in oil and gas properties. 

49

Cash flows provided by financing activities. Cash provided by financing activities for the year ended December 31, 2019 decreased to $49.6 million as compared to $338.8 million for the year ended December 31, 2018.  During 2019, we borrowed $50.0 million on our Revolving Facility to fund a portion of our 2019 drilling program.  In 2018, we raised $250.1 million (net of fees and including the impact of our foreign currency derivatives) in connection with the Eagle Ford acquisition, plus proceeds from borrowings of $315 million as a result of entering into our Term Loan and Revolving Facility. This was partially offset by the repayment of our previous credit facility of $192 million, the repayment of a production advance from our then oil purchaser, of $18.2 million and borrowing costs of $16.0 million.  

Capital Expenditures

The following table summarizes our capital expenditures incurred (excluding acquisitions and changes related to its asset retirement obligation) for the years ending December 31, 2019 and 2018.

	Year ending December 31
(In $ ’000s)	2019		2018		Change in $	Change in %
Unproved (1)	$	177	$	1,609	(1,432)	(89)
Proved (1)		149,766		181,463	(31,697)	(17)
Total	$	149,943	$	183,072	(33,129)	(18)

(1) Capital expenditures for unproved properties includes costs incurred at our Dimmit County properties, which were held for sale and disposed of in October 2019, of nil and $1.0 million during the years ended December 31, 2019 and 2018, respectively.  Capital expenditures for proved properties includes costs incurred at the Dimmit County properties of $8.4 million and $5.3 million as of December 31, 2019 and 2018, respectively.  We began drilling two wells in late 2018 in Dimmit County to extend the acreage lease term.

Our capital expenditures for proved properties for the year ended December 31, 2019 decreased 17% to $149.8 million, as compared to $181.5 million in the prior year.  Our drilling and completion costs totaled $125.0 million, which included costs to add 22.3 net producing wells and there were 2.0 additional net operated wells waiting on completion and 0.3 non operated wells in the process of being drilled.  In addition, we invested $13.6 million into shared facility projects during the year ended December 31, 2019. 

Credit Facilities

We and our wholly owned subsidiary, SEI, are parties to the Term Loan, which is syndicated $250.0 million second lien term loan with Morgan Stanley Capital Administrators Inc., as administrative agent, and the Revolving Facility, which is a syndicated reserve-based revolver with Toronto Dominion (Texas) LLC, as administrative agent, which has a borrowing base of $210.0 million, an elected commitment of $190 million, and $115.0 million outstanding as of December 31, 2019. The Revolving Facility matures October 23, 2022, and the Term Loan matures on April 23, 2023. We refer to our Revolving Facility and Term Loan collectively as our “credit facilities”.

Interest on the Revolving Facility accrues at LIBOR plus a margin that ranges from 2.25% to 3.25% based upon the amount drawn. Interest on the Term Loan accrues at LIBOR (with a LIBOR floor of 1.0%) plus 8.0%.

Under the Revolving Facility, we are required to maintain the following financial ratios:

· a minimum Current Ratio, consisting of consolidated current assets (as defined in the Revolving Facility) including undrawn borrowing capacity to consolidated current liabilities (as defined in the Revolving Facility), of not less than 1.0 to 1.0 as of the last day of any fiscal quarter;

· a maximum Leverage Ratio, consisting of consolidated Total Debt to adjusted consolidated EBITDAX (as defined in the Revolving Facility), of not greater than 3.5 to 1.0 as of the last day of any fiscal quarter; and

· a minimum Interest Coverage Ratio, consisting of EBITDAX to Consolidated Interest Expense (as defined in the Revolving Facility), of not less than 1.5 to 1.0 as of the last day of any fiscal quarter (for such time as there a similar covenant under ours or SEI’s subordinated indebtedness).

50

Under the Term Loan, we are required to maintain the following financial ratios:

· a minimum Interest Coverage Ratio, consisting of EBITDAX to Consolidated Interest Expense (as defined in the Term Loan), of not less than 1.5 to 1.0 as of the last day of any fiscal quarter (for such time as there a similar covenant under ours or SEI’s subordinated indebtedness); and

· an Asset Coverage Ratio, consisting of Total Proved PV9% to Total Debt (as defined in the Term Loan agreement), of not less than 1.50 to 1.0.

The Revolving Facility agreement requires us to hedge at least 50% of reasonably projected oil and gas production from the Proved Reserves classified as “Developed Producing Reserves” for a rolling 36 month period, but not more than 85% of reasonably projected production from the Proved Reserves for a rolling 24 months and not more than 75% of the reasonably projected production from the Proved reserves for months 25-60.

EBITDAX, as defined in the Term Loan and the Revolving Facility, is calculated as consolidated net income (loss) less the impact of interest, income taxes, depreciation, depletion, amortization, exploration expenses and other non-cash charges and income (including stock-based compensation, and unrealized gains and loss on derivative instruments). In addition, our Credit Agreements contain various covenants that limit our ability to take certain actions, including, but not limited to, the following:

· incur indebtedness or grant liens on any of our assets;

· enter into certain commodity hedging agreements;

· sell, transfer, assign or convey assets, including a sale of all or substantially all of our assets, or engage in certain mergers or acquisitions;

· make certain distributions (including payments of dividends);

· make certain loans, advances and investments; and

· engage in transactions with affiliates.

If an event of default exists under either the Revolving Facility or the Term Loan, the administrative agents will be able to terminate the commitments under the credit facilities and accelerate the maturity of all loans made pursuant to our credit facilities and exercise other rights and remedies. Events of default include, but are not limited to, the following events:

· failure to pay any principal when due under the Revolving Facility or Term Loan;

· failure to pay any other obligation when due and payable within three business days after same becomes due

· failure to observe or perform any covenant, condition or agreement in the Revolving Facility or Term Loan or other loan documents, subject, in certain instances, to certain cure periods;

· failure of any representation and warranty made in connection with the loan documents to be true and correct in all material respects;

· bankruptcy or insolvency events involving us or our subsidiaries;

· cross-default to other indebtedness in excess of $5 million;

· certain ERISA events involving us or our subsidiaries;

· a violation of the terms of the Intercreditor Agreement; and

· a change of control (as defined in our credit facilities).

We and SEI and their respective subsidiaries have also executed and delivered certain other related agreements and documents pursuant to the credit facilities, including a guarantee and collateral agreement and mortgages for both the Revolving Facility and the Term Loan. Our obligations as well as those of SEI and SEI’s respective subsidiaries under the Revolving Facility are secured by a first priority security interest in favor of the lenders, in our, SEI’s and SEI’s respective subsidiaries’ tangible and intangible assets, and proved reserves, among other things. Our obligations as well as those of SEI and SEI’s respective subsidiaries under the Term Loan are secured by a second priority security interest in favor of the lenders, in our, SEI’s and SEI’s respective subsidiaries’ tangible and intangible assets, and proved reserves, among other things.

51

A breach of any covenant, including the Asset Coverage Ratio, in our credit agreements will result in default under both our Term Loan and cross default on our Revolving Credit Facility, after any applicable grace period.  A default, if not waived, could result in acceleration of the amounts outstanding under the credit facilities.  In the event that some or all of the amounts outstanding under our credit facilities are accelerated and become immediately due and payable, we may not have the funds to repay, or the ability to refinance, such outstanding amounts and our lenders could foreclose upon our assets.  If we are unable to remain in compliance with our financial and non-financial covenants, we intend to seek a waiver or covenant relief.  However, no assurances can be given that we will be able to obtain such relief. 

As of December 31, 2019, we were in compliance with all the covenants in our Revolving Facility and Term Loan.  As described above, we are required to maintain an Asset Coverage Ratio of not less than 1.5 to 1.0, which is calculated as the value of our Total Proved Reserves (PV 9%) using Nymex pricing and giving consideration to the value of our commodity derivative instruments, to Total Debt. The value of our oil and gas reserves, (including “Total Proved Reserves” as described in the Term Loan agreement) is highly sensitive to future commodity prices, and as a result of the decline in prices since year-end, there is uncertainty regarding our ability to maintain the covenant through the 12 months following the date of this report.  We regularly enter into commodity derivative contracts to protect the cash flows associated with our proved developed producing wells and to provide supplemental liquidity to mitigate decreases in revenue due to reductions in commodity prices.  As described above, we believe, based on historical experience, that the prevailing market price for oil and gas services also decreases during periods of sustained low commodity prices, and we have secured numerous cost reductions to date in 2020.

Despite the risks and uncertainties described above, we believe we have or likely will be able to implement plans to substantially mitigate any potential breach of covenant related to this pricing downturn.  However, since we cannot guarantee our ability to maintain compliance with the Asset Coverage Ratio and other covenants and cannot guarantee that we will be able to obtain waivers if a covenant is breached, it raises uncertainty about our ability to continue as a going concern.

As described above, the Revolving Facility and Term Loan each contain reporting covenants that require delivery of audited consolidated financial statements and related reports and certificates on or before certain deadlines,  provided for in each of the Revolving Facility and Term Loan Facility.  Additionally, our financial statements must be delivered without a going concern or like qualification or exception.  Failure to comply with these covenants would constitute a default under both the Revolving Facility and Term Loan.  The report of the Company’s independent registered public accounting firm that accompanies our audited consolidated financial statements in this annual report contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern.  To address this, and any potential default arising from a failure to deliver consolidated audited financial statements and related reports and certificates by the applicable deadlines, we have entered into waivers with our lenders under the Revolving Facility and Term Loan.  These waivers were effective as of April 29, 2020, subject to the conditions set forth in the waivers, which included delivery of our audited consolidated financial statements for the fiscal year ended December 31, 2019 and related reports and certificates, and payment of the fees and expenses of the administrative agent incurred in connection with such waivers

In consideration for the waiver under our Revolving Facility, we agreed to certain limitations on our ability to effect draws under the Revolving Facility until such time as the May 2020 borrowing base redetermination has been completed.   In addition, in consideration for the waiver with respect to the Term Loan, we agreed to amend certain covenants in the Term Loan, as to be mutually agreed with the Term Loan lenders within 15 days.  The waiver under our Revolving Facility also provides for a right to require corresponding amendments of that facility manner, as requested by the administrative agent in its discretion. Failure to enter into such amendment with respect to our Term Loan within 15 days (or a similar amendment with respect to our Revolving Facility on the date the Term Loan is amended) would constitute an event of default under our credit facilities, in which case the amounts outstanding under our credit facilities could be accelerated and become immediately due and payable. While we believe that we will finalize such amendments within the required time frame, there can be no assurance that our efforts will result in any finalizing these amendments or the ultimate terms of any such amendments.

52

With respect to the Term Loan, we have engaged in preliminary discussions regarding the terms of the required amendment.  In addition, we and have agreed to explore in good faith with our Term Loan Lenders options to reduce our overall level of indebtedness and leverage and limit capital and general and administrative expenditures for some specified period of time.  As described above, the lenders under our Revolving Facility may request corresponding amendments under the Revolving Facility.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have, or are reasonably likely to have, a current or future effect on our financial statements, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in our financial statements. Actual results could differ from our estimates and assumptions, and these differences could result in material changes to our financial statements. The following discussion presents information about our most critical accounting policies and estimates. Our significant accounting policies are further described in Note 1 to our audited consolidated financial statements included in “Item 8. Financial Statements and Supplemental Data” of this annual report.

Estimates of Oil and Gas Reserve Quantities. The estimated quantities of oil, natural gas and NGL reserves are integral to the calculation of DD&A and to assessments of possible impairment of assets. Proved oil and gas reserves are those quantities of oil and 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 and under existing economic conditions, operating methods, and government regulations.  These estimates require significant judgements to be made regarding future development and production costs, development plans and fiscal regimes. The estimates of reserves may change from period to period as the economic assumptions used to estimate the reserves can change from period to period and as additional geological data is generated during the course of operations. Ryder Scott prepared 100% of our proved reserve estimates as of December 31, 2019 and 2018. In connection with Ryder Scott performing their independent reserve estimations, we furnish them with the following information that they review: (i) technical support data, (ii) technical analysis of geologic and engineering support information, (iii) economic and production data and (iv) our well ownership interests and (v) expected future development plans.

Depreciation, Depletion and Amortization. The quantities of estimated proved oil and gas reserves are a significant component of our calculation of DD&A expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserve quantities were revised upward or downward, net income would increase or decrease, respectively.

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method.  The reserve base used to calculate depreciation, depletion and amortization for proved leasehold acquisition costs is the sum of proved developed reserves and proved undeveloped reserves.  With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves.  We have one unit-of-production field, the Eagle Ford formation. This method considers the geographic concentration, operating similarities within the area, geologic considerations and common cost environments in this area.

53

Proved Property Impairment. We assess our proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. We estimate the expected future cash flows of our oil and gas properties and compare these undiscounted cash flows to the carrying value of the oil and gas properties to determine if the carrying value is recoverable.  We may apply an additional risk-adjustment factor to the undiscounted cash flows from proved undeveloped reserves. If the carrying value exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, estimated future operating costs, and discount rates commensurate with the risk associated with realizing the projected cash flows.

Our impairment analysis requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our oil and gas properties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may incur impairment expense.  As a result of lower commodity prices and their impact on our estimated future cash flows, we have continued to review our proved oil and gas properties for impairment. At December 31, 2019, using SEC defined pricing as described in Note 16, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties by approximately $801 million, or 112%.  As of December 31, 2019, our reserve estimate, updated with management’s future pricing assumptions as of that date, was higher than the SEC reserve value.

Unproved Property Impairment. Unproved properties consist of costs incurred to acquire undeveloped leases as well as purchases of unproved reserves. Undeveloped lease costs and unproved reserve acquisitions are initially capitalized, and when successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. We evaluate significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, or future plans to develop acreage.

Derivative Financial Instruments. We use derivative financial instruments to mitigate our exposure to changes in commodity prices arising in the normal course of business. We primarily utilize commodity price swap, option and costless collar contracts. We do not trade in derivative financial instruments for speculative purposes. None of our derivative contracts have been designated as cash flow hedges for accounting purposes, and as a result, all of our derivative contracts are recorded in the consolidated financial statements at fair value, with changes in derivative fair value being recognized currently in earnings. 

We determine the recorded amounts of our derivative instruments measured at fair value utilizing third-party valuation specialists, who utilize industry-standard models that consider various assumptions, including quoted forward prices for commodities, time to maturity, volatility and credit risk.  We review these valuations, including the related model inputs and assumptions, and analyze changes in fair value measurements between periods.  We corroborate such inputs, calculations and fair value changes using various methodologies, and review unobservable inputs for reasonableness utilizing relevant information from other published sources.  We also utilize counterparty valuations to assess the reasonableness of our valuations.  The values we report in our financial statements change as the assumptions used in these valuations are revised to reflect changes in market conditions (particularly those for oil and natural gas forward prices) or other factors, many of which are beyond our control.

Income Taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not, including judgments and assumptions about future taxable income and future operating conditions (particularly as related to prevailing oil and natural gas prices). For the year ended December 31, 2019, we did not recognize tax assets of $64.9 million as the recovery was not determined to be more likely than not. Some or all of these deferred tax assets could be recognized in future periods against future taxable income.

54

Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement could have an impact on our results of operations. Revisions to our estimated effective tax rate could increase or decrease our reported income tax expense or benefit.

Our effective and statutory income tax rates could be impacted by the state income tax rates in which we operate, and the effective and statutory income tax rates are not significantly different as the amount of permanent differences resulting from treatment that differs for assets and liabilities for financial and tax reporting purposes is not significant. The tax impact of temporary differences, primarily oil and gas properties, is reflected in deferred income taxes. At December 31, 2019 and 2018, we had no unrecognized tax benefits that would impact our effective tax rate and we have not provided for interest or penalties related to uncertain tax positions.

Asset Retirement Obligations. Asset retirement obligations (“ARO”) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition in accordance with applicable local, state and federal laws as well as the terms of our lease agreements.  The discounted fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is spud or acquired) with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset.  The liability is accreted each period through charges to DD&A expense, and the capitalized cost is depleted on a unit-of-production basis over the proved developed reserves of the related asset. Revisions may occur due to changes in estimated abandonment costs or well economic lives, and such revisions result in adjustments to the related capitalized asset and corresponding liability.

Revenue Recognition. Our revenue is derived from the sale of produced oil, natural gas and NGLs. Revenue is recorded in the month the product is delivered to the purchaser, while payment is received up to 60 days after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. Historically the differences have not been material. 

Transfer of control drives the statement of operations classification of transportation, gathering, processing, and marketing expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within gathering, processing and transportation expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of revenue.

Recently Issued Accounting Pronouncements.  See Note 1 to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report for discussion of the recent accounting pronouncements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Not applicable.

Item 8. Financial Statements and Supplementary Data.

The financial statements and supplementary information required by this Item appears on pages 60 through 100 of this annual report.

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

None.

55

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

As of December 31, 2019, our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a‑15(e) under the Exchange Act). Disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures.  There are inherent limitations to the effectiveness of any disclosure controls and procedures system, including the possibility of human error and circumventing or overriding them. Even if effective, disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives.

Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that due to the material weakness in our internal control over financial reporting related to the IFRS to US GAAP conversion as described below, the Company’s disclosure controls and procedures were not effective as of December 31, 2019.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2019 based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework (2013).  Based on this assessment, our Chief Executive Officer and Chief Financial Officer concluded that a material weakness in internal control over financial reporting existed as of December 31, 2019, as described below.

A material weakness is a deficiency, or combination of deficiencies in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

In connection with the conversion of our financial statements from IFRS to U.S. GAAP following our Redomiciliation, an analysis of the valuation allowance related to deferred tax assets as of December 31, 2019 was not prepared in a timely manner.  We did not have a process for identifying when an analysis should be prepared other than on an annual basis. When the analysis was prepared, it resulted in a $3.7 million adjustment to deferred income tax benefit and to the associated balance sheet account.  This control deficiency created a reasonable possibility that a material misstatement to the consolidated financial statement would not have been prevented or detected on a timely basis, and therefore management concluded that the deficiency represented a material weakness in internal control over financial reporting, and that internal control over control over financial reporting was not effective as of December 31, 2019.

We have updated our policy and processes to require that we perform an update of the analysis of the valuation allowance related to deferred tax assets for the tax implications of non-recurring events when a nonrecurring event occurs.

Changes in internal control over financial reporting

Other than the material weakness associated with the IFRS to US GAAP conversion discussed above, there was no change in our internal control over financial reporting that occurred during the quarter ended December 31, 2019, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

56

Because we are an “emerging growth company” under the JOBS Act, our independent registered public accounting firm, Deloitte & Touche LLP, is not required to issue an attestation report on our internal control over financial reporting.

Item 9B. Other Information.

On May 8, 2020 and May 11, 2020, respectively, we obtained waivers from its Revolving Facility and Term Loan lenders to waive the event of default arising from the inclusion of the going concern explanatory paragraph included in the audit report for the year ended December 31, 2019 and with respect to the defaults arising from a failure to deliver audited consolidated financial statements for the year ended December 31, 2019 and related reports and certificates by the applicable deadline.  These waivers were effective as of April 29, 2020, subject to the conditions set forth in the waivers.  

Under the Revolving Facility waiver, we may not draw any additional funds on the Revolving Facility until completion of our second quarter 2020 borrowing base redetermination.     

Under the Term Loan waiver, we agreed to amend certain provisions in the Term Loan, as to be mutually agreed with the Term Loan lenders, within 15 days from the execution date.  The waiver under the Revolving Facility also provides for a right to require corresponding amendments of that facility manner, as requested by the administrative agent in its discretion. Failure to enter into such amendment with respect to the Term Loan within 15 days (or a similar amendment with respect to the Revolving Facility on the date the Term Loan is amended) would constitute an event of default under the credit facilities, in which case the amounts outstanding under the credit facilities could be accelerated and become immediately due and payable.  While management believes that it will finalize such amendments within the required time frame, there can be no assurance that management’s efforts will result in any finalizing these amendments or the ultimate terms of any such amendments. 

With respect to the Term Loan, we have engaged in preliminary discussions regarding the terms of the required amendment.  In addition, we have agreed to explore in good faith with its Term Loan lenders options to reduce our overall level of indebtedness and leverage and limit capital and general and administrative expenditures for some specified period of time.  As described above, the lenders under the Revolving Facility may request corresponding amendments under the Revolving Facility.

The forgoing summary of the waivers is qualified in its entirety by reference to the full text of such waivers, copies of which are attached as Exhibit 10.19 and Exhibit 10.20 to this annual report, respectively, and incorporated herein by reference.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

The information concerning our executive officers and directors in response to this item will be included in the Proxy Statement for our 2020 Annual Meeting of Stockholders and is incorporated herein by reference.  

Item 11. Executive Compensation.

The information required by this item will be included in our Proxy Statement for our 2020 Annual Meeting of Stockholders, and is incorporated herein by reference.

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

The information required by this item will be included in our Proxy Statement for our 2020 Annual Meeting of Stockholders and is incorporated herein by reference.

57

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

The information required by this item will be included in our Proxy Statement for our 2020 Annual Meeting of Stockholders and is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services.

The information required by this item will be included in our Proxy Statement for our 2020 Annual Meeting of Stockholders and is incorporated herein by reference.

PART IV

Item 15. Exhibits, Financial Statement Schedules.

Financial Statements.  Refer to the Index to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report for a list of all financial statements filed as part of this report.

Financial Statement Schedules.  All schedules are omitted since the required information is not present, or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in our Consolidated Financial Statements or the Notes thereto included in Item 8. “Financial Statements and Supplementary Data” of this annual report.

Exhibits. The exhibits listed in the accompanying exhibit index are filed (except where otherwise indicated) as part of this report.

Item 16. Form 10‑K Summary.

None.

58

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Sundance Energy Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Sundance Energy Inc. and its subsidiaries (the "Company") as of December 31, 2019 and 2018, the related consolidated statements of operations and comprehensive loss, changes in equity, and cash flows, for each of the two years in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of 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.

Basis for Opinion

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

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

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

Going Concern

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company anticipates that it may not comply with the covenant requirements of the Credit Facilities within the next 12 months following the date of this report, which would accelerate the amounts outstanding under the credit facilities, making it currently due and payable. The Company does not have sufficient liquidity to repay such outstanding amounts. This issue raises substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Deloitte & Touche LLP

Denver, CO

May 14, 2020

We have served as the Company's auditor since 2019.

59

SUNDANCE ENERGY INC.

CONSOLIDATED BALANCE SHEETS

(all amounts in thousands except share and per share data)

	December 31,
	2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	12,382	$	1,581
Accounts receivable trade and other		27,020		21,249
Derivative financial instruments		1,215		24,315
Income tax receivable		3,555		2,384
Other current assets		3,616		3,547
Assets held for sale		—		23,471
Total current assets		47,788		76,547
Oil and gas properties, successful efforts method		1,122,908		986,548
Less: accumulated depletion, depreciation and amortization		(379,961)		(293,598)
Total oil and gas properties, net		742,947		692,950
Other long-term assets:
Other property and equipment, net of accumulated depreciation of $3,419 and $2,823		1,963		1,354
Income tax receivable		1,172		2,344
Operating lease right-of-use assets		17,331		—
Derivative financial instruments		878		8,003
Other long-term assets		1,835		2,150
TOTAL ASSETS	$	813,914	$	783,348
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable trade	$	43,284	$	45,137
Accrued liabilities		26,409		25,285
Derivative liabilities		4,394		436
Operating lease liabilities - current		7,720		—
Liabilities related to assets held for sale		—		193
Total current liabilities		81,807		71,051
Long-term liabilities:
Long-term debt		353,490		300,804
Asset retirement obligations		3,653		3,296
Operating lease liabilities - long term		9,611		—
Derivative financial instruments		3,669		2,578
Deferred tax liabilities		7,138		11,656
Other long-term liabilities		1,149		1,474
Total long-term liabilities		378,710		319,808
Total liabilities		460,517		390,859
Commitments and contingencies (Note 14)
Stockholders’ Equity:
Common stock, $0.001 value, 100,000,000 shares authorized; 6,875,672 issued and outstanding at December 31, 2019 and 6,874,622 shares issued and outstanding at December 31, 2018.		7		7
Additional paid-in capital		633,246		632,742
Accumulated deficit		(279,144)		(239,554)
Accumulated other comprehensive loss		(712)		(706)
Total stockholders’ equity		353,397		392,489
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	813,914	$	783,348

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

60

SUNDANCE ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

(all amounts in thousands except share and per share data)

			For the year ended December 31,
Revenues:			2019		2018
	Oil sales		$	177,853	$	140,240
	Natural gas sales			12,553		12,025
	Natural gas liquid sales			13,174		12,668
		Total revenues		203,580		164,933
Operating expenses:
	Lease operating and workover expense			33,681		33,957
	Gathering, processing and transportation expense			17,086		8,633
	Production taxes			11,484		9,270
	Exploration expense			337		3,339
	Depreciation, depletion and amortization expense			92,334		62,814
	Impairment expense			9,990		43,828
	General and administrative expense			22,276		30,539
	Loss (gain) on commodity derivative financial instruments			20,542		(40,216)
	Other expense (income), net			1,900		(48)
		Total operating expenses		209,630		152,116
Income (loss) from operations:				(6,050)		12,817
Other income (expense)
	Interest expense			(38,058)		(28,631)
	Gain on foreign currency derivative financial instruments			—		6,838
		Total other expense		(38,058)		(21,793)
Loss before income taxes				(44,108)		(8,976)
Income taxes
	Current expense			—		(2,301)
	Deferred benefit (expense)			4,518		(11,656)
		Total income tax benefit (expense)		4,518		(13,957)
Net loss			$	(39,590)	$	(22,933)
Loss per common share
		Basic and diluted	$	(5.76)	$	(4.38)
Weighted average shares outstanding
		Basic and diluted		6,874,170		5,236,524
Comprehensive loss
	Net loss		$	(39,590)	$	(22,933)
	Other comprehensive income (loss):
		Foreign currency translation		(6)		428
Total comprehensive loss			$	(39,596)	$	(22,505)

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

61

SUNDANCE ENERGY INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(all amounts in thousands except share and per share data)

										Accumulated
										other
		Common stock				Additional		Accumulated		comprehensive
		Shares	Amount			Paid-In Capital		Deficit		loss	Total
BALANCES - January 1, 2018		1,253,250	$	1	$	389,013	$	(216,621)	$	(1,134)	$	171,259
	Fractional shares issued upon reverse split	10		—		—		—		—		—
	Shares issued in connection with private placement	5,614,446		6		253,511		—		—		253,517
	Private placement offering costs, net of tax	—		—		(10,297)		—		—		(10,297)
	Stock-based compensation	6,916		—		515		—		—		515
	Net loss	—		—		—		(22,933)		—		(22,933)
	Foreign currency translation	—		—		—		—		428		428
BALANCES - December 31, 2018		6,874,622	$	7	$	632,742	$	(239,554)	$	(706)	$	392,489
	Stock-based compensation	1,050		—		504		—		—		504
	Net loss	—		—		—		(39,590)		—		(39,590)
	Foreign currency translation	—		—		—		—		(6)		(6)
BALANCES - December 31, 2019		6,875,672	$	7	$	633,246	$	(279,144)	$	(712)	$	353,397

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

62

SUNDANCE ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(all amounts in thousands except for share and per share data)

				Year Ended December 31,
					2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES
	Net loss			$	(39,590)	$	(22,933)
	Adjustments to reconcile net loss to net cash provided by operating activities:
		Depreciation, depletion and amortization expense			92,334		62,814
		Impairment expense			9,990		43,828
		Loss on abandonment of unproved oil and gas properties			—		550
		Stock-based compensation			504		515
		Deferred income tax (benefit) expense			(4,518)		11,656
		Gain on foreign currency derivative financial instruments			—		(6,838)
		Loss (gain) on commodity derivative financial instruments			20,542		(40,216)
		Net cash settlements received on commodity derivative contracts			11,258		(599)
		Premiums (paid) received on commodity derivative contracts			(152)		634
		Unrealized loss on interest rate swaps			3,625		2,137
		Amortization of deferred financing fees			3,234		2,281
		Write-off of deferred financing fees			—		251
		Other			(83)		—
	Changes in assets and liabilities:
		Accounts receivable trade and other			2,539		(17,728)
		Accounts payable trade			2,512		9,014
		Accrued liabilities			9,803		(1,144)
		Other assets and liabilities, net			(769)		(408)
			Net cash provided by operating activities		111,229		43,814
CASH FLOWS FROM INVESTING ACTIVITIES
	Capital expenditures for proved oil and gas properties				(166,646)		(168,956)
	Capital expenditures for unproved oil and gas properties				(319)		(1,790)
	Acquisition of oil and gas properties				—		(215,790)
	Proceeds from the sale of oil and gas properties				17,383		100
	Other property and equipment				(407)		(352)
			Net cash used in investing activities		(149,989)		(386,788)
CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from borrowings				50,000		315,000
	Repayments of borrowings				—		(210,194)
	Payments of debt issuance costs				(232)		(16,040)
	Proceeds from issuance of common shares				—		253,517
	Equity offering costs				—		(10,293)
	Receipts from foreign currency derivatives				—		6,838
	Principal payments on finance lease obligations				(187)		(11)
			Net cash provided by financing activities		49,581		338,817
			Net change in cash and cash equivalents		10,821		(4,157)
CASH AND CASH EQUIVALENTS
			Beginning of year		1,581		5,761
			Effect of exchange rates on cash		(20)		(23)
			End of year	$	12,382	$	1,581
SUPPLEMENTAL CASH FLOW DISCLOSURES
	Income taxes paid			$	—	$	2,301
	Interest paid, net of amounts capitalized			$	26,203	$	26,359
NON-CASH INVESTING AND FINANCING ACTIVITIES
	Accounts payable and accrued expenses for oil and gas properties			$	25,000	$	38,508

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

63

SUNDANCE ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Operations

On November 26, 2019, a new Delaware corporation named Sundance Energy Inc. (the “Company”) acquired all of the issued and outstanding ordinary shares of Sundance Energy Australia Limited (“SEAL”), an Australian Company, pursuant to a Scheme of Arrangement under Australian law (the “Scheme”) which was approved by SEAL’s shareholders on November 8, 2019 and the Federal Court of Australia on November 14, 2019.  These events are collectively referred to as the “Redomiciliation”.  Prior to the Redomiciliation, the Company’s ordinary shares were listed on the Australian Securities Exchange (“ASX”) and Sundance Energy Inc. had no business or operations. Following the Redomiciliation, the business and the operations of Sundance Energy Inc. consist solely of the historical business and operations of SEAL and its subsidiaries.  

In the Redomiciliation, all outstanding SEAL ordinary shares on November 26, 2019, were cancelled and shares of the Company’s common stock, par value $0.001 per share, were issued.  Each of SEAL’s shareholders received one share of the Company’s common stock in exchange for 100 SEAL ordinary shares held.

The purpose of the Redomiciliation was to reorganize the operations of SEAL, a public company incorporated under the laws of the State of South Australia, into a structure whereby the ultimate parent company of the Sundance group of companies would be a Delaware corporation. In connection with the Redomiciliation, the ordinary shares of SEAL were delisted from the ASX, and the common stock of Sundance Energy Inc. began trading on the Nasdaq Global Market on November 26, 2019 under the ticker symbol “SNDE”, the same symbol under which SEAL’s American Depository Shares were traded on Nasdaq Global Market prior to the implementation of the Redomiciliation.  Immediately following the effectiveness of the Redomiciliation, SEAL distributed all of its assets to Sundance Energy Inc., and Sundance Energy Inc. assumed all of the liabilities of SEAL.

Sundance Energy Inc. is an independent oil and gas company engaged in the development, production and exploration of oil, natural gas and natural gas liquids (“NGLs”) primarily targeting the Eagle Ford basin in South Texas.

Basis of Preparation

Prior to the Redomiciliation, SEAL reported its consolidated financial statements in accordance with International Financial Reporting Standards (“IFRS”).  Following the Redomiciliation, the Company retroactively transitioned to accounting principles generally accepted in the United States of America (“GAAP”) and applied GAAP retrospectively for all prior periods presented.  The Company’s consolidated financial statements have been prepared in accordance with GAAP and Securities and Exchange Commission (“SEC”) rules and regulations, and include the accounts of the Company and its consolidated subsidiaries.  All intercompany balances and transactions have been eliminated in consolidation.

64

Going Concern

The accompanying consolidated financial statements are prepared in accordance with GAAP applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.

In March 2020, the prevailing market price for oil prices decreased from an average of approximately $60 per barrel for December 2019 to less than $20 per barrel.  As described in Note 7, the Company is required to meet certain financial and non-financial covenants as a condition to its credit facilities.  Under the Company’s second lien term loan (“Term Loan”), the Company is required to maintain an Asset Coverage Ratio of not less than 1.5 to 1.0, which is calculated as the value of its Total Proved Reserves (PV 9%)  based upon the forward month prices quoted on the NYMEX, adjusted for basis differentials or premiums and transportation costs and to reflect the Company’s commodity hedging agreements then in effect to Total Debt. The value of the Company’s oil and gas reserves, (including “Total Proved Reserves” as described in the Term Loan agreement) is highly sensitive to future commodity prices.  The Company regularly enters into commodity derivative contracts to protect the cash flows associated with the Company’s proved developed producing wells and to provide supplemental liquidity to mitigate decreases in revenue due to reductions in commodity prices.

Based on the Company’s historical experience, in periods of sustained low commodity prices, the prevailing market price for oil and gas services has also decreased, including the types of costs included in the Company’s lease operating expenses, drilling costs, completion costs and costs to equip its wells.  Subsequent to December 31, 2019, the Company renegotiated pricing with a number of its vendors and entered into contractual arrangements with drilling and completion service providers at reduced costs relative to the assumed costs in the Company’s year-end reserve report.  Additionally, the Company has changed its field operating procedures in response to the material drop in oil prices which further reduces its cost structure relative to that assumed in the Company’s year-end reserve report.  The Company continues to work to secure additional costs reductions.

Commodity hedging that the Company currently has in place, combined with cost reductions are expected to reduce the impact of recent commodity price declines.  However, given the recent decline and continued volatility of commodity prices, the Company cannot assert that it is probable that it will comply with the Asset Coverage Ratio and other covenants within the next 12 months following the date of this report.  A breach of any covenant in Company’s credit agreements will result in default under both the Company’s Term Loan and cross default on the Company’s revolving credit facility, after any applicable grace period, which could result in acceleration of the amounts outstanding under the credit facilities by the Company’s lenders.  

Additionally, the Company’s credit facilities contain the requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception.  The issuance of these consolidated financial statements with the accompanying audit opinion constitutes a default under the senior secured revolving credit facility (“Revolving Facility”) and Term Loan.  The Company obtained waivers from its Revolving Facility and Term Loan lenders, executed on May 8, 2020 and May 11, 2020, respectively, to waive the event of default arising from the inclusion of the going concern explanatory paragraph included in the audit report for the year ended December 31, 2019 and other related defaults.  These waivers were effective April 29, 2020, subject to the conditions set forth in the waivers.  As described in Note 15, in consideration for the waiver under our Revolving Facility, the Company agreed to certain limitations on its ability to effect draws under the revolving credit facility until such time as the second quarter 2020 borrowing base redetermination has been completed.  In addition, in consideration for waiver with respect to the Term Loan, the Company agreed to amend certain covenants in the Term Loan, as to be mutually agreed with the Term Loan lenders, within 15 days from the execution date.  The waiver under our Revolving Facility also provides for a right to require corresponding amendments of that facility manner, as requested by the administrative agent in its discretion, within 90 days from the execution date. Failure to enter into such amendments with respect to our Term Loan within 15 days (or a similar amendment with respect to our Revolving Facility on the date the Term Loan is amended) would constitute an event of default under the credit facilities, in which case the amounts outstanding under the credit facilities could be accelerated and become immediately due and payable.  While management believes that it will finalize such amendments within the required time frame, there can be no assurance that management’s efforts will result in any finalizing these amendments or the ultimate terms of any such amendments. 

65

Although the Company has obtained these waivers, there is no guarantee that its lenders will agree to waive events of default or potential events of default in the future.    In the event that some or all of the amounts outstanding under its credit facilities are accelerated and become immediately due and payable, the Company does not have sufficient liquidity to repay such outstanding amounts. These conditions and events raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. 

Management is currently pursuing and evaluating several plans to mitigate the conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern, which include the following:

· Renegotiating pricing with a number of its operating expenditure vendors and has realized lower drilling and completion costs on recent development relative to the costs incurred in 2019 and the assumed costs in the Company’s year-end reserve report.

· Negotiating with its lenders to obtain waivers for potential failures in covenants.

· Pursuing further changes to its cost structure in response to the material drop in oil prices. 

· Pursuing additional costs savings with its vendors and other internal costs, including a reduction in force, which occurred in early May 2020.

There can be no assurance that sufficient liquidity can be obtained to meet the outstanding obligations of the Company, if repayment of its credit facilities is accelerated. As a result, and given the recent declines and continued volatility in commodity prices, the Company has concluded that management’s plans do not alleviate substantial doubt about the Company’s ability to continue as a going concern.

The consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.  Items subject to such estimates and assumptions include (i) oil and natural gas reserves; (ii) impairment tests of long-lived assets; (iii) depreciation, depletion and amortization; (iv) asset retirement obligations; (v) assignment of fair value and allocation of purchase price in connection with business combinations; (vi) income taxes; (vii) accrued liabilities; (viii) valuation of derivative instruments; and (ix) accrued revenue and related receivables.  Although management believes these estimates are reasonable, actual results could differ from these estimates.  Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of lower commodity prices, may have a significant negative impact to the Company’s business, financial condition, results of operations and cash flows.

Cash and Cash Equivalents

Cash and cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less.

66

Accounts Receivable Trade and Other

The Company has letters of credit in place with certain of its purchasers, which the Company could draw upon in the event the purchaser defaults.  Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts.  For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.  The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability.  At December 31, 2019 and 2018, the Company had no allowance for doubtful accounts.  At December 31, 2019 and 2018 the accounts receivable trade and other included the following (in thousands):

	December 31,
	2019		2018
Oil, natural gas and NGL sales	$	18,211	$	16,408
Joint interest owners		260		584
Commodity hedge contract receivables and other		4,342		4,257
Receivable due from buyer (Dimmit County oil and gas properties)		4,207		—
Total accounts receivable trade and other	$	27,020	$	21,249

Concentration of Credit Risk

The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries.  The creditworthiness of customers and other counterparties is subject to continuing review.

As of December 31, 2019, the Company had a receivable from one purchaser, a large midstream company and production purchaser, of $13.2 million that accounted for 73% of total accounts receivable for oil, natural gas and NGL sales.  As of December 31, 2019, the Company has a long-term contract in place with this customer, under which the Company is subject to minimum revenue commitments for gathering, processing, transportation and marketing services totaling $54.3 million through 2022.

As of December 31, 2018, the Company had a receivable due from the same customer of $12.1 million that accounted for 74% of total accounts receivable for oil, natural gas and NGL sales.

The following tables present the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 2019 and 2018:

Year Ended December 31, 2019
Purchaser A	60%
Purchaser B	21%
Year Ended December 31, 2018
Purchaser A	34%
Purchaser B	26%
Purchaser C	23%

The Company owns nearly 100% of the working interest in the majority of the wells that it operates; therefore, joint interest billing receivables, and the related credit risk, is minimal.  Further, if payment is not made by a working interest partner, the Company can withhold future payments of revenue to that working interest partner.

67

Oil and Gas Properties

Proved.  The Company follows the successful efforts method of accounting for its oil and gas properties.  Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a unit-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively.  Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful.  For the years ended December 31, 2019 and 2018, the Company recorded depletion, depreciation and amortization expense related to proved oil and gas properties of $91.4 million and $62.1 million, respectively.

The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable.  The impairment test compares undiscounted future net cash flows of the assets to the assets’ net book value.  If the net book value exceeds future net cash flows, then the cost of the property is written down to fair value.  Fair value for oil and gas properties is generally determined based on discounted future net cash flows.  There was no impairment expense during the years ended December 31, 2019 or 2018.

Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income.  Gains or losses from the disposal of complete units of depreciable property are recognized in results of operations.

For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Interest is capitalized until the asset is ready for service.  

Unproved.  Unproved properties consist of costs to acquire undeveloped leases as well as purchases of unproved reserves.  Capitalized costs of unproved property are transferred to proved property when related proved reserves are determined and depleted on a unit-of-production basis.The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage.  There was no unproved property impairment expense during the years ended December 31, 2019 and 2018.

Exploratory.  Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage, are expensed as incurred.  Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs.  Amounts of seismic costs capitalized are based on only those blocks of data used in determining developmental well locations.  To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.

Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves.  If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense.  Costs incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (i) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.  If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed.

Other Property and Equipment

Other property and equipment consists of office furniture, computer equipment, software and vehicles, which are stated at cost and depreciated using the straight-line method over their estimated useful lives ranging from 3 to 20 years. Leasehold improvements are depreciated over the shorter of the lease term or the estimated useful life of the improvement. Costs that do not extend the useful lives of property and equipment are charged to expense as incurred.  Major replacements, renewals and betterments are capitalized.

68

Other Current Assets

Other current assets consist of oil and equipment inventory and prepaid expenses.  The Company records oil and equipment inventory at the lower of cost or net realizable value.  Prepaid expenses are recorded at cost.

Assets Held for Sale

Oil and gas properties expected to be sold or otherwise disposed of within one year are classified as assets held for sale and included as current assets in the consolidated balance sheets are separately presented in the accompanying consolidated balance sheets at the lower of carrying value or fair value less estimated costs to sell (“FVLCS”).   The Company continued to extract oil and gas from the assets while held for sale, although in accordance with accounting standards, it did not record DD&A for assets classified as held for sale.  

Debt Issuance Costs

Debt issuance costs related to the Company’s Term Loan are included as a deduction from the carrying amount of the credit facility in the consolidated balance sheets and are amortized to interest expense using the effective interest method over the term of the related debt.  Debt issuance costs related to the Revolving Facility are included in other long-term assets and are amortized to interest expense on a straight-line basis over the term of the facility.

Derivative Instruments

The Company enters into derivative contracts, primarily swaps, and costless collars, to manage its exposure to commodity price risk, and follows Financial Accounting Standards Board (“FASB”) ASC Topic 815, Derivatives and Hedging, to account for its derivative financial instruments.  The Company also has interest rate swaps contracts to mitigate its exposure to the floating interest rate charged on its long-term debt.  In addition, the Company historically entered into foreign exchange derivatives to protect cash flows generated during a common stock equity raise in 2018 from changes in currency fluctuations.  Prior to the Company’s redomiciliation, the majority of its common stock issuances were denominated in Australian dollars.  All derivative instruments, other than those that meet the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value.  Gains and losses from changes in the fair value of derivative instruments are recognized immediately in operations. The Company does not apply hedge accounting to any of its outstanding derivative instruments and, as a result, changes in derivative fair values are recognized as an unrealized gain or loss in operations.

Cash flows from derivatives used to manage commodity price risk and interest rate risk are classified in operating activities along with the cash flows of the underlying hedged transactions.  Cash flows from derivatives used to manage foreign currency risk are classified in financing activities.  The Company does not enter into derivative instruments for speculative or trading purposes.  Refer to the Note 10 and Note 11 for further information.

Asset Retirement and Environmental Obligations

Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition as specified by the lease or regulatory agencies.  The Company follows FASB ASC Topic 410, Asset Retirement and Environmental Obligations, to determine its asset retirement obligation amounts by calculating the present value of the estimated future cash outflows associated with its plug and abandonment obligations.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is spud or acquired), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount.  The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a unit-of-production basis over the proved developed reserves of the related asset.  Revisions typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells, and such revisions result in adjustments to the related capitalized asset and corresponding liability.

69

Revenue Recognition

The Company recognizes revenue from the sale of oil, natural gas and NGLs in the period that the performance obligations are satisfied.  The Company’s performance obligations are primarily comprised of the delivery of oil, natural gas or NGLs at a delivery point.  Each barrel of oil, MMBtu of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated.  Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer through delivery of oil, natural gas and NGLs, which differs depending on the contractual terms of each of the Company’s arrangements.

Transfer of control drives the presentation of gathering, processing, transportation, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations, and requires significant judgements. Fees and other deductions incurred prior to control transfer are recorded within the gathering, processing and transportation expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of oil, gas, and NGLs production revenue. The Company has three types of contracts under which oil, gas, and NGLs production revenue is generated, which are summarized below:

1) The Company sells oil production at or near the wellhead and receives an agreed-upon index price from the purchaser, net of basis, quality, and transportation differentials. Under this arrangement, control transfers at or near the wellhead.

2) The Company sells unprocessed natural gas to a midstream processor at the wellhead or inlet of the midstream processing facility. The midstream processor gathers and processes the raw natural gas stream and remits proceeds to the Company from the ultimate sale of the processed NGLs and residue natural gas to third parties. In such arrangements, the midstream processor obtains control of the product at the wellhead or inlet of the facility and is considered the customer. Proceeds received for unprocessed natural gas under these arrangements are reflected as natural gas or NGL revenue and are recorded net of transportation and processing fees incurred by the midstream processor after control has transferred.

3) The Company has certain processing arrangements that include the delivery of unprocessed natural gas to the inlet of a midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind. For the NGLs, control is deemed to have transferred after it has been separated from the residue gas.  The midstream processor remits payment to the Company based on the proceeds it generates from selling the NGLs to other third parties.  The Company recognizes the proceeds as NGL revenue.  For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. The Company recognizes proceeds from the downstream contracts as natural gas revenue.  Under these processing arrangements for both NGL and natural gas, the Company recognizes gathering, transportation, and processing fees incurred prior to control transfer as expense recorded within the gathering, processing and transportation expense line item on the accompanying consolidated statements of operations.

Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received within two months after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, metered sales volumes, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Variances between estimates and the actual amounts received are recorded in the month payment is received, but have not historically been material.  Estimated revenue due to the Company is recorded within accounts receivable trade and other on the accompanying consolidated balance sheets until payment is received. The accounts receivable balance from contracts with customers within the accompanying balance sheet as of December 31, 2019 and 2018 was $18.2 million and $16.4 million, respectively.

70

Stock-Based Compensation

Equity - Settled Compensation

Prior to the effectiveness of the Redomiciliation, SEAL issued restricted share units (“RSUs”) pursuant to its Long Term Incentive Plan (the “Plan”) to motivate management and employees to make decisions benefiting long-term value creation, retain management and employees and reward the achievement of the Company’s long-term goals.  The RSUs are generally settled based on the achievement of certain goals established by the Compensation Committee and approved by the Board. There were three types of RSU awards:

1) Time based vesting: The fair value of time-based RSUs is determined based on the price of the underlying equity on the date of grant and the expense is recognized over the vesting period.

2) Total shareholder return (“TSR”) or absolute total share-holder return (“ATSR”):  Certain RSUs vest based on the achievement of metrics related to the a three‑year ATSR or TSR as compared to a peer group or a market index. A Monte Carlo simulation model to determine the fair value of such RSUs and the expense is recognized over the vesting period. The Monte Carlo model was used to determine based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The expected volatility used in the model is based on the historical volatility commensurate with the length of the performance period of the award. The risk-free rate used in the model is based on published interest rates relevant to the term of the RSU award. 

3) Performance targets: Certain RSUs vest based on the achievement of Adjusted EBITDAX per debt adjusted share or average daily production volume per debt adjusted share metrics during 2019 and 2020. At the end of each reporting period, the amount of expense recorded is adjusted based on the number of shares it ultimately expects to vest based on the comparison of internal forecasts to the performance conditions. 

The fair value of the equity to which employees become entitled is measured at grant date and recognized as an expense over the vesting period with a corresponding increase in equity.  The Company accounts for forfeitures of RSUs as they occur.  See Note 13 for further discussion of the RSUs.

Defined Contribution Plan

The Company has a defined contribution retirement plan for all employees.  The plan is funded by employee contributions and discretionary Company contributions.  The Company’s contributions for the years ended December 31, 2019 and 2018 were $0.6 million and $0.3 million, respectively.

Income Taxes

Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes.  Deferred income taxes are accounted for using the liability method.  Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s consolidated financial statements.  The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized.  The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense (benefit).

71

Earnings (Loss) Per Share

Basic earnings (loss) per common share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding during each period.  Diluted earnings per common share is calculated by dividing net income by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities.  Potentially dilutive securities for the diluted earnings per share calculations consist of outstanding restricted share units which have been issued to employees, all using the treasury stock method.  When a loss from continuing operations exists, all dilutive securities and potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.

Industry Segment and Geographic Information

The Company’s strategic focus is the exploration, development and production of large, repeatable onshore resource plays in North America. All of the Company’s operations and assets are located in the Eagle Ford area of south Texas.  Management has determined, based upon the reports the Chief Operating Decision Maker (the Company’s Chief Executive Officer) reviews and uses to make strategic decisions, that the Company has one reportable segment being oil and natural gas development and production in North America.

Foreign Currency Transaction Gains and Losses

The U.S. dollar is the functional currency for the Company.  The Company’s Australian subsidiaries have an Australian dollar functional currency, and asset and liability accounts denominated in foreign currencies are remeasured to their U.S. dollar equivalent at the exchange rate in effect at the end of each reporting period. Foreign currency gains and losses arising from translation are reflected in accumulated other comprehensive (loss) in the consolidated balance sheets.

Business Combinations

A business combination is a transaction in which an acquirer obtains control of one or more businesses. The Company accounts for business combinations using the acquisition method of accounting, under which the cost of the acquisition is allocated to assets acquired and liabilities assumed based upon their respective fair values as of the acquisition date. Costs directly attributable to the business combination are expensed as incurred, except those directly and incrementally attributable to equity issuance.

Recently Issued and Adopted Accounting Standards

In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (“ASU 2016-02”). The FASB subsequently issued various ASUs which provided additional implementation guidance, and these ASUs collectively make up FASB ASC Topic 842 – Leases (“ASC 842”). The objective of ASC 842 is to increase transparency and comparability among organizations, by recognizing lease liabilities and right-of-use assets on the balance sheet at the date of initial application and disclosing key information about leasing arrangements. The Company adopted ASC 842 using the modified retrospective method effective January 1, 2019. Accordingly, the 2019 financial statements are not comparable with respect to leases in effect for all periods prior to January 1, 2019. Refer to Note 6 for further information on the Company’s implementation of this standard.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments, which provides a model, known as the current expected credit loss model (“CECL model”), to estimate the expected lifetime credit loss on financial assets, including trade and other receivables.  The Company adopted the ASU effective January 1, 2020, and it did not have a material impact on the Company’s consolidated financial statements as the Company does not have a history of material credit losses. 

72

NOTE 2 — OIL AND GAS PROPERTIES

Net capitalized costs related to the Company’s oil and gas producing activities at December 31, 2019 and 2018 are as follows (in thousands):

	December 31,
	2019		2018
Oil and gas properties, successful efforts method:
Unproved	$	25,037	$	48,049
Proved		1,090,774		925,551
Work in progress		7,097		12,948
		1,122,908		986,548
Accumulated depletion, depreciation and amortization		(379,961)		(293,598)
Oil and gas properties, net	$	742,947	$	692,950

Capitalized Interest

For the years ended December 31, 2019 and 2018, the Company capitalized interest of $2.3 million and $1.5 million, respectively.

NOTE 3 — ACQUISITIONS AND DISPOSITIONS

2019

The Company did not have any acquisitions during the year ended December 31, 2019.

On October 1, 2019, the Company closed on the sale of its assets located in Dimmit County, Texas, for $21.5 million, of which $4.2 million was a receivable due to Sundance as of December 31, 2019.  The disposed assets included 19 gross producing wells located on approximately 6,100 net acres.  Production from these wells approximated 1,200 Boe/d during 2019 prior to the disposition.  This disposal group was classified as held for sale prior to its sale.  See Note 4 for further discussion.

2018

On April 23, 2018, Sundance Energy Inc. acquired from Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC (collectively the “Sellers”) approximately 21,900 net acres targeting the Eagle Ford Formation in McMullen, Live Oak, Atascosa and La Salle counties, Texas, for cash of $215.8 million, after the effective date to closing date adjustments of $5.8 million.  The acquisition included working interests in 132 gross producing wells, and furthered the Company’s strategy of aggregating assets in the Eagle Ford.

The following table reflects the fair value of the assets acquired and the liabilities assumed (in thousands):

Assets Acquired:	December 31, 2018
Oil and gas properties
Proved	$	173,750
Unproved		43,642
Liabilities Assumed:
Trade and other payables		(80)
Asset retirement obligation		(1,522)
Net assets acquired	$	215,790

73

For the period from April 23, 2018 through December 31, 2018 the acquired properties generated the following revenues and direct operating expenses, including depletion, depreciation and amortization expense:

Revenues	$	64,507
Direct operating expenses (1)		(45,194)
Income from operations	$	19,313

(1) Direct operating expenses include lease operating and workover expense, gathering, processing and transportation expense, production taxes and depreciation, depletion and amortization expense.

Included in general and administrative expenses in the consolidated statement of operations are transaction costs, including legal, accounting, valuation and other fees incurred to complete the acquisition, totaling $13.7 million, of which $12.4 million and $1.3 million were incurred during the years ended December 31, 2018 and 2017, respectively.

Pro Forma Information (unaudited)

For the years ended December 31, 2018, the pro forma financial information represents the combined results for the Company and the properties acquired as if the acquisition had occurred January 1, 2018.  For the year ended December 31, 2018 the pro forma revenue and loss before income taxes was $174.7 million and $(7.7) million, respectively.  This pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations.

There were no material dispositions in 2018.

NOTE 4 — ASSETS HELD FOR SALE

The consolidated balance sheet includes assets and liabilities related to assets held for sale, comprised of the following as of December 31, 2018 (in thousands):

Assets held for sale:	December 31, 2018
Oil and gas properties - Dimmit County, Texas	$	23,471
Liabilities related to assets held for sale:
Asset retirement obligations		(193)
Net assets held for sale	$	23,278

The Dimmit County assets were divested in October 2019.  See Note 3.  As of December 31, 2019, the Company’s balance sheet did not include assets or liabilities related to assets held for sale.

Impairment of Assets Held for Sale

For the years ended December 31, 2019 and 2018, the Company recorded impairment expense of $10.0 million and $43.0 million, respectively, related to assets held for sale as discussed in Note 11. 

74

NOTE 5 — ACCRUED LIABILITIES

The following is a summary of accrued liabilities as of December 31, 2019 and 2018 (in thousands):

	December 31,
	2019		2018
Oil and natural gas properties:
Capital expenditures	$	4,168	$	12,879
Re-fracture liability		764		900
Lease operating and workover expenses and other		7,393		6,586
Accrued interest payable		6,885		458
General and administrative expense		6,894		4,462
Finance lease liabilities		305		—
Total accrued liabilities	$	26,409	$	25,285

The Company entered into an agreement with Schlumberger Limited (“Schlumberger”) to re‐fracture five Eagle Ford wells in 2016. Under the terms of the agreement, Schlumberger will be paid for the services, plus a premium (if applicable), from the cash flow resulting from the incremental production generated by the re‐fractured wells above the forecasted base production prior to the re‐fracture work. The term of the agreement is five years and expires in 2021. The estimate of the remaining payout amount requires judgements regarding future production, pricing, operating costs and discount rates.  The estimate of the related current liability is included above as the re-fracture liability.  In addition, the Company recorded a long term liability related to the refracture services of $0.7 million and $1.1 million as of December 31, 2019 and 2018, respectively, which is included in other long-term liabilities on the consolidated balance sheets.

NOTE 6 – LEASES

Lease Accounting

Adoption and transition

Effective January 1, 2019, the Company began accounting for leases in accordance with ASC 842, which requires lessees to recognize lease liabilities and right-of-use assets on the balance sheet for contracts that provide lessees with the right to control the use of identified assets for periods of greater than 12 months. Prior to January 1, 2019, the Company accounted for leases in accordance with ASC Topic 840, Leases (“ASC 840”), under which operating leases were not recorded on the balance sheet. Adoption of ASC 842 resulted in the recognition of lease liabilities of $11.5 million and right-of-use assets (“ROU”) of $11.4 million related to the Company’s operating leases on its consolidated balance sheet, and did not result in the Company recognizing a cumulative-effect adjustment to accumulated deficit, at January 1, 2019.

In connection with the adoption of ASC 842 effective January 1, 2019, the Company applied the following transition practical expedients:

· A package of practical expedients which allowed the Company, for its arrangements in existence prior to the January 1, 2019 application date, to not reassess (1) whether an arrangement was or contained a lease at its commencement date, (2) its previous conclusions regarding classification of a lease as an operating or finance lease at its commencement date, and (3) initial direct costs as recorded;

· A practical expedient which allowed the Company, for its arrangements in existence prior to the January 1, 2019 application date, to not reassess its accounting for land easement arrangements not previously accounted for as leases; and

· A practical expedient to use hindsight in assessing the lease term and impairment.

75

The scope of ASC 842 excludes leases to explore for or use minerals, oil, natural gas, and similar non-regenerative resources.  However, leases of equipment used to explore for natural resources (for example, drilling equipment) are not part of this scope exception.

Accounting Policies for Leases

The Company has made the following policy elections related to accounting for its leases under ASC 842:

· Exemption from recognition and measurement provisions for short-term leases (a lease that at commencement has a lease term of 12 months or less) in all classes of assets;

· Election to not separate nonlease components, such as amounts for related taxes and common area maintenance charges, in certain classes of assets, including its office facilities and equipment, amine and compression equipment, land right-of-way and surface use arrangements, and employee lodging; and

· Election to apply general provisions and discount rates to certain portfolios of leases with reasonably similar characteristics.

The Company determines whether an arrangement is, or contains, a lease based on the substance of the arrangement at its inception. The Company applies judgment in analyzing the arrangement to determine whether it conveys an enforceable right to control the use of an identified asset or assets for a period of time in exchange for consideration. For the Company as lessee, this assessment includes consideration of whether it has the right to obtain substantially all of the economic benefits from the use of the identified asset, together with the right to direct the use of the asset, and whether there is an enforceable obligation for it to exchange consideration for those rights. 

The Company assesses the classification of its lease arrangements upon commencement of the lease by determining whether the lease contains any one of the following criteria for classification as a finance lease, and if it does not, it is classified as an operating lease:

· Transfer of ownership of the underlying asset to the Company by the end of the lease term;

· An option to purchase the underlying asset that the Company is reasonably certain to exercise;

· A lease term that is for the major part of the remaining economic life of the underlying asset;

· A present value of the sum of lease payments and lessee’s guaranteed residual value equal to or in excess of substantially all of the fair value of the underlying asset; or

· An underlying asset that is of such a specialized nature that it is expected to have no alternative use to the lessor at the end of the lease term.

Operating lease cost is recognized on a straight-line basis over the lease term. Finance lease cost is recognized based on the effective interest method for the lease liability and straight-line amortization of the ROU asset, resulting in more cost being recognized in earlier periods. All payments for short-term leases are recognized on a straight-line basis over the lease term.  Short-term lease cost excludes amounts for rental of equipment for periods less than thirty days in duration. 

Leasing Arrangements and Significant Assumptions and Judgments

The Company enters into leases as lessee to conduct its normal operations. The Company has operating leases primarily for its use of compression equipment, a drilling rig, land right of way and surface use arrangements, office facilities, and other production equipment. The Company has finance leases for its use of field vehicles and office equipment. Most of the Company’s leasing arrangements include extension and termination options, including evergreen provisions, all of which provide the Company flexibility in retaining the underlying facilities and equipment, as well as some protection from future price variability. The Company recognizes options to extend or terminate its leases as part of its assessment of the lease term, when it is reasonably certain to exercise the option. The Company’s leases are typically not significant enough individually or in the aggregate to impose or affect restrictions in its borrowing capacity or financial covenants.

76

Some of the Company’s contracts have pricing that is variable within a range based on throughput, others have a set rate increase at predetermined intervals, and others are silent as to future increases or have a rate that is undefined for the variable components. The Company’s leases do not have future variable payments related to indices. For contracts with throughput provisions subject to a range, future payments have been included in the calculation of the lease liabilities at the contract minimum rate.  Future payment increases for leases with set rate increases have been incorporated into the calculation of the lease liabilities, including the escalations. Future variable payments such as for movement or demobilization of the underlying leased asset have typically been excluded from the calculation of the lease liabilities unless they are determinable, and are expensed as incurred.

The Company has applied judgment to determine the lease term for some of its lease contracts which include renewal or termination options. Certain of the Company’s leases include an “evergreen” provision that allows the contract term to continue on a month-to-month or year-to-year basis following expiration of the initial term included in the contract. For leases with an evergreen provision that renewed during the year ended December 31, 2019, the term of the lease was re-assessed by the Company and determined to be the non-cancelable period in the contract, plus the period beyond that cancellation period that the Company believes it is reasonably certain it will need the equipment for operational purposes. This re-assessment affects the value of ROU assets and lease liabilities recognized in the balance sheets at December 31, 2019. 

The Company has also applied judgment in determining the discount rate to apply to its lease calculations. The lease liabilities and corresponding ROU assets have been discounted using the Company’s incremental borrowing rate, which has been derived from rates expected to be available under the Company’s Revolving Credit Facility, using available borrowing base capacity and forward curve information over periods comparable to the term of each lease.

Lease Recognition and Measurement

The ROU asset is initially measured to be equal to the lease liability and adjusted for any lease incentives received and initial direct costs and lease prepayments incurred. Subsequently, the ROU asset is measured at cost less any accumulated amortization and adjusted for certain remeasurements of the lease liability or impairments of the ROU asset. 

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date. The lease liability is subsequently increased by the interest cost on the lease liability and decreased by lease payments made. It is re-measured when there is a change in future lease payments arising from a change in the Company’s plans with respect to exercise of options included in terms of the lease, or a modification to the lease arrangement. 

In the event that there is a modification to a lease arrangement, a determination of whether the modification results in a separate lease arrangement being recognized is made. The Company also considers the impact of the modification on classification of the lease.  If the modification results in the recognition of a separate lease arrangement, due to an increase in scope of a lease for example through additional underlying leased assets being added and a commensurate increase in lease payments, the Company measures the new arrangement separately, accounting for it as a new lease. If the modification does not result in a separate lease arrangement, for example due to an extension of the lease term that does not exceed the life of the underlying asset, the Company re-measures the remaining lease liability from the effective date of the modification using the re-determined lease term, remaining future lease payments and applicable discount rate. An adjustment is made to the carrying amount of the associated right-of-use asset for the re-measurement of the corresponding lease liability. If there has been a partial or full termination of a lease, the Company recognizes any resulting gain or loss in the consolidated statement of operations and other comprehensive income (loss).

77

Lease Supplemental Disclosures

The following tables present the carrying amounts and classifications of the Company’s ROU assets (net of accumulated amortization) and estimated lease liabilities as of December 31, 2019 (in thousands):

Right-of-use assets	Balance Sheet Location	December 31, 2019
Operating lease right-of-use assets	Operating lease right-of-use assets	$	17,331
Finance lease right-of-use assets	Other property and equipment, net of accumulated depreciation		747
Total right-of-use assets		$	18,078
Lease liabilities	Balance Sheet Location	December 31, 2019
Operating lease liabilities - current	Operating lease liabilities - current	$	7,720
Operating lease liabilities - non-current	Operating lease liabilities - non-current		9,611
Finance lease liabilities - current	Accrued expenses		305
Finance lease liabilities - non-current	Other long-term liabilities		429
Total lease liabilities		$	18,065

Information regarding the Company’s lease terms and discount rates as of December 31, 2019 are as follows:

Weighted Average Remaining Lease Term (years)
Operating Leases	5.22
Finance Leases	2.58
Weighted Average Discount Rate
Operating Leases	4.73%
Finance Leases	4.69%

The following summarizes total lease cost, which includes amounts recognized on the consolidated statement of operations and other comprehensive income (loss) and amounts capitalized related to the Company’s leases (in thousands):

	Year ended
	December 31, 2019
Operating lease cost (1)	$	11,729
Finance lease cost:
Amortization of right-of-use assets	$	187
Interest on lease liabilities		20
Total finance lease cost	$	207
Short-term lease cost	$	1,065
Variable lease cost	$	1,395
Sublease income	$	150

(1) Operating lease cost of $6.3 million related to the Company’s drilling rig was capitalized to oil and gas properties on the consolidated balance sheet and will be depleted in accordance with the Company’s policies.

78

The following summarizes supplemental cash flow information related to the Company’s leases (in thousands):

	December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	5,271
Operating cash flows from finance leases	$	20
Investing cash flows from operating leases	$	6,308
Financing cash flows from finance leases	$	187
Supplemental non-cash information on lease liabilities arising from right of use assets
Operating lease liability additions	$	17,358
Finance lease liability additions	$	640

The Company’s lease obligations as of December 31, 2019 will mature as follows (in thousands):

Year Ending December 31,	Operating Leases		Finance Leases
2020	$	7,848	$	312
2021		4,061		305
2022		2,819		150
2023		2,192		12
2024		845		-
Thereafter		1,481		-
Total lease payments	$	19,246	$	779
Less: Interest		(1,915)		(45)
Total discounted lease payments	$	17,331	$	734

As of December 31, 2018, future minimum contractual payments for long-term leases under the scope of ASC 840 were as follows (in thousands):

Year Ending December 31,	Drilling  Rig		Operating Leases		Capital Leases
2019	$	4,106	$	2,087	$	97
2020		-		1,376		98
2021		-		602		90
2022		-		141		15
2023		-		83		12
Thereafter		-		964		-
Total lease payments	$	4,106	$	5,253	$	312
Less interest						(26)
Total discounted lease payments					$	286

Capital leases at December 31, 2018 included $0.2 million related to field vehicles and $0.1 million related to office equipment.  Rent expense for the year ended December 31, 2018 was $3.6 million.

79

NOTE 7 — LONG-TERM DEBT

The following is a summary of long-term debt as of December 31, 2019 and 2018 (in thousands):

		December 31,
		2019		2018
Revolving Facility	$	115,000	$	65,000
Term Loan		250,000		250,000
Total long-term debt		365,000		315,000
Deferred financing fees, net of accumulated amortization		(11,510)		(14,196)
Total credit facilities, net of deferred financing fees	$	353,490	$	300,804

On April 23, 2018, contemporaneous with the closing of its Eagle Ford acquisition, the Company entered into the $250.0 million syndicated Term Loan with Morgan Stanley Energy Capital, as administrative agent, and the syndicated Revolving Facility with Natixis, New York Branch, as administrative agent, with initial availability of $87.5 million ($250.0 million face).  The proceeds of the refinanced debt facilities were used to retire the Company’s previous credit facilities of $192.0 million, repay the Company’s production prepayment of $11.8 million and pay deferred financing fees on the Term Loan and Revolving Facility of $16.7 million, with the balance being used for the Company’s working capital needs at the time of closing the acquisition.

The Revolving Facility and Term Loan are secured by certain of the Company’s oil and gas properties.  The Revolving Facility is subject to a borrowing base, which is redetermined at least semi-annually; the next of such redeterminations will occur in the second quarter of 2020.  The Revolving Facility will mature in October 2022, and the Term Loan will mature in April 2023.  If, upon any downward adjustment of the borrowing base, the outstanding borrowings are in excess of the revised borrowing base, the Company may have to repay its indebtedness in excess of the borrowing base immediately, or in five monthly installments.

As of December 31, 2019, the Company had letters of credit of $16.4 million outstanding on the Revolving Facility, and $38.6 million of available borrowing capacity.   

Interest on the Revolving Facility accrues at a rate equal to LIBOR, plus a margin, depending on the level of funds borrowed. As of December 31, 2019, the margin ranged from 2.25% to 3.25% (2.5% to 3.5% prior to May 2019).  Interest on the Term Loan accrues at a rate equal to the greater of (i) LIBOR plus 8% or (ii) 9%.  As of December 31, 2019, the stated interest rates on the Revolving Facility and the Term Loan were 4.75%, and 10.1%, respectively.  As of December 31, 2018, the stated interest rates on the Revolving Facility and the Term Loan were 5.40% and 10.81%, respectively.

Subsequent to December 31, 2019, the Company entered into the fourth amendment to the Revolving Facility, which increased the borrowing base to $210 million (with elected borrowing commitments of $190 million), increased the maximum credit amount from $250 million to $500 million, revised the Leverage Ratio and Interest Coverage Ratio covenant (as reflected below) and appointed Toronto Dominion (Texas) LLC, as the administrative agent.  The amendment increased the Company’s undrawn borrowing capacity to $58.6 million as of the date of this report.   The Company is currently restricted in its ability to make draws until the finalization of its second quarter borrowing base redetermination.  Refer to Note 15 for additional information. 

Under the Revolving Facility, the Company is required to maintain the following financial ratios:

· a minimum Current Ratio, consisting of consolidated current assets (as defined in the Revolving Facility) including undrawn borrowing capacity to consolidated current liabilities (as defined in the Revolving Facility), of not less than 1.0 to 1.0 as of the last day of any fiscal quarter;

· a maximum Leverage Ratio, consisting of consolidated Total Debt to adjusted consolidated EBITDAX (as defined in the Revolving Facility), of not greater than 3.5 to 1.0 as of the last day of any fiscal quarter; and

· a minimum Interest Coverage Ratio, consisting of EBITDAX to Consolidated Interest Expense (as defined in the Revolving Facility), of not less than 1.5 to 1.0 as of the last day of any fiscal quarter (for such time as there a similar covenant under the Company’s or SEI’s subordinated indebtedness).

80

Under the Term Loan, the Company is required to maintain the following financial ratios:

· a minimum Interest Coverage Ratio, consisting of EBITDAX to Consolidated Interest Expense (as defined in the Term Loan), of not less than 1.5 to 1.0 as of the last day of any fiscal quarter (for such time as there a similar covenant under the Company’s or SEI’s subordinated indebtedness); and

· An Asset Coverage Ratio, consisting of Total Proved PV9% to Total Debt (as defined in the Term Loan agreement), of not less than 1.50 to 1.0.

As of December 31, 2019 and 2018, the Company was in compliance with all restrictive financial and other covenants under the Revolving Facility and Term Loan.    The Company’s credit facilities contain the requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception.  The issuance of these consolidated financial statements with the accompanying audit opinion constitutes a default under the Revolving Facility and Term Loan agreements.  The Company obtained waivers from its Revolving Facility and Term Loan lenders on May 8, 2020 and May 11, 2020, respectively,  to waive the event of default arising from the inclusion of the going concern explanatory paragraph included in the audit report for the year ended December 31, 2019 and with respect to the defaults arising from a failure to deliver audited consolidated financial statements for the year ended December 31, 2019 and related reports and certificates by the applicable deadline.  These waivers were effective as of April 29, 2020, subject to the conditions set forth in the waivers.    Refer to Note 1 and Note 15 for additional information. 

NOTE 8 — ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration in accordance with applicable lease terms, local, state and federal laws. The following table provides a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2019 and 2018 (in thousands):

	December 31,
	2019		2018
Balance, beginning of year	$	3,489	$	1,549
Additional liability incurred		145		195
Obligations settled		(85)		(29)
Obligations on assets acquired		—		1,522
Obligations on assets sold		(232)		—
Accretion expense		336		252
Balance, end of year	$	3,653	$	3,489
Liabilities related to assets held for sale	$	—	$	193
Long-term		3,653		3,296
	$	3,653	$	3,489

NOTE 9 — INCOME TAXES

Income taxes are computed using the asset and liability method.  Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits, and tax credit carryforwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.

81

The income tax provision is comprised of the following (in thousands):

	Year Ended December 31,
	2019		2018
Current income tax expense - Federal	$	—	$	2,301
Deferred income tax expense (benefit)
Federal		(8,281)		(5,555)
State		11		318
Foreign		(503)		(2,929)
Total deferred income tax expense (benefit)		(8,773)		(8,166)
Valuation Allowance
Income tax provision (benefit)		4,255		19,822
Total income tax expense (benefit)	$	(4,518)	$	13,957

A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands):

	Year Ended December 31,
		2019		2018
Income tax benefit at the federal statutory rate	$	(9,263)	$	(1,885)
State income taxes - net of federal income tax benefits		10		290
Stock-based compensation		114		839
Nondeductible expenses		519		1,055
Change in valuation allowance		4,255		19,822
Foreign tax rates		(166)		(877)
Australian tax losses on U.S. Restructuring		—		(3,284)
Deemed interest payment due to U.S. restructuring		—		(4,350)
U.S. withholding tax net of foreign tax credit		—		2,301
Other		13		46
Total income tax expense (benefit)	$	(4,518)	$	13,957

In 2018 in connection with the equity raise to fund the Company’s Eagle Ford acquisition, the Company had a greater than 50% ownership change pursuant to Section 382 of the Internal Revenue Code.  As a result of the ownership change, the Company’s ability to use pre-change net operating losses (“NOLs”) and credits against post-change taxable income is limited to an annual amount plus any built-in gains recognized within five years of the ownership change.  The Company’s use of pre-change losses of $248.5 million will be limited to approximately $42.3 million.  Accordingly, the Company recorded a valuation allowance to reduce its deferred tax assets.

As of December 31, 2019, the Company had U.S. federal NOL carryforwards of $292.4 million.   The Company also has various state NOL carryforwards. The determination of the state NOL carryforwards is dependent upon apportionment percentages and state laws that can change from year to year and that can thereby impact the amount of such carryforwards.  If unutilized, the majority of the federal NOLs will expire between 2033 and 2037 and the state NOLs will expire between 2021 and 2037.  Any federal NOLs generated in 2018 or subsequent do not expire.  The Company also has Australian NOLs of $26.2 million that do not expire.

82

The Company completed a restructuring of its U.S. subsidiaries during the year ended December 31, 2018.  The restructuring resulted in recognized tax losses under Australian tax law of $15.6 million creating loss carryover available to offset future income.  As the Company does not believe it is more likely than not that these carryovers will be utilized in the future, it has recorded a valuation allowance against the Australian deferred tax assets. Additionally, the restructuring resulted in a deemed payment of interest from the U.S. subsidiaries to the Company of $20.7 million which required the Company to pay a $2.3 million withholding tax. 

In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized.  Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required.  Such evidence includes the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making this assessment.  Judgment is required in considering the relative weight of negative and positive evidence.  The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits, and other deferred tax assets will be utilized prior to their expiration.  As a result, it may be determined that a deferred tax asset valuation allowance should be established or released.  Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense.

The tax effects of temporary differences that give rise to significant components of the deferred income tax assets and deferred tax liabilities at each of the period ends is presented in the following table (in thousands):

	December 31,
		2019		2018
Deferred tax assets:
Net operating loss carryforward	$	76,624	$	70,560
Business interest carryforward		10,474		7,054
Stock-based compensation		93		102
Statutory depletion carryforward		2,927		2,977
Unrealized (gain) loss on commodity derivative		1,147		(6,453)
Lease obligations		3,735		—
Property, plant and equipment		82		(122)
Other assets		524		1,688
Total deferred tax assets		95,606		75,806
Valuation allowance		(64,898)		(60,643)
Deferred tax assets, net		30,708		15,163
Deferred tax liabilities:
Basis of oil and gas properties		(33,950)		(26,819)
Lease assets		(3,896)		—
Total deferred tax liabilities		(37,846)		(26,819)
Deferred tax liabilities, net	$	(7,138)	$	(11,656)

As of December 31, 2019, the Company had no unrecognized tax benefits.  The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position.  Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards, and would not result in significant interest expense or penalties.  The Company’s federal and state tax returns filed since December 31, 2016 and December 31, 2015, respectively, remain subject to examination by tax authorities.  The Company's Australian tax returns filed since December 31, 2015 also remain subject to examination.

83

On March 27, 2020, President Trump signed into U.S. federal law the CARES Act, which is aimed at providing emergency assistance and health care for individuals, families, and businesses affected by the COVID-19 pandemic and generally supporting the U.S. economy. 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  (“AMT”) refunds, modifications to the net interest deduction limitations and technical corrections to tax depreciation methods for qualified improvement property. In particular, the CARES Act, (i) eliminates the 80% of taxable income limitation by allowing corporate entities to fully utilize NOLs to offset taxable income in 2018, 2019 or 2020, (ii) allows for NOLs generated in 2018, 2019, or 2020 to be carried back 5 years, (iii) increases the net interest expense deduction limit to 50% of adjusted taxable income from 30% for tax years beginning January 1, 2019 and 2020, and (iv) allows taxpayers with AMT credits to claim a refund in 2019 for the entire amount of the credit instead of recovering the credit through refunds over a period of years, as originally enacted by the Tax Cuts and Jobs Act in 2017.  The Company is in the process of analyzing the different aspects of the CARES Act to quantify the impact of these provisions.

NOTE 10 — DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Derivatives

The Company uses derivative instruments to mitigate volatility in commodity prices.  While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future cash flow from favorable price changes.  The Company’s policy is to hedge at least 50% of its the reasonably projected oil & gas production from the Proved Reserves classified as “Developed Producing Reserves” for a rolling 36 month period, but not more than 85% of the reasonably projected production from the Proved Reserves for a rolling 24 months and not more than 75% of the reasonably projected production from the Proved Reserves for months 25-60, as required by its Revolving Facility agreement.  

As of December 31, 2019, the Company has primarily entered into oil and gas swaps and collars and oil basis swaps. For collars, the Company receives the difference between the published index price and a floor price if the index price is below the floor price, or pays the difference between the ceiling price and the index price if the index price is above the ceiling price.  No amounts are paid or received if the index price is between the floor and the ceiling prices. By using a collar, the minimum and maximum prices on the underlying production are fixed. The oil basis swaps are settled based on the difference between a published index price minus a fixed differential and the applicable local index price under which the underlying production is sold. By using a basis swap, the Company has fixed the differential between the published index price and certain of our physical pricing points. The basis swaps fix the price differential between the WTI NYMEX (Cushing Oklahoma) price and the WTI Houston Argus price.

A summary of the Company’s commodity derivative positions as of December 31, 2019 follows:

Oil Swaps - WTI (1)
Year	Volumes (Bbl)		Weighted Average Price per Bbl
2020	1,074,000	$	57.17
2021	216,000	$	54.84

Oil Collars - WTI
Year	Volumes (Bbl)		Weighted Average Price per Bbl - Floor		Weighted Average Price per Bbl - Ceiling
2020	672,000	$	54.47	$	61.82
2021	216,000	$	45.00	$	65.00
2022	228,000	$	40.00	$	66.00
2023	160,000	$	40.00	$	63.10

84

Oil Three-Way Collars - WTI
Year	Volumes (Bbl)		Weighted Average Price per Bbl - Floor Sold		Weighted Average Price per Bbl - Floor Purchased		Weighted Average Price per Bbl - Ceiling
2020	300,000	$	35.00	$	50.00	$	59.60
2021	300,000	$	35.00	$	50.00	$	57.50
2022	300,000	$	35.00	$	50.00	$	56.90

Propane Calls Sold - OPIS Propane Mont Belvieu - TET(2)
Year	Volumes (Bbl)		Weighted Average Price per Bbl
2020	271,000	$	0.70

Oil Basis Swaps - WTI-HOU (3)
Year	Volumes (Bbl)		Weighted Average Differential per Bbl
2020	720,000	$	2.98
2021	120,000	$	2.53

Natural Gas Swaps	Price Swaps - HH(4)			Price Swaps - HSC(5)
Year	Volumes (MMBtu)		Weighted Average Price per MMBtu	Volumes (MMBtu)		Weighted Average Price per MMBtu
2020	1,890,000	$	2.70	120,000	$	2.53
2021	1,050,000	$	2.69	240,000	$	2.50
2022	720,000	$	2.76	360,000	$	2.54
2023				240,000	$	2.64

Natural Gas Collars  - HH
Year	Volumes (MMBtu)		Weighted Average Price per MMBtu - Floor		Weighted Average Price per MMBtu - Ceiling
2020	120,000	$	2.50	$	2.95

HSC
Year	Volumes (MMBtu)		Weighted Average Price per MMBtu - Floor		Weighted Average Price per MMBtu - Ceiling
2020	96,000	$	2.60	$	2.91

Subsequent to December 31, 2019, the Company entered into the following commodity derivative positions:

Oil Swaps	Price Swaps - WTI
Year	Volumes (Bbl)		Weighted Average Price per Bbl
2020	720,000	$	49.39
2021	1,980,000	$	48.38

85

Natural Gas Swaps	Price Swaps - HH
Year	Volumes (MMBtu)		Weighted Average Price per MMBtu
2021	600,000	$	2.67

The following is a list of index prices:

(1) WTI crude oil as quoted on NYMEX.

(2)Mont Belvieu – Texas Eastern Transmission (“TET”) propane as quoted by Oil Price Information Service (“OPIS”). 

(3)WTI Houston Argus (“WTI-HOU”) crude oil as quoted by Argus US Pipeline.

(4)Henry Hub (“HH”) natural gas as quoted on the NYMEX.

(5)Houston Ship Channel (“HSC”) natural gas as quoted in Platt’s Inside FERC.

Interest Rate Derivatives

A summary of the Company’s interest rate swaps as of December 31, 2019 follows (notional amount in thousands):

							Portion of
	Term						Term Loan
Effective Date		Termination Date	Notional Amount		Fixed Rate (1)		Face Amount
July 11, 2019		July 11, 2020	$	187,500	3.016	%	75	%
July 11, 2020		July 11, 2021	$	125,000	3.072	%	50	%
July 11, 2021		July 11, 2022	$	125,000	3.061	%	50	%
July 13, 2022		May 23, 2023	$	125,000	3.042	%	50	%

(1) Each contract has a 1% floor, consistent with the structure of the Term Loan. 

86

Offsetting of Derivative Assets and Liabilities. 

The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract.  The following tables summarize the location and fair value amounts of all the Company’s derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets (in thousands):

		December 31, 2019
		Gross		Gross		Net Recognized
		Recognized		Amounts		Fair Value
Not Designated as ASC 815 Hedges	Balance Sheet Classification	Assets/Liabilities		Offset		Assets/Liabilities
DERIVATIVE ASSETS:
Current:
Derivative financial instruments — commodity contracts	Derivative assets	$	2,863	$	(1,648)	$	1,215
Derivative financial instruments — interest rate swaps	Derivative assets		8		(8)		—
Long-term:
Derivative financial instruments — commodity contracts	Derivative assets		2,637		(1,759)		878
Derivative financial instruments — interest rate swaps	Derivative assets		377		(377)		—
Total derivative assets			5,885				2,093
DERIVATIVE LIABILITIES:
Current:
Derivative financial instruments — commodity contracts	Derivative liabilities		3,946		(1,648)		2,298
Derivative financial instruments — interest rate swaps	Derivative liabilities		2,104		(8)		2,096
Total current derivative liabilities			6,050				4,394
Long-term:
Derivative financial instruments — commodity contracts	Derivative liabilities		1,761		(1,759)		2
Derivative financial instruments — interest rate swaps	Derivative liabilities		4,044		(377)		3,667
Total long-term derivative liabilities			5,805				3,669
Total derivative liabilities			11,855				8,063
		$	(5,970)			$	(5,970)

87

		December 31, 2018
		Gross		Gross		Net Recognized
		Recognized		Amounts		Fair Value
Not Designated as ASC 815 Hedges	Balance Sheet Classification	Assets/Liabilities		Offset		Assets/Liabilities
DERIVATIVE ASSETS:
Current:
Derivative financial instruments — commodity contracts	Derivative assets	$	24,877	$	(562)	$	24,315
Derivative financial instruments — interest rate swaps	Derivative assets		5,081		(5,081)		—
Long-term:
Derivative financial instruments — commodity contracts	Derivative assets		8,403		(400)		8,003
Derivative financial instruments — interest rate swaps	Derivative assets		11,142		(11,142)		—
Total derivative assets			49,503				32,318
DERIVATIVE LIABILITIES:
Current:
Derivative financial instruments — commodity contracts	Derivative liabilities		787		(562)		225
Derivative financial instruments — interest rate swaps	Derivative liabilities		5,292		(5,081)		211
Total current derivative liabilities			6,079				436
Long-term:
Derivative financial instruments — commodity contracts	Derivative liabilities		1,051		(400)		651
Derivative financial instruments — interest rate swaps	Derivative liabilities		13,069		(11,142)		1,927
Total long-term derivative liabilities			14,120				2,578
Total derivative liabilities			20,199				3,014
		$	29,304			$	29,304

		Gain (Loss) Recognized in Income Year Ended December 31,
Not designated as ASC 815 Hedges	Statement of Operations Classification	2019		2018
Foreign currency	Gain on foreign currency derivative financial instruments	$	-	$	6,838
Commodity contracts	Gain (loss) on commodity derivative financial instruments		(20,542)		40,216
Interest rate swap	Interest expense		(4,270)		(2,435)
		$	(24,812)	$	44,619

Contingent Features in Financial Derivative Instruments.  None of the Company’s derivative instruments contain credit-risk related contingent features.  Most of the counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions and that are lenders under Sundance’s credit agreement.  The Company uses credit agreement participants to hedge with, since these institutions are secured equally with the holder’s of Sundance’s bank debt, which eliminates the need to post collateral when Sundance is in a derivative liability position.  The Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.

Refer to Note 11 for additional information regarding the valuation of derivative instruments.

88

NOTE 11 — FAIR VALUE MEASUREMENT

The Company follows FASB ASC Topic 820 – Fair Value Measurement and Disclosure which establishes a three-level valuation hierarchy for disclosure of fair value measurements.  The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.  The three levels are defined as follows:

Level 1:        Quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2:        Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.

Level 3:        inputs for the asset or liability that are not based on observable market data (unobservable inputs).

The Level within which the financial asset or liability is classified is determined based on the lowest level of significant input to the fair value measurement. The financial assets and liabilities measured at fair value on a recurring basis in the consolidated balance sheets are grouped into the fair value hierarchy as follows (in thousands):

	December 31, 2019
	Level 1		Level 2		Level 3		Total
Assets measured at fair value
Derivative commodity contracts	$	—	$	2,093	$	—	$	2,093
Liabilities measured at fair value
Derivative commodity contracts		—		(2,300)		—		(2,300)
Derivative interest rate swaps		—		(5,763)		—		(5,763)
		—		(8,063)		—		(8,063)
Net fair value	$	—	$	(5,970)	$	—	$	(5,970)
	December 31, 2018
	Level 1		Level 2		Level 3		Total
Assets measured at fair value
Derivative commodity contracts	$	—	$	32,318	$	—	$	32,318
Liabilities measured at fair value
Derivative commodity contracts		—		(876)		—		(876)
Derivative interest rate swaps		—		(2,138)		—		(2,138)
		—		(3,014)		—		(3,014)
Net fair value	$	—	$	29,304	$	—	$	29,304

During the years ended December 31, 2019 and 2018, there were no transfers between Level 1 and Level 2 fair value measurements, and no transfer into or out of Level 3 fair value measurements.

Measurement of Fair Value

a) Derivatives

The Company’s derivative instruments consist of commodity contracts (primarily swaps and collars) and interest rate swaps. The Company utilizes present value techniques and option-pricing models for valuing its derivatives. Inputs to these valuation techniques include published forward prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy.

89

b)           Credit Facilities

As of December 31, 2019 and 2018, the Company had $250 million and $115 million, and $250 million and $65 million of principal debt outstanding on its Term Loan and Revolving Facility, respectively. The Company estimated that the fair value of its Term Loan at December 31, 2019 was $249 million.  The fair value of the Term Loan was determined by using a discounted cash flow model using a discount rate that reflects the Company’s assumed borrowing rate at the end of the reporting period. The carrying value of the Company’s Revolving Facility approximates its fair value as its variable interest rate is tied to current market rates and the applicable margins of 2.25%‑3.25% approximate market rates.

c)           Other Financial Instruments

The carrying amounts of cash, accounts receivable, accounts payable, and accrued liabilities approximate fair value due to their short-term nature.

d)Non-recurring Fair Value Measurements

The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties and assets held for sale. 

Assets held for sale.  Oil and gas properties classified as held for sale, including any corresponding asset retirement obligation, are valued using a market approach, based on an estimated net selling price.  If an estimated selling price is not available, the Company utilizes valuation techniques depending on whether the properties are proved or unproved.  These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances.

	Net Carrying Value as of			Fair Value Measurements Using
(in thousands)	December 31, 2018			Level 1	Level 2		Level 3
Assets held for sale	$	23,471	$	—	$	—	$	23,471

The Company wrote down its Dimmit County oil and gas properties, which were classified as held for sale, to the expected purchase price proceeds, less anticipated external broker marketing costs.  The Company’s estimate of the expected purchase price proceeds was based upon comparable transaction data.  The Company disposed of the Dimmit County properties in October 2019. 

Business Combinations. In estimating the fair values of assets acquired and liabilities assumed, the Company makes various assumptions, which include Level 3 inputs. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved oil and gas properties. To derive fair value, the Company prepares estimates of oil and gas reserves, applying forward strip prices to reserve quantities acquired, and estimating future operating and development costs to arrive at an estimate of undiscounted future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital (“WACC”) rate at the time of the acquisition. The market-based WACC rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, the Company reduces the discounted future net revenues of probable and possible reserves by higher discount rates or additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, the Company reviews comparable purchases and sales of oil and gas properties within the same regions and uses that data as a basis for fair market value. 

90

NOTE 12 — EARNINGS PER SHARE

The reconciliations between basic and diluted earnings (loss) per share are as follows (in thousands, except per share data):

	Year Ended December 31,
	2019		2018
Net loss	$	(39,590)	$	(22,933)
Weighted average shares (1):
Weighted average common shares outstanding, basic		6,874,170		5,236,524
Diluted effect of incremental shares related to restricted share units (2)		—		—
Weighted average common shares outstanding, diluted		6,874,170		5,236,524
Net loss per share:
Basic and diluted	$	(5.76)	$	(4.38)

(1) All share numbers have been retroactively adjusted for the 2019 and 2018 periods to reflect the Company’s one for 100 share consolidation in November 2019, as described in Note 13. 

(2) For the year ended December 31, 2019, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes anti-dilutive shares of 320 shares of service-based awards.  For the year ended December 31, 2018, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes anti-dilutive shares of 786 shares of service-based awards. 

NOTE 13 — EQUITY

Reverse Stock Split

In conjunction with the Company’s Redomiciliation, the Company acquired all of the outstanding ordinary shares of SEAL on the basis of one share of the Company’s stock for every 100 ordinary shares outstanding, which had the effect of a 1-for-100 reverse stock split.  On the effective date of the Redomiciliation, the number of ordinary outstanding shares was reduced from 687 million to 6.9 million.  All share and per share amounts in these consolidated financial statements and related notes for periods prior to the Redomiciliation have been retroactively adjusted to reflect the effect of the exchange ratio.

Equity Offerings

During 2018, the Company issued 5,614,446 shares in connection with a $243 million capital raise (net of offering costs), proceeds of which were used to complete the 2018 acquisition of Eagle Ford oil and gas properties.

Stock-Based Compensation

For the years ended December 31, 2019 and 2018, the Company recognized stock-based compensation expense of $0.5 million and $0.5 million, respectively, related to RSUs (equity-settled).

91

During the years ended December 31, 2019 and 2018, the Board of Directors awarded 38,373 and 71,175 RSUs, respectively, to certain employees. These awards were made in accordance with SEAL’s Plan.  In connection with the Redomiciliation, in November 2019 Sundance Energy Inc. assumed SEAL’s obligations with respect to the settlement of the RSUs that were granted pursuant to the Plan prior to the effective date of the Redomiciliation.  Accordingly, the RSUs will be settled in shares of common stock of Sundance Energy Inc. rather than ordinary shares of SEAL.  Following the effective date of the Redomiciliation, no new awards or grants have been or will be made pursuant to the Plan.  Historical RSU information is summarized below:

		Weighted Average
		Fair Value at
	Number of RSUs	Grant Date
Outstanding at December 31, 2017	33,804	$	166.87
Granted	71,175	$	18.80
Vested	(6,916)	$	361.03
Forfeited	(6,724)	$	198.37
Outstanding at December 31, 2018	91,339	$	34.37
Granted	38,373	$	20.31
Vested (1)	(1,425)	$	61.56
Forfeited	(43,358)	$	51.20
Outstanding at December 31, 2019	84,929	$	22.97

⁽¹⁾ Includes 375 RSUs that have vested, but will be settled in 2020.

Restricted Share Units on Issue

Details of the RSUs outstanding as of December 31, 2019 and 2018:

	Number of RSUs
Grant Date	2019	2018
March 15, 2016 (1)	—	4,428
May 27, 2016 (1)	—	4,342
June 29, 2016 (1)	—	497
February 17, 2017 (1)(2)	3,411	4,572
May 25, 2017 (1)(2)	3,724	3,724
October 23, 2017 (1)	745	745
October 23, 2017	375	750
December 29, 2017	497	1,106
December 26, 2018 (3)	30,414	35,587
December 26, 2018 (4)	15,207	35,588
May 5, 2019	1,775	—
May 5, 2019 (1)	5,325	—
May 31, 2019 (3)	15,637	—
May 31, 2019 (4)	7,819	—
Total RSUs outstanding	84,929	91,339

⁽¹⁾ RSUs vest based on three‑year absolute total shareholder return (“ATSR”).

⁽²⁾ ATSR RSUs were evaluated for vesting subsequent to December 31, 2019.  The vesting conditions were not met and the outstanding awards will be forfeited in 2020.

⁽³⁾ RSUs vest based on three-year total shareholder return (“TSR”) as compared to the XOP index.

⁽⁴⁾ Company performance-based RSUs vest based on 2019 and 2020 EBITDA per debt adjusted share and production per debt adjusted share.

92

The following tables summarize the RSUs issued and their related grant date, fair value and vesting conditions. RSUs awarded during the year ended December 31, 2019:

		Fair Value at
Grant Date	Number of RSUs	Grant Date		Vesting Conditions
May 5, 2019	1,775	$	29.49	Vests on 3rd anniversary of award
May 5, 2019	5,325	$	16.35	0 % - 200% based on 3 year TSR as compared to the XOP index.
May 31, 2019	15,637	$	16.13	0 % - 200% based on 3 year TSR as compared to the XOP index.
May 31, 2019	3,909	$	24.92	0 % - 200% based on 2019 EBITDA per Debt Adjusted Share
May 31, 2019	3,909	$	24.92	0 % - 200% based on 2020 EBITDA per Debt Adjusted Share
May 31, 2019	3,909	$	24.92	0 % - 200% based on 2019 Production per Debt Adjusted Share
May 31, 2019	3,909	$	24.92	0 % - 200% based on 2020 Production per Debt Adjusted Share
	38,373

The following tables summarize the RSUs issued and their related grant date, fair value and vesting conditions. RSUs awarded during the year ended December 31, 2018:

		Fair Value at
Grant Date	Number of RSUs	Grant Date		Vesting Conditions
December 26, 2018	35,587	$	16.44	0 % - 200% based on 3 year TSR as compared to the XOP index
December 26, 2018	8,897	$	21.16	0 % - 200% based on 2019 EBITDA per Debt Adjusted Share
December 26, 2018	8,897	$	21.16	0 % - 200% based on 2020 EBITDA per Debt Adjusted Share
December 26, 2018	8,897	$	21.16	0 % - 200% based on 2019 Production per Debt Adjusted Share
December 26, 2018	8,897	$	21.16	0 % - 200% based on 2020 Production per Debt Adjusted Share
	71,175

Upon vesting, and after a certain administrative period, the RSUs are settled in newly issued common stock of the Company. Once settled, the RSUs are no longer restricted. As of December 31, 2019, the remaining expense associated with unvested RSUs was $0.5 million, which will be recognized over the weighted average remaining contractual life of the RSUs of 1.0 years. For the years ended December 31, 2019 and 2018, the weighted average prices of the RSUs at the date of conversion were $22.02 and $70.85, per share, respectively. At December 31, 2019, the fair value of the RSU awards expected to vest was $0.1 million. 

93

NOTE 14 —COMMITMENTS AND CONTINGENCIES

Marketing, Gathering, Processing and Transportation Commitments

In connection with the Company’s 2018 acquisition, the Company entered into contracts with a large midstream company to gather, process, transport and market oil, NGL and natural gas production for the acquired properties.  The contracts contain a Minimum Revenue Commitment (“MRC”) that requires payment of minimum annual fees for those services. Fixed fees are expensed as incurred and settled with the purchaser on a monthly basis. If, at the end of each calendar year, the Company fails to satisfy the MRC, the Company is required to pay a shortfall. The Company’s MRC for the years ended December 31, 2019 and 2018 totaled $15.8 million and $11.1 million, respectively, and it realized deficiency fees of $2.3 million and $2.8 million, respectively.  The total remaining MRC by fiscal year are as follows (in thousands):

	2020		2021		2022		Total
Hydrocarbon gathering and handling agreement	$	14,297	$	13,972	$	6,675	$	34,944
Crude oil and condensate purchase agreements		4,710		7,513		4,317		16,540
Gas processing agreement		2,017		-		-		2,017
Gas transportation agreements		783		-		-		783
Total MRC	$	21,807	$	21,485	$	10,992	$	54,284

Cooper Basin Capital Commitments

The Company has non-core interest in the petroleum exploration license 570 located in the Cooper Basin, a license located in Australia (PEL 570). The Company has a commitment to fund exploratory drilling in the Cooper Basin of up to approximately A$10.6 million (US$7.5 million) through 2022, of which A$7.1 million (US$5.0 million) has been incurred as of December 31, 2019, with a remaining commitment of A$3.5 million. (US$2.5 million).  The exploratory drilling has not resulted in any proved reserves to date, and less than $0.1 million and $0.7 million incurred during the years ended December 31, 2019 and 2018 was recorded as exploration expense on the consolidated statement of operations. 

Litigation

The Company is involved in various legal proceedings in the ordinary course of business, and recognizes a contingent liability when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. While the outcome of these lawsuits and claims cannot be predicted with certainty, it is the opinion of management that, as of the date of this report, it is not probable that these claims and litigation will have a material adverse impact on the Company, Accordingly, no material amounts for loss contingencies associated with litigation, claims or assessments have been accrued as of December 31, 2019 other than described below. 

In 2013, the Company sold its interests in a non-operated North Dakota property.  During the year ended December 31, 2019, the Company recorded additional expense of $0.7 million for a litigation settlement with the Buyer within other expense (income), net on the consolidated statement of operations.  The settlement was paid in January 2020.

94

NOTE 15 — SUBSEQUENT EVENTS

As discussed in Note 1, the Company’s credit facilities contain the requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception.  The issuance of these consolidated financial statements with the accompanying audit opinion constitutes a default under the Revolving Facility and Term Loan agreements. The Company obtained waivers from its Revolving Facility and Term Loan lenders on May 8, 2020 and May 11, 2020, respectively,  to waive the event of default arising from the inclusion of the going concern explanatory paragraph included in the audit report for the year ended December 31, 2019 and with respect to the defaults arising from a failure to deliver audited consolidated financial statements for the year ended December 31, 2019 and related reports and certificates by the applicable deadline.  These waivers were effective as of April 29, 2020, subject to the conditions set forth in the waivers.  

Under the Revolving Facility waiver, the Company may not draw any additional funds on the Revolving Facility until completion of the Company’s second quarter 2020 borrowing base redetermination.     

Under the Term Loan waiver, the Company agreed to amend certain provisions in the Term Loan, as to be mutually agreed with the Term Loan lenders, within 15 days from the execution date.  The waiver under the Revolving Facility also provides for a right to require corresponding amendments of that facility manner, as requested by the administrative agent in its discretion. Failure to enter into such amendment with respect to the Term Loan within 15 days (or a similar amendment with respect to the Revolving Facility on the date the Term Loan is amended) would constitute an event of default under the credit facilities, in which case the amounts outstanding under the credit facilities could be accelerated and become immediately due and payable.  While management believes that it will finalize such amendments within the required time frame, there can be no assurance that management’s efforts will result in any finalizing these amendments or the ultimate terms of any such amendments. 

With respect to the Term Loan, the Company has engaged in preliminary discussions regarding the terms of the required amendment.  In addition, the Company has agreed to explore in good faith with its Term Loan lenders options to reduce the Company’s overall level of indebtedness and leverage and limit capital and general and administrative expenditures for some specified period of time.  As described above, the lenders under the Revolving Facility may request corresponding amendments under the Revolving Facility.

NOTE 16 — SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Costs Incurred

The Company’s oil and gas activities for 2019 and 2018 were entirely within the United States.  Costs incurred in oil and gas producing activities were as follows (in thousands):

	Year ended December 31,
	2019		2018
Property acquisition costs
Proved	$	—	$	173,750
Unproved (1)		177		45,252
Exploration costs		335		2,789
Development costs (2) (3)		149,766		181,463

⁽¹⁾ Includes costs incurred related to its Dimmit County assets, which were classified as held for sale during 2018 through their sale in October 2019, of nil and $1.0 million during the years ended December 31, 2019 and 2018, respectively.

⁽²⁾ Development costs include $7.1 million and $12.9 million wells in-progress as of December 31, 2019 and 2018, respectively.  These wells in-progress were either drilling, waiting on hydraulic fracturing or production testing. 

95

⁽³⁾ Includes costs incurred related to its Dimmit County assets, which were classified as held for sale during 2018 through their sale in October 2019, of $8.4 million and $5.3 million during the years ended December 31, 2019 and 2018, respectively.

SEC Oil and Gas Reserve Information

Ryder Scott Company, L.P., an independent petroleum engineering consulting firm, prepared estimates of all of the Company’s proved reserve quantities and pre-tax future net cash flows discounted at 10% as of December 31, 2019 and 2018.

Proved reserves are those quantities of oil and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and 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.

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The estimation of our proved reserves employs one or more of the following: production trend extrapolation, analogy, volumetric assessment and material balance analysis. Techniques including review of production and pressure histories, analysis of electric logs and fluid tests, and interpretations of geologic and geophysical data are also involved in this estimation process.

The following reserve data represents estimates only and should not be construed as being exact. All such reserves are located in the continental United States.

		Natural
	Oil	Gas	NGL	Total
	(MBbl)	(MMcf)	(MBbl)	(MBoe)
Proved reserves:
January 1, 2018	27,987	59,409	9,190	47,079
Revisions of previous estimates	(5,138)	(14,257)	(3,201)	(10,716)
Extensions and discoveries	7,577	12,889	2,179	11,904
Purchases of reserves in-place	30,474	55,367	8,801	48,503
Production	(2,256)	(4,534)	(497)	(3,508)
Sales of reserves in-place	(15)	(33)	-	(21)
December 31, 2018	58,629	108,841	16,472	93,241
Revisions of previous estimates	(14,358)	(27,504)	(4,225)	(23,168)
Extensions and discoveries	23,018	52,297	7,915	39,649
Production	(3,077)	(5,768)	(798)	(4,836)
Sales of reserves in-place	(1,424)	(6,962)	(1,230)	(3,814)
December 31, 2019	62,788	120,904	18,134	101,072
Proved developed reserves:
December 31, 2018	16,742	33,169	4,927	27,197
December 31, 2019	16,101	26,930	4,022	24,611
Proved undeveloped reserves
December 31, 2018	41,887	75,672	11,545	66,044
December 31, 2019	46,687	93,974	14,112	76,461

96

Notable changes in proved reserves for the years ended December 31, 2019 and 2018 included the following:

Proved Undeveloped Reserves

As of December 31, 2019, the Company’s proved undeveloped reserves were approximately 76,461 MBoe, an increase of 10,417 MBoe over its December 31, 2018 proved undeveloped reserves estimate of approximately 66,044 MBoe.  The change primarily resulted from proved undeveloped locations added in 2019 as result of the Company’s technical evaluation of wells drilled and completed in late 2018 and in 2019 on properties acquired in 2018 (extensions and discoveries totaled 36,535 MBoe during the year).  As of December 31, 2018, the Company was still in the process of evaluating many of the undeveloped locations acquired in 2018. As of December 31, 2018 approximately half of the undeveloped locations in its development plan were on acreage acquired in the 2018 acquisition.  The remainder of the December 31, 2018 proved undeveloped locations were on properties that the Company owned prior to the 2018 acquisition (legacy properties or legacy locations).  As a result of the Company’s additional technical evaluation of the acquired properties during 2019, the focus of its development plan shifted to properties acquired in 2018 with higher projected returns.  Approximately 19,881 MBoe primarily associated with approximately 50 proved undeveloped locations on legacy properties were removed and 80 locations on the acquired assets with 35,630 MBoe were added to the Company’s five-year development plan.  During 2019, the Company converted 4,501 MBoe of proved undeveloped reserves to proved developed producing reserves. 

Over the next five years, the Company expects to fund future development costs of $1,173.2 million associated with proved undeveloped reserves with operating cash flows from its existing proved developed reserves, cash flows from proved undeveloped reserves converted to proved developed reserves and with capacity available under its Revolving Credit Facility as of December 31, 2019. Using December 31, 2019 SEC price assumptions, the Company’s undiscounted operating cash flows from its proved reserves are expected to be approximately $1,503.7 million over the next five years which is adequate to fund projected future development costs, administrative expenses and interest.  The Company’s development plan does not contemplate a uniform conversion of proved undeveloped reserves. At December 31, 2019, the Company’s five-year development plan assumed a slower development pace in 2020 and 2021, which would allow operating cash flow to accumulate.  The Company intends to use the accumulated cash flow to fund an increased pace of development in later years such that all remaining proved undeveloped locations would be developed within the five-year period. 

Revisions of Previous Estimates

The Company’s previous estimates of Proved Reserves decreased by 23,168 MBoe in 2019.  This decrease was primarily due to the removal of certain proved undeveloped legacy locations as they were no longer scheduled to be drilled within their initial five year window as a result of redirecting the Company’s development plan to focus on locations with better economics that were acquired in 2018.

The Company’s previous estimates of Proved Reserves related to the Eagle Ford Formation decreased by 10,716 MBoe in 2018. This decrease was primarily due to the removal of certain proved undeveloped reserves as they were not planned to be drilled within their initial five year window as a result of redirecting drilling efforts toward more locations that were part of the 2018 acquisition.

Extensions and Discoveries

The Company had extensions and discoveries of 39,649 MBoe during 2019, which were primarily proved undeveloped reserves, that were the result of the Company’s technical evaluation of wells drilled and completed in late 2018 and in 2019 on properties acquired in 2018.  The 2019 drilling program was focused primarily in Live Oak County, Texas, and, to a lesser extent, in McMullen and Atascosa Counties, Texas.  The Company’s total proved undeveloped locations as of December 31, 2019 were relatively consistent with that of prior year as a result of the removal of proved undeveloped legacy locations discussed in revisions of previous estimates.  The Company had extensions and discoveries of 11,904 MBoe during 2018, resulting from the 2018 drilling program primarily in Live Oak County, Texas, and, to a lesser extent, in McMullen and LaSalle Counties, Texas, targeting the Eagle Ford Formation. 

97

Purchase of Reserves In-Place

The Company did not purchase any reserves in place during 2019.  In 2018, the Company’s purchases of reserves in place were located in the Eagle Ford in South Texas. 

Sales of Reserves In-Place

During 2019, the Company’s sales of reserves were located in Dimmit County, Texas, which consisted of 2,078 Mboe of proved developed reserves, and 1,736 MBoe of proved undeveloped reserves.  

During 2018, the Company’s sales of reserves were located in Maverick County, Texas. 

Standardized Measure of Future Net Cash Flow

The Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport, nor should it be interpreted, to present the fair value of a company’s proved oil and natural gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value of money, and risks inherent in reserve estimates.

Under the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves which are based on SEC-defined pricing as discussed further below. Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. The Company calculatesthe projected income tax effect using the “year- by-year” method for purposes of the supplemental oil and gas disclosures.  Future net cash flow after income taxes is discounted using a 10% annual discount rate to arrive at the Standardized Measure.

The following summary sets forth our Standardized Measure (in thousands):

	December 31,
	2019		2018
Cash inflows	$	4,148,426	$	4,733,751
Production costs		(1,348,892)		(1,318,059)
Development costs		(1,231,467)		(1,143,083)
Income tax expense		(183,680)		(343,068)
Net cash flow		1,384,387		1,929,541
10% annual discount rate		(709,288)		(976,916)
Standardized measure of discounted future net cash flow	$	675,099	$	952,625

98

The following are the principal sources of change in the Standardized Measure (in thousands):

	Year ended December 31,
	2019		2018
Standardized Measure, beginning of year	$	952,625	$	366,747
Sales, net of production costs		(141,329)		(113,073)
Net change in sales prices, net of production costs		(422,811)		201,784
Extensions and discoveries, net of future production and development costs		258,433		206,179
Changes in future development costs		283,154		63,297
Previously estimated development costs incurred during the period		84,739		94,673
Revision of quantity estimates		(308,312)		(198,956)
Accretion of discount		110,985		38,124
Change in income taxes		79,728		(142,730)
Purchases of reserves in-place		—		525,547
Sales of reserves in-place		(47,059)		(220)
Change in production rates and other		(175,054)		(88,747)
Standardized Measure, end of year	$	675,099	$	952,625

Impact of Pricing

The estimates of cash flows and reserve quantities shown above are based upon the unweighted average first-day-of-the-month prices for the previous twelve months, inclusive of adjustments for quality and location. If future gas sales are covered by contracts at specified prices, the contract prices are used. Fluctuations in prices are due to supply and demand and are beyond our control.

The following average prices were used in determining the Standardized Measure:

	Year ended December 31,
	2019		2018
Oil (per Bbl)	$	56.05	$	66.34
Gas (per Mcf)	$	2.75	$	3.50
NGL (per Bbl)	$	16.35	$	28.15

99

NOTE 17—QUARTERLY FINANCIALDATA (UNAUDITED)

The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2019 and 2018 (in thousands, except per share data):

	Three Months Ended
	March 31, 2019		June 30, 2019		September 30, 2019		December 31, 2019
Revenues	$	47,740	$	52,901	$	51,097	$	51,842
Income (loss) from operations	$	(31,804)	$	13,572	$	24,126	$	(11,944)
Net income (loss)	$	(37,209)	$	2,643	$	13,297	$	(18,321)
Income (loss) per share - basic	$	(5.41)	$	0.38	$	1.93	$	(2.67)
Income (loss) per share - diluted	$	(5.41)	$	0.38	$	1.93	$	(2.67)
	Three Months Ended
	March 31, 2018		June 30, 2018		September 30, 2018		December 31, 2018
Revenues	$	24,036	$	28,737	$	53,824	$	58,336
Income (loss) from operations	$	(9,738)	$	(47,852)	$	(13,202)	$	83,609
Net income (loss)	$	(25,731)	$	(49,673)	$	(20,249)	$	72,720
Income (loss) per share - basic	$	(19.75)	$	(8.63)	$	(2.95)	$	10.58
Income (loss) per share - diluted	$	(19.75)	$	(8.63)	$	(2.95)	$	10.58

⁽¹⁾ Per share amounts have been retroactively adjusted for periods prior to the fourth quarter of 2019 to reflect the Company’s one-for-100 reverse stock split in November 2019, as described in Note 13 to these consolidated financial statements.

100

EXHIBIT INDEX

Exhibit Number	Description of Exhibit
2.1	Scheme Implementation Agreement (incorporated by reference to Exhibit 99.2 of the Current Report on Form 6-K (File No. 001-36302) furnished to the SEC on September 11, 2019)
3.1	Certificate of Incorporation of Sundance Energy Inc., dated September 5, 2019 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 001-36302) filed with the SEC on November 26, 2019)
3.2	Bylaws of Sundance Energy Inc., dated September 5, 2019 (incorporated by reference to Exhibit 3.2 of Form 8-K (File No. 001-36302) filed with the SEC on November 26, 2019)
3.3	Form of common stock certificate of Sundance Energy Inc. (incorporated by reference to Exhibit 4.1 of Form 8-K (File No. 001-36302) filed with the SEC on November 26, 2019)
4.1	Description of Securities*
10.1	Purchase and Sale Agreement, dated March 9, 2018 between Pioneer Natural Resources USA, Inc., Reliance Eagleford Upstream Holding LP, and Newpek, LLC as Sellers and Sundance Energy, Inc. as Buyer (incorporated by reference to Exhibit 4.3 of Form 20‑F (File No. 000‑36302) filed with the SEC on May 1, 2018)
10.2	Amended and Restated Term Loan Credit Agreement, dated April 23, 2018 among Sundance Energy Australia Limited, as parent, Sundance Energy, Inc., as borrower and Morgan Stanley Energy Capital, Inc., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 4.4 of Form 20-F (File No. 001-36302) filed with the SEC on May 1, 2018)
10.3	First Amendment to Amended and Restated Term Loan Credit Agreement, dated July 31, 2018, among Sundance Energy Australia Limited, as parent, Sundance Energy, Inc., as borrower, Morgan Stanley Energy Capital, Inc., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 4.3 of Form 20-F (File No. 001-36302) filed with the SEC on April 30, 2019)
10.4	Guarantee and Collateral Agreement, dated April 23, 2018, by Sundance Energy Australia Limited, Sundance Energy, Inc. and other guarantor party thereto, in favor of Morgan Stanley Energy Capital Inc., as administrative agent (incorporated by reference to Exhibit 4.5 of Form 20-F (File No. 001-36302) filed with the SEC on May 1, 2018)
10.5	Mortgage, Deed of Trust, Assignment of As-Extracted Collateral, Security Agreement, Fixture Filing and Financing Statement from Sundance Energy, Inc. to David Lazarus, as trustee for the benefit of Morgan Stanley Energy Capital Inc., as administrative agent for the secured parties (incorporated by reference to Exhibit 4.6 of Form 20-F (File No. 001-36302) filed with the SEC on May 1, 2018)
10.6	Mortgage, Deed of Trust, Assignment of As-Extracted Collateral, Security Agreement, Fixture Filing and Financing Statement from SEA Eagle Ford, LLC to David Lazarus, as trustee for the benefit of Morgan Stanley Energy Capital Inc., as administrative agent for the secured parties (incorporated by reference to Exhibit 4.7 of Form 20-F (File No. 001-36302) filed with the SEC on May 1, 2018)
10.7	Mortgage, Deed of Trust, Assignment of As-Extracted Collateral, Security Agreement, Fixture Filing and Financing Statement from Armadillo E&P, Inc to David Lazarus, as trustee for the benefit of Morgan Stanley Energy Capital Inc., as administrative agent for the secured parties (incorporated by reference to Exhibit 4.8 of Form 20-F (File No. 001-36302) filed with the SEC on May 1, 2018)

101

10.8	Intercreditor Agreement, dated April 23, 2018, among Sundance Energy, Inc., the other grantors party thereto, Natixis, New York Branch, as senior representative, and Morgan Stanley Energy Capital, Inc., as the second priority representative (incorporated by reference to Exhibit 4.9 of Form 20-F (File No. 001-36302) filed with the SEC on May 1, 2018)
10.9	Credit Agreement, dated April 23, 2018 among Sundance Energy Australia Limited, Sundance Energy, Inc., as borrower and Natixis, New York Branch, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 4.10 of Form 20-F (File No. 001-36302) filed with the SEC on May 1, 2018)
10.10	First Amendment to Credit Agreement, dated July 18, 2018 among Sundance Energy Australia Limited, Sundance Energy, Inc., as borrower and Natixis, New York Branch, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 4.10 of Form 20-F (File No. 001-36302) filed with the SEC on April 30, 2019)
10.11	Second Amendment to Credit Agreement, dated December 28, 2018 among Sundance Energy Australia Limited, Sundance Energy, Inc., as borrower, Natixis, New York Branch, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 4.11 of Form 20-F (File No. 001-36302) filed with the SEC on April 30, 2019)
10.12	Guarantee and Collateral Agreement, dated April 23, 2018, among Sundance Energy Australia Limited and Sundance Energy, Inc., in favor of Natixis, New York Branch, as administrative agent (incorporated by reference to Exhibit 4.11 of Form 20-F (File No. 001-36302) filed with the SEC on May 1, 2018)
10.13	Mortgage, Deed of Trust, Assignment of As-Extracted Collateral, Security Agreement, Fixture Filing and Financing Statement from Sundance Energy, Inc. to Tim Polvado, as trustee for the benefit of Natixis, New York Branch, as administrative agent (incorporated by reference to Exhibit 4.12 of Form 20-F (File No. 001-36302) filed with the SEC on May 1, 2018)
10.14	Mortgage, Deed of Trust, Assignment of As-Extracted Collateral, Security Agreement, Fixture Filing and Financing Statement from SEA Eagle Ford, LLC to Tim Polvado, as trustee for the benefit of Natixis, New York Branch, as administrative agent (incorporated by reference to Exhibit 4.13 of Form 20-F (File No. 001-36302) filed with the SEC on May 1, 2018)
10.15	Mortgage, Deed of Trust, Assignment of As-Extracted Collateral, Security Agreement, Fixture Filing and Financing Statement from Armadillo E&P, Inc. to Tim Polvado, as trustee for the benefit of Natixis, New York Branch, as administrative agent (incorporated by reference to Exhibit 4.14 of Form 20-F (File No. 001-36302) filed with the SEC on May 1, 2018)
10.16	Third Amendment to Credit Agreement, dated May 15, 2019 among Sundance Energy Australia Limited, Sundance Energy, Inc., as borrower, Natixis, New York Branch, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 99.2 of Form 6-K (File No. 001-36302) furnished to the SEC on September 13, 2019)
10.17	Fourth Amendment to Credit Agreement, dated January 13, 2020, among Sundance Energy, Inc., as borrower, Sundance Energy Inc., as parent guarantor, SEA Eagle Ford, LLC and Armadillo E&P, Inc., as subsidiary guarantors, the lenders party thereto, KeyBank National Association, Toronto Dominion (Texas) LLC, as administrative agent, Natixis, New York branch, in its own capacity and Bank of America N.A. (incorporated by reference to Exhibit 10.1 of Form 8-K (File No. 001-36302) filed with the SEC on January 14, 2020)

102

10.18	Second Amendment to Amended and Restated Term Loan Credit Agreement, dated January 13, 2020, among Sundance Energy, Inc., as borrower, Sundance Energy Inc., as parent guarantor, SEA Eagle Ford, LLC and Armadillo E&P, Inc., as subsidiary guarantors, the lenders party thereto, and Morgan Stanley Capital Administrators Inc. (f/k/a Morgan Stanley Energy Capital Inc.), as administrative agent (incorporated by reference to Exhibit 10.2 of Form 8-K (File No. 001-36302) filed with the SEC on January 14, 2020)
10.19	Limited Waiver, dated May 8, 2020, among Sundance Energy, Inc., as borrower, Sundance Energy Inc., as parent guarantor, SEA Eagle Ford, LLC and Armadillo E&P, Inc., as subsidiary guarantors, the lenders party thereto and KeyBank National Association, Toronto Dominion (Texas) LLC, as administrative agent*
10.20	Limited Waiver, dated May 11, 2020, among Sundance Energy, Inc., as borrower, Sundance Energy Inc., as parent guarantor, SEA Eagle Ford, LLC and Armadillo E&P, Inc., as subsidiary guarantors, the lenders party thereto, and Morgan Stanley Capital Administrators Inc., as administrative agent*
10.21	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File No. 001-36302) filed with the SEC on November 26, 2019) †
10.22	Sundance Energy Australia Limited Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 of Form 8-K (File No. 001-36302) filed with the SEC on November 26, 2019) †
10.23	Employment Agreement, dated January 24, 2020, by and among Sundance Energy Inc., a Delaware corporation, its wholly owned subsidiary Sundance Energy, Inc., a Colorado corporation, and Eric P. McCrady (incorporated by reference to Exhibit 10.1 of Form 8-K (File No. 001-36302) filed with the SEC on January 29, 2020) †
10.24	Employment Agreement, dated January 24, 2020, by and among Sundance Energy Inc., a Delaware corporation, its wholly owned subsidiary Sundance Energy, Inc., a Colorado corporation, and Cathy L. Anderson (incorporated by reference to Exhibit 10.2 of Form 8-K (File No. 001-36302) filed with the SEC on January 29, 2020) †
21.1	List of significant subsidiaries of Sundance Energy Inc.*
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002*
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002*
32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**
32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**
99.1	Report of Ryder Scott Company regarding Sundance Energy Inc.’s estimated proved reserves as of December 31, 2019 dated February 13, 2020*
99.2	Report of Ryder Scott Company regarding Sundance Energy Inc.’s estimated proved reserves as of December 31, 2018 dated February 21, 2019 (incorporated by reference to Exhibit 15.3 of Form 20-F (File No. 001-36302) filed with the SEC on April 30, 2019)
101	The following materials from Sundance Energy Inc.’s Annual Report for the year ended December 31, 2019 are filed herewith, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statements of Operations for the Years Ended December 31, 2019 and 2018, (ii) the Consolidated Balance Sheets as of December 31, 2019 and 2018, (iii) the Consolidated Statements of Equity for the Years Ended December 31, 2019 and 2018 (iv) the Consolidated Statements of Cash Flows for the Years Ended December 31, 2019 and 2018, and (v) Notes to Consolidated Financial Statements.*

103

*Filed herewith.

**Furnished herewith.

†  Management contract or compensatory plan or arrangement.

104

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SUNDANCE ENERGY INC.
	By:	/s/ Eric P. McCrady
		Name:	Eric P. McCrady
		Title:	Chief Executive Officer and Director
Date: May 14, 2020

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

By:	/s/ Cathy L. Anderson
	Name:	Cathy L. Anderson
	Title:	Chief Financial Officer
	May 14, 2020
By:	/s/ Stephen J. McDaniel
	Name:	Stephen J. McDaniel
	Title:	Chairman of the Board of Directors
	May 14, 2020
By:	/s/ Judith D. Buie
	Name:	Judith D. Buie
	Title:	Director
	May 14, 2020
By:	/s/ Damien A. Hannes
	Name:	Damien A. Hannes
	Title:	Director
	May 14, 2020
By:	/s/ H. Weldon Holcombe
	Name:	H. Weldon Holcombe
	Title:	Director
	May 14, 2020
By:	/s/ Neville W. Martin
	Name:	Neville W. Martin
	Title:	Director
	May 14, 2020
By:	/s/ Thomas L. Mitchell
	Name:	Thomas L. Mitchell
	Title:	Director
	May 14, 2020

105

EX-4.1

Exhibit 4.1

SUNDANCE ENERGY INC.

DESCRIPTION OF SECURITIES

As of December 31, 2019, our common stock is the only class of securities we have registered under Section 12 of the Securities Exchange Act of 1934, as amended.

DESCRIPTION OF OUR COMMON STOCK

The following description of our common stock is a summary. This summary is subject to the General Corporation Law of the State of Delaware and the complete text of our certificate of incorporation and bylaws. We have filed copies of our certificate of incorporation and bylaws as exhibits to our periodic reports filed with the SEC, each of which are incorporated by reference as exhibits to the Annual Report on Form 10-K of which this exhibit is a part.

Our authorized capital stock presently consists of 100,000,000 shares of common stock, par value $0.001 per share.

Voting Rights

Each holder of common stock is entitled to one vote for each share on all matters submitted to a vote of the stockholders, including the election of directors. For a proposal other than the election of directors, unless otherwise required by our certificate of incorporation, bylaws or other applicable laws and standards,the proposal will be approved if the votes cast in favor of the proposal exceed the votes cast opposing the proposal.

In the election of directors, holders of our common stock do not have cumulative voting rights. In an uncontested election, each nominee who receives a majority of the votes cast shall be deemed to be elected. In a contested director election, in which the number of nominees exceeds the number of directors to be elected, each director shall be elected by a plurality of the votes cast.

Dividends

Holders of our common stock are entitled to receive dividends, if any, that the board of directors may from time to time declare out of funds legally available. 

Liquidation

In the event of liquidation, dissolution or winding up, holders of our common stock are entitled to share ratably in the net assets legally available for distribution after the payment of all of debts and other liabilities.

Other Rights

Holders of our common stock have no pre-emptive, conversion, subscription or other rights, and there are no redemption or sinking fund provisions applicable to our common stock.

All outstanding shares of our common stock are fully paid and non-assessable.

Nasdaq Listing

Our common stock is listed on Nasdaq Global Market under the symbol “SNDE.”

EX-10.19

Exhibit 10.19

LIMITED WAIVER

This LIMITED WAIVER (hereinafter referred to as this “Agreement”), dated as of May 8, 2020 (the “Execution Date”), but effective as of the Effective Date (hereinafter defined), is made by and among SUNDANCE ENERGY INC.,a Delaware corporation (“Parent”), SUNDANCE ENERGY, INC., a Colorado corporation (the “Borrower”), the other LOAN PARTIES hereto and TORONTO DOMINION (TEXAS) LLC, as administrative agent (in such capacity, the “Administrative Agent”).  Unless the context otherwise requires or unless otherwise expressly defined herein, capitalized terms used but not defined in this Agreement have the meanings assigned to such terms in the Credit Agreement (as defined below).

WITNESSETH:

WHEREAS, the Parent, the Borrower, the Administrative Agent and the lenders party thereto (the “Lenders”) are parties to that certain Credit Agreement dated as of April 23, 2018 (as the same may have been amended, restated, amended and restated, supplemented or otherwise modified from time to time prior to the date hereof, the “Credit Agreement”);

WHEREAS, the Borrower has advised the Administrative Agent and the Lenders that (a) Deloitte & Touche LLP may include a going concern or like qualification or exception in its audit opinion with respect to the financial statements of the Parent and its Subsidiaries for the fiscal year ended December 31, 2019 (the “2019 Audited Financial Statements”) required to be delivered pursuant to Section 8.01(a) of the Credit Agreement as a result of the Borrower’s anticipated failure to comply with Section 9.01(b) of the Term Loan Credit Agreement during the 2020 calendar year (the “Going Concern Qualification”) and (b) the Borrower will not deliver (i) the 2019 Audited Financial Statements required by Section 8.01(a) of the Credit Agreement, (ii) the certificate of the Financial Officer of the Parent as required by Section 8.01(c) of the Credit Agreement, (iii) the certificates of insurance as required by Section 8.01(f) of the Credit Agreement (iv) the production report and lease operating statements for each calendar month during the then current fiscal year to date as required by Section 8.01(n) of the Credit Agreement, and (v) the operating budget for the immediately succeeding twelve (12) months as required by Section 8.01(p) of the Credit Agreement (the foregoing, collectively, the “2019 Financial Deliverable Package”) to the Administrative Agent and each Lender, in each case, within 120 days after the end of the fiscal year ended December 31, 2019 (the “2019 Financial Statements Delivery Deadline”);

WHEREAS, the delivery of (a) the 2019 Audited Financial Statements accompanied by an auditor’s report containing the Going Concern Qualification and (b) the 2019 Financial Deliverable Package after the 2019 Financial Statements Delivery Deadline, in each case, would violate Sections 8.01(a),  (c),  (f),  (n) and (p) of the Credit Agreement and would result in a Default or Event of Default under Section 10.01(e) of the Credit Agreement (any such Defaults or Events of Default being, collectively, the “Specified Defaults”);

WHEREAS, the Loan Parties have requested that the Lenders waive the Specified Defaults arising from such breaches of the terms of Sections 8.01(a),  (c),  (f),  (n) and (p) of the Credit Agreement;

WHEREAS, pursuant to Section 12.02(b) of the Credit Agreement, the Borrower, the other Loan Parties and the Majority Lenders may waive, or consent to the Administrative Agent’s waiver of, certain provisions of the Credit Agreement and other Loan Documents pursuant to an agreement in writing; and

WHEREAS, pursuant to Section 12.02(b) of the Credit Agreement, the Borrower, the other Loan Parties and Lenders comprising the Majority Lenders, are willing to waive the Specified Defaults with respect to the delivery of the 2019 Financial Deliverable Package on and subject to the terms and conditions set forth herein.

Limited Waiver – 2019 Audited Financial Statements (Revolving Facility) – Page 1

NOW, THEREFORE, for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

1. Limited Waiver.  Subject to the terms and conditions set forth herein, effective as of April 29, 2020 (the “Effective Date”), the Administrative Agent, on behalf of the Majority Lenders, hereby waives the Specified Defaults arising solely from (a) the Borrower’s delivery of an audit report of the Parent and its Subsidiaries containing the Going Concern Qualification with respect to the 2019 Audited Financial Statements and (b) the Borrower’s delivery of the 2019 Financial Deliverable Package after the 2019 Financial Statements Delivery Deadline. The limited waiver set forth in this Section 1 (the “Waiver”) is limited to the extent expressly set forth herein and no other terms, covenants or provisions of the Credit Agreement or any other Loan Document shall in any way be affected hereby.  The Waiver is granted only with respect to the Specified Defaults relating to the 2019 Financial Deliverable Package, and shall not apply to any financial statements for any other fiscal year or period, any other breach of the terms of the Credit Agreement, or any actual or prospective default or breach of any other provision of the Credit Agreement or any other Loan Document. Other than with respect to the Going Concern Qualification and the 2019 Financial Statements Delivery Deadline, the Waiver does not waive any other requirement with respect to delivery of the 2019 Financial Deliverable Package. The Waiver shall not in any manner create a course of dealing or otherwise impair the future ability of the Administrative Agent or the Lenders to declare a Default or Event of Default under or otherwise enforce the terms of the Credit Agreement or any other Loan Document with respect to any matter other than the Specified Defaults specifically and expressly waived in, and subject to the terms of, the Waiver.

2. Conditions Precedent.  This Agreement and the Waiver provided for in Section 1 shall become effective on the date when the following conditions are met:

(a) the Administrative Agent shall have received a counterpart signature page of this Agreement duly executed by each of the Parent, the Borrower, the other Loan Parties, and the Administrative Agent and a consent to the Administrative Agent’s entry into this Agreement, on behalf of and at the direction of the Lenders, from Lenders constituting the Majority Lenders;

(b) the Administrative Agent shall have received a fully executed copy of a valid waiver under the Term Credit Agreement and the other Term Loan Documents with respect to any default or event of default resulting from the Borrower delivering (i) the 2019 Audited Financial Statements with the Going Concern Qualification and (ii) the 2019 Financial Deliverable Package after the 2019 Financial Statements Delivery Deadline, in form reasonably satisfactory to the Administrative Agent (the “Term Waiver”);

(c) the Administrative Agent shall have received such other documents, instruments, opinions, certifications, undertakings, further assurances and other matters as the Administrative Agent may reasonably request;

(d) Borrower shall have delivered the 2019 Financial Deliverable Package to the Administrative Agent; and

(e) the Borrower shall have paid all fees and expenses payable to the Administrative Agent and the Lenders (including the fees and expenses of counsel to the Administrative Agent) accrued to date in full to the extent invoiced prior to the date hereof, but without prejudice to the later payment of accrued fees and expenses not so invoiced.

Limited Waiver – 2019 Audited Financial Statements (Revolving Facility) – Page 2

3. Borrowing Requests and Letters of Credit. In consideration of the Waiver, beginning on the Effective Date and ending upon the Business Day next succeeding delivery of the New Borrowing Base Notice with respect to the first Scheduled Redetermination following the Effective Date and notwithstanding any provision to the contrary in the Credit Agreement, Borrower shall not be permitted to request or receive any Borrowing or issuance, amendment, renewal or extension of any Letter of Credit (the “Draw Restrictions”), nor shall the Lenders be obligated to honor any such request. The Draw Restrictions shall not prohibit the Borrower from continuing or converting any Borrowing existing prior to the Effective Date.

4. Agreement to Amend the Credit Agreement.  In consideration of the Waiver, each Loan Party hereby agrees to enter into an amendment (or amendments as applicable) to the Credit Agreement, and the other Loan Documents to the extent applicable, with the Administrative Agent and the number of Lenders required by Section 12.02(b) of the Credit Agreement (any such amendment, a “Tag-along Amendment”) that would have the effect of incorporating mutatis mutandis in favor of the Administrative Agent and/or the Lenders any of the provisions requested by the Administrative Agent and such Lenders that are or are to be incorporated in favor of the Term Agent or any Term Lender or any Secured Party (as defined in the Term Credit Agreement) in any amendment to the Term Credit Agreement or any Term Loan Documents between any Loan Party and the Term Agent and/or any Term Lender and/or any Secured Party (as defined in the Term Credit Agreement) (a) within 90 days from the Execution Date and/or (b) to discharge or satisfy the obligations of any Loan Party under the Term Waiver, including Section 3 of the Term Waiver (any such amendment, a “Term Amendment”). Borrower shall provide notice to the Administrative Agent of all substantive provisions to be incorporated in a Term Amendment at least [five] Business Days prior to entering into any such Term Amendment. Failure to enter into a Tag-along Amendment contemporaneously with entering into a Term Amendment or failure to provide the notice required pursuant to this Section 4 shall constitute an immediate Event of Default under the Credit Agreement. This Section 4 and any provision of the Term Waiver, including Section 3 of the Term Waiver, shall in all respects be subject to the Intercreditor Agreement, including Section 5.03 of the Intercreditor Agreement.

5. Ratification; Representations and Warranties.  Each Loan Party hereby (a) ratifies and affirms its obligations under, and acknowledges, renews and extends its continued liability under, each Loan Document to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect, except as expressly amended hereby and (b) represents and warrants to the Lenders that, as of the date hereof, after giving effect to the terms of this Agreement: (i) all of the representations and warranties contained in each Loan Document to which it is a party are true and correct in all material respects (unless already qualified by materiality in which case such applicable representation and warranty shall be true and correct), except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct in all material respects (unless already qualified by materiality in which case such applicable representation and warranty shall be true and correct) as of such specified earlier date and (ii) no Default or Event of Default has occurred and is continuing.

6. Counterparts.  This Agreement may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. Delivery of an executed counterpart of a signature page of this Agreement by fax, as an attachment to an email or other similar electronic means shall be effective as delivery of a manually executed counterpart of this Agreement.

7. No Oral Agreement.  THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS EXECUTED HEREWITH AND THEREWITH REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES HERETO AND THERETO AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL

Limited Waiver – 2019 Audited Financial Statements (Revolving Facility) – Page 3

AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

8. Severability.  Any provision of this Agreement held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof or thereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.

9. Governing Law.  THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES UNDER THIS AGREEMENT SHALL BE GOVERNED BY, CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

10. JURISDICTION; SERVICE OF PROCESS; JURY TRIAL WAIVER. BORROWER, PARENT AND THE OTHER LOAN PARTIES AGREE TO THE PROVISIONS OF SECTION 12.09(B) (JURISDICTION); SECTION 12.09(C) (SERVICE OF PROCESS) AND SECTION 12.09(D) (JURY TRIAL WAIVER) OF THE CREDIT AGREEMENT AND SUCH PROVISIONS ARE INCORPORATED HEREIN, MUTATIS MUTANDIS, AS A PART HEREOF.

11. Claims. As additional consideration to the execution, delivery, and performance of this Agreement by the parties hereto and to induce the Administrative Agent and the Lenders to enter into this Agreement, each Loan Party represents and warrants that it does not know of any defenses, counterclaims or rights of setoff to the payment of any Secured Obligations to the Administrative Agent, Issuing Bank or the Lenders.

12. WAIVER AND RELEASE. IN CONSIDERATION OF THE WAIVER HEREIN AND OTHER GOOD AND VALUABLE CONSIDERATION, THE RECEIPT AND SUFFICIENCY OF WHICH IS HEREBY ACKNOWLEDGED, EACH LOAN PARTY HEREBY WAIVES, REMISES, RELEASES, AND FOREVER DISCHARGES EACH LENDER, ISSUING BANK, AND THE ADMINISTRATIVE AGENT, THEIR RESPECTIVE PREDECESSORS AND ITS SUCCESSORS, ASSIGNS, AFFILIATES, SHAREHOLDERS, DIRECTORS, OFFICERS, ACCOUNTANTS, ATTORNEYS, EMPLOYEES, AGENTS, REPRESENTATIVES, AND SERVANTS (COLLECTIVELY, THE “RELEASED PARTIES”) OF, FROM AND AGAINST ANY AND ALL CLAIMS, ACTIONS, CAUSES OF ACTION, SUITS, PROCEEDINGS, CONTRACTS, JUDGMENTS, DAMAGES, ACCOUNTS, RECKONINGS, EXECUTIONS, AND LIABILITIES WHATSOEVER OF EVERY NAME AND NATURE, WHETHER KNOWN OR UNKNOWN, WHETHER OR NOT WELL FOUNDED IN FACT OR IN LAW, AND WHETHER IN LAW, AT EQUITY, OR OTHERWISE, WHICH THE UNDERSIGNED EVER HAD OR NOW HAS FOR OR BY REASON OF ANY MATTER, CAUSE, OR ANYTHING WHATSOEVER TO THIS DATE RELATING TO OR ARISING OUT OF THE LOANS, OR ANY OF THEM, OR ANY OF THE LOAN DOCUMENTS, INCLUDING WITHOUT LIMITATION ANY ACTUAL OR ALLEGED ACT OR OMISSION OF ANY OF THE RELEASED PARTIES WITH RESPECT TO THE LOANS, OR ANY OF THEM, OR ANY OF THE LOAN DOCUMENTS, INCLUDING WITHOUT LIMITATION ANY ACTUAL OR ALLEGED ACT OR OMISSION OF ANY OF THE RELEASED PARTIES WITH RESPECT TO THE LOANS, OR ANY OF THEM, OR ANY OF THE LOAN DOCUMENTS, OR ANY LIENS OR COLLATERAL IN CONNECTION THEREWITH, OR THE ENFORCEMENT OF ANY OF SUCH LENDER’S OR ISSUING BANK’S OR THE ADMINISTRATIVE AGENT’S RIGHTS OR REMEDIES THEREUNDER.  THE TERMS OF THIS WAIVER AND RELEASE SHALL SURVIVE THE TERMINATION OF THIS AGREEMENT, THE LOANS, OR THE LOAN DOCUMENTS AND SHALL REMAIN IN FULL FORCE AND EFFECT AFTER THE TERMINATION THEREOF.

Limited Waiver – 2019 Audited Financial Statements (Revolving Facility) – Page 4

13. No Waiver. Borrower agrees that other than the Specified Defaults, no Event of Default and no Default has been waived or remedied by the execution of this Agreement by the Administrative Agent and the Lenders, and any such Default or Event or Default heretofore arising and currently continuing shall continue after the execution and delivery hereof.  Other than with respect to the Waiver specifically set forth herein, nothing contained in this Agreement nor any past indulgence by the Administrative Agent or the Lenders, nor any other action or inaction on behalf of the Administrative Agent or the Lenders (i) shall constitute or be deemed to constitute a waiver of any Defaults or Events of Default which may exist under the Credit Agreement or the other Loan Documents, or (ii) shall constitute or be deemed to constitute an election of remedies by the Administrative Agent or the Lenders or a waiver of any of the rights or remedies of the Administrative Agent or the Lenders provided in the Credit Agreement or the other Loan Documents or otherwise afforded at law or in equity.

14. Headings. Section headings used herein are for convenience of reference only, are not part of this Agreement and shall not affect the construction of, or be taken into consideration in interpreting, this Agreement.

15. Fees and Expenses. The Parent and the Borrower hereby agree, jointly and severally, to reimburse the Administrative Agent and the Lenders for all reasonable and documented out-of-pocket costs and expenses incurred in connection with the development, preparation and execution of this Agreement, including the reasonable and documented fees, disbursements and other charges of one primary counsel to the Administrative Agent, in accordance with and to the extent required by Section 12.03 of the Credit Agreement. The Parent, the Borrower and each Loan Party further agree that any reasonable and documented out-of-pocket fees, costs and expenses paid by the Administrative Agent or any Lender to any restructuring advisor hired in connection with any workout, restructuring or similar negotiations in respect of the Credit Agreement and the Loans made thereunder shall be reimbursed in accordance with and subject to the obligations of the Parent and the Borrower set forth in Section 12.03 of the Credit Agreement.

[Signature Pages Follow]

Limited Waiver – 2019 Audited Financial Statements (Revolving Facility) – Page 5

IN WITNESS WHEREOF, the parties have caused this Agreement to be duly executed as of the date first above written.

PARENT:

Sundance Energy Inc.,

a Delaware corporation

By:  /s/ Eric McCrady

Name: Eric McCrady

Title:  CEO

BORROWER:

Sundance Energy, Inc.,

a Colorado corporation

By: /s/ Eric McCrady

Name: Eric McCrady

Title:  CEO

OTHER LOAN PARTIES:

Sea Eagle Ford, LLC

By: /s/ Eric McCrady

Name:  Eric McCrady

Title:  CEO

Armadillo E&P, Inc.

By: /s/ Eric McCrady

Name: Eric McCrady

Title:  CEO

Limited Waiver – 2019 Audited Financial Statements (Revolving Facility) – Signature Page

TORONTO DOMINION (TEXAS) LLC,  

as Administrative Agent

By: /s/ Hughroy Enniss

Name: Hughroy Enniss

Title: Authorized Signatory

Limited Waiver – 2019 Audited Financial Statements (Revolving Facility) – Signature Page

EX-10.20

Exhibit 10.20

LIMITED WAIVER

This LIMITED WAIVER (hereinafter referred to as this “Agreement”), dated as of May 11, 2020 (the “Execution Date”), but effective as of the Effective Date (hereinafter defined), is made by and among SUNDANCE ENERGY INC.,a Delaware corporation (“Parent”), SUNDANCE ENERGY, INC., a Colorado corporation (the “Borrower”), the other LOAN PARTIES hereto, the LENDERS party hereto, and MORGAN STANLEY CAPITAL ADMINISTRATORS INC., as administrative agent (in such capacity, the “Administrative Agent”).  Unless the context otherwise requires or unless otherwise expressly defined herein, capitalized terms used but not defined in this Agreement have the meanings assigned to such terms in the Credit Agreement (as defined below).

WITNESSETH:

WHEREAS, the Parent, the Borrower, the Administrative Agent and the lenders party thereto (the “Lenders”) are parties to that certain Amended & Restated Term Loan Credit Agreement, dated as of April 23, 2018 (as the same may have been amended, restated, amended and restated, supplemented or otherwise modified from time to time prior to the date hereof, the “Credit Agreement”);

WHEREAS, the Borrower has advised the Administrative Agent and the Lenders that (a) Deloitte & Touche LLP may include a going concern or like qualification or exception in its audit opinion with respect to the financial statements of the Parent and its Subsidiaries for the fiscal year ended December 31, 2019 (the “2019 Audited Financial Statements”) required to be delivered pursuant to Section 8.01(a) of the Credit Agreement as a result of the Borrower’s anticipated failure to comply with Section 9.01(b) of the Credit Agreement during the 2020 calendar year (the “Going Concern Qualification”) and (b) the Borrower will not deliver (i) the 2019 Audited Financial Statements required by Section 8.01(a) of the Credit Agreement, (ii) the certificate of the Financial Officer of the Parent as required by Section 8.01(c) of the Credit Agreement, (iii) the certificates of insurance as required by Section 8.01(e) of the Credit Agreement (iv) the production report and lease operating statements for the previous twelve (12) months as required by Section 8.01(m) of the Credit Agreement, and (v) the operating budget for the immediately succeeding twelve (12) months as required by Section 8.01(o) of the Credit Agreement (the foregoing, collectively, the “2019 Financial Deliverable Package”) to the Administrative Agent and each Lender within (A) with respect to the foregoing clauses (i) through (iv), ninety (90) days and (B) with respect to the foregoing clause (v), 120 days after the end of the fiscal year ended December 31, 2019 (the foregoing clauses (A) and (B), as applicable, the “Applicable 2019 Financial Statements Delivery Deadline”);

WHEREAS, the delivery of (a) the 2019 Audited Financial Statements accompanied by an auditor’s report containing the Going Concern Qualification and (b) the 2019 Financial Deliverable Package after the Applicable 2019 Financial Statements Delivery Deadline, in each case, would violate Sections 8.01(a),  (c),  (e),  (m) and (o)  of the Credit Agreement and would result in a Default or Event of Default under Section 10.01(e) of the Credit Agreement (any such Defaults or Events of Default being, collectively, the “Specified Defaults”);

WHEREAS, the Loan Parties have requested that the Lenders waive the Specified Defaults arising from such breaches of the terms of Sections 8.01(a),  (c),  (e),  (m) and (o) of the Credit Agreement;

WHEREAS, pursuant to Section 12.02(b) of the Credit Agreement, the Borrower, the other Loan Parties and the Required Lenders may waive, or consent to the Administrative Agent’s waiver of, certain provisions of the Credit Agreement and other Loan Documents pursuant to an agreement in writing; and

WHEREAS, pursuant to Section 12.02(b) of the Credit Agreement, the Borrower, the other Loan Parties and Lenders comprising the Required Lenders are willing to waive the Specified Defaults with respect

Limited Waiver – 2019 Audited Financial Statements (Term Facility) – Page 1

to the delivery of the 2019 Financial Deliverable Package on and subject to the terms and conditions set forth herein.

NOW, THEREFORE, for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

1. Limited Waiver.  Subject to the terms and conditions set forth herein, effective as of April 29, 2020 (the “Effective Date”), the Required Lenders hereby waive the Specified Defaults arising solely from (a) the Borrower’s delivery of an audit report of the Parent and its Subsidiaries containing the Going Concern Qualification with respect to the 2019 Audited Financial Statements and (b) the Borrower’s delivery of the 2019 Financial Deliverable Package after the Applicable 2019 Financial Statements Delivery Deadline. The limited waiver set forth in this Section 1 (the “Waiver”) is limited to the extent expressly set forth herein and no other terms, covenants or provisions of the Credit Agreement or any other Loan Document shall in any way be affected hereby.  The Waiver is granted only with respect to the Specified Defaults relating to the 2019 Financial Deliverable Package, and shall not apply to any financial statements or other deliverables for any other fiscal year or period, any other breach of the terms of the Credit Agreement, or any actual or prospective default or breach of any other provision of the Credit Agreement or any other Loan Document.  Other than with respect to the Going Concern Qualification and the Applicable 2019 Financial Statements Delivery Deadline, the Waiver does not waive any other requirement with respect to delivery of the 2019 Financial Deliverable Package.  The Waiver shall not in any manner create a course of dealing or otherwise impair the future ability of the Administrative Agent or the Lenders to declare a Default or Event of Default under or otherwise enforce the terms of the Credit Agreement or any other Loan Document with respect to any matter other than the Specified Defaults specifically and expressly waived in, and subject to the terms of, the Waiver.

2. Conditions Precedent.  This Agreement and the Waiver provided for in Section 1 shall become effective on the date when the following conditions are met:

(a) the Administrative Agent shall have received a counterpart signature page of this Agreement duly executed by each of the Parent, the Borrower, the other Loan Parties, the Administrative Agent and Lenders constituting the Required Lenders;

(b) the Administrative Agent shall have received a fully executed copy of a valid waiver under the Revolving Credit Agreement and the other Revolving Loan Documents of any default or event of default resulting from the Borrower delivering (i) the 2019 Audited Financial Statements with the Going Concern Qualification and (ii) the 2019 Financial Deliverable Package after the Applicable 2019 Financial Statements Delivery Deadline, in form reasonably satisfactory to the Administrative Agent;

(c) the Administrative Agent shall have received such other documents, instruments, opinions, certifications, undertakings, further assurances and other matters as the Administrative Agent may reasonably request; and

(d) the Borrower shall have paid all fees and expenses payable to the Administrative Agent and the Lenders (including the fees and expenses of counsel to the Administrative Agent) accrued to date shall have been paid in full to the extent invoiced prior to the date hereof, but without prejudice to the later payment of accrued fees and expenses not so invoiced.

Limited Waiver – 2019 Audited Financial Statements (Term Facility) – Page 2

3. Agreement to Amend the Credit Agreement.  In consideration of the Waiver, each Loan Party hereby agrees to enter into an amendment to the Credit Agreement with the Administrative Agent and the number of Lenders required by Section 12.02(b) of the Credit Agreement.  Such amendment shall amend certain provisions of the Credit Agreement in a manner to be mutually agreed by the Administrative Agent, the Loan Parties and such Lenders.  Failure of any Loan Party to enter into such amendment within fifteen (15) days from the Execution Date shall constitute an Event of Default under the Credit Agreement.   This Section 3 shall in all respects be subject to the Intercreditor Agreement dated as of April 23, 2018 (as amended, supplemented, restated or otherwise modified) by and among the Borrower, the other Grantors (as defined therein) party thereto, Toronto Dominion (Texas) LLC, as Senior Representative (as defined therein) and the
Administrative Agent, as Second Priority Representative (as defined therein), including Section 5.03 of the Intercreditor Agreement.

4. Ratification; Representations and Warranties.  Each Loan Party hereby (a) ratifies and affirms its obligations under, and acknowledges, renews and extends its continued liability under, each Loan Document to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect, except as expressly amended hereby and (b) represents and warrants to the Lenders that, as of the date hereof, after giving effect to the terms of this Agreement: (i) all of the representations and warranties contained in each Loan Document to which it is a party are true and correct in all material respects (unless already qualified by materiality in which case such applicable representation and warranty shall be true and correct), except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct in all material respects (unless already qualified by materiality in which case such applicable representation and warranty shall be true and correct) as of such specified earlier date and (ii) no Default or Event of Default has occurred and is continuing.

5. Counterparts.  This Agreement may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. Delivery of an executed counterpart of a signature page of this Agreement by fax, as an attachment to an email or other similar electronic means shall be effective as delivery of a manually executed counterpart of this Agreement.

6. No Oral Agreement.  THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS EXECUTED HEREWITH AND THEREWITH REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES HERETO AND THERETO AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

7. Severability.  Any provision of this Agreement held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof or thereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.

8. Governing Law.  THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES UNDER THIS AGREEMENT SHALL BE GOVERNED BY, CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

9. JURISDICTION; SERVICE OF PROCESS; JURY TRIAL WAIVER. BORROWER, PARENT AND THE OTHER LOAN PARTIES AGREE TO THE PROVISIONS OF SECTION 12.09(B)

Limited Waiver – 2019 Audited Financial Statements (Term Facility) – Page 3

(JURISDICTION); SECTION 12.09(C) (SERVICE OF PROCESS) AND SECTION 12.09(D) (JURY TRIAL WAIVER) OF THE CREDIT AGREEMENT AND SUCH PROVISIONS ARE INCORPORATED HEREIN, MUTATIS MUTANDIS, AS A PART HEREOF.

10. Claims. As additional consideration to the execution, delivery, and performance of this Agreement by the parties hereto and to induce the Administrative Agent and the Lenders to enter into this Agreement, each Loan Party represents and warrants that it does not know of any defenses, counterclaims or rights of setoff to the payment of any Secured Obligations to the Administrative Agent, Secured Parties or the Lenders.

11. WAIVER AND RELEASE. IN CONSIDERATION OF THE WAIVER HEREIN AND OTHER GOOD AND VALUABLE CONSIDERATION, THE RECEIPT AND SUFFICIENCY OF WHICH IS HEREBY ACKNOWLEDGED, EACH LOAN PARTY HEREBY WAIVES, REMISES, RELEASES, AND FOREVER DISCHARGES EACH LENDER, SECURED PARTY, AND THE ADMINISTRATIVE AGENT, THEIR RESPECTIVE PREDECESSORS AND ITS SUCCESSORS, ASSIGNS, AFFILIATES, SHAREHOLDERS, DIRECTORS, OFFICERS, ACCOUNTANTS, ATTORNEYS, EMPLOYEES, AGENTS, REPRESENTATIVES, AND SERVANTS (COLLECTIVELY, THE “RELEASED PARTIES”) OF, FROM AND AGAINST ANY AND ALL CLAIMS, ACTIONS, CAUSES OF ACTION, SUITS, PROCEEDINGS, CONTRACTS, JUDGMENTS, DAMAGES, ACCOUNTS, RECKONINGS, EXECUTIONS, AND LIABILITIES WHATSOEVER OF EVERY NAME AND NATURE, WHETHER KNOWN OR UNKNOWN, WHETHER OR NOT WELL FOUNDED IN FACT OR IN LAW, AND WHETHER IN LAW, AT EQUITY, OR OTHERWISE, WHICH THE UNDERSIGNED EVER HAD OR NOW HAS FOR OR BY REASON OF ANY MATTER, CAUSE, OR ANYTHING WHATSOEVER TO THIS DATE RELATING TO OR ARISING OUT OF THE LOANS, OR ANY OF THEM, OR ANY OF THE LOAN DOCUMENTS, INCLUDING WITHOUT LIMITATION ANY ACTUAL OR ALLEGED ACT OR OMISSION OF ANY OF THE RELEASED PARTIES WITH RESPECT TO THE LOANS, OR ANY OF THEM, OR ANY OF THE LOAN DOCUMENTS, OR ANY LIENS OR COLLATERAL IN CONNECTION THEREWITH, OR THE ENFORCEMENT OF ANY OF SUCH LENDER’S OR SECURED PARTY’S OR THE ADMINISTRATIVE AGENT’S RIGHTS OR REMEDIES THEREUNDER.  THE TERMS OF THIS WAIVER AND RELEASE SHALL SURVIVE THE TERMINATION OF THIS AGREEMENT, THE LOANS, OR THE LOAN DOCUMENTS AND SHALL REMAIN IN FULL FORCE AND EFFECT AFTER THE TERMINATION THEREOF.

12. No Waiver. Borrower agrees that other than the Specified Defaults, no Event of Default and no Default has been waived or remedied by the execution of this Agreement by the Administrative Agent and the Lenders, and any such Default or Event or Default heretofore arising and currently continuing shall continue after the execution and delivery hereof.  Other than with respect to the Waiver specifically set forth herein, nothing contained in this Agreement nor any past indulgence by the Administrative Agent or the Lenders, nor any other action or inaction on behalf of the Administrative Agent or the Lenders (i) shall constitute or be deemed to constitute a waiver of any Defaults or Events of Default which may exist under the Credit Agreement or the other Loan Documents, or (ii) shall constitute or be deemed to constitute an election of remedies by the Administrative Agent or the Lenders or a waiver of any of the rights or remedies of the Administrative Agent or the Lenders provided in the Credit Agreement or the other Loan Documents or otherwise afforded at law or in equity.

13. Headings. Section headings used herein are for convenience of reference only, are not part of this Agreement and shall not affect the construction of, or be taken into consideration in interpreting, this Agreement.

Limited Waiver – 2019 Audited Financial Statements (Term Facility) – Page 4

14. Fees and Expenses. The Parent and the Borrower hereby agree, jointly and severally, to reimburse the Administrative Agent and the Lenders for all reasonable and documented out-of-pocket costs and expenses incurred in connection with the development, preparation and execution of this Agreement, including the reasonable and documented fees, disbursements and other charges of one primary counsel to the Administrative Agent, in accordance with and to the extent required by Section 12.03 of the Credit Agreement. The Parent, the Borrower and each Loan Party further agree that any reasonable and documented out-of-pocket fees, costs and expenses paid by the Administrative Agent or any Lender to any restructuring advisor hired in connection with any workout, restructuring or similar negotiations in respect of the Credit Agreement and the Loans made thereunder shall be reimbursed in accordance with and subject to the obligations of the Parent and the Borrower set forth in Section 12.03 of the Credit Agreement.

[Signature Pages Follow]

Limited Waiver – 2019 Audited Financial Statements (Term Facility) – Page 5

IN WITNESS WHEREOF, the parties have caused this Agreement to be duly executed as of the date first above written.

PARENT:

Sundance Energy Inc.,

a Delaware corporation

By: /s/ Eric McCrady

Name: Eric McCrady

Title:  CEO

BORROWER:

Sundance Energy, Inc.,

a Colorado corporation

By: /s/ Eric McCrady

Name: Eric McCrady

Title:  CEO

OTHER LOAN PARTIES:

Sea Eagle Ford, LLC

By: /s/ Eric McCrady

Name:  Eric McCrady

Title:  CEO

Armadillo E&P, Inc.

By: /s/ Eric McCrady

Name: Eric McCrady

Title:  CEO

Limited Waiver – 2019 Audited Financial Statements (Term Facility) – Signature Page

MORGAN STANLEY CAPITAL

ADMINISTRATORS INC.,  

as Administrative Agent

By: /s/ Parker Corbin

Name: Parker Corbin

Title:  Authorized Signatory

Limited Waiver – 2019 Audited Financial Statements (Term Facility) – Signature Page

MORGAN STANLEY CAPITAL GROUP INC.,  

as a Lender

By: /s/ Parker Corbin

Name: Parker Corbin

Title: Vice President

Limited Waiver – 2019 Audited Financial Statements (Term Facility) – Signature Page

Apollo Moultrie Credit Fund, L.P., as a Lender

By: Apollo Moultrie Credit Fund Advisors, L.P., its general partner

By: Apollo Moultrie Capital Management, LLC, its general partner

By: /s/Joseph D. Glatt

Name: Joseph D. Glatt

Title: Vice President

MPI (London) Limited, as a Lender

By: Apollo TRF MP Management, LLC, its sub advisor

By: Apollo Capital Management, L.P., its sole member

By: Apollo Capital Management GP, LLC, its general partner

By: /s/ Joseph D Glatt

Name: Joseph D. Glatt

Title: Vice President

Apollo Atlas Master Fund, LLC, as a Lender

By: Apollo Atlas Management, LLC, its investment Manager

By: /s/ Joseph D Glatt

Name: Joseph D. Glatt

Title: Vice President

Apollo Tower Credit Fund, L.P, as a Lender

By: Apollo Tower Credit Advisors, LLC, its general partner

By: /s/ Joseph D Glatt

Name: Joseph D. Glatt

Title: Vice President

Apollo TR Enhanced Levered Yield LLC, as a Lender 

By: Apollo Total Return Enhanced Management LLC, its investment manager

By: /s/ Joseph D Glatt

Name: Joseph D. Glatt

Title: Vice President

Limited Waiver – 2019 Audited Financial Statements (Term Facility) – Signature Page

Apollo Union Street Partners, L.P., as a Lender 

By: Apollo Union Street Advisors, L.P., its general partner

By: Apollo Union Street Capital Management, LLC, its general partner

By: /s/ Joseph D Glatt

Name: Joseph D. Glatt

Title: Vice President

AMISSIMA DIVERSIFIED INCOME ICAV,

an Umbrella Irish Collective Asset-Management Vehicle with Segregated Liability between its Sub-Funds, acting in respect of its Sub-Fund Amissima Assicurazioni Multi-Credit Strategy Fund, as a Lender

By: Apollo Management International LLP, solely in its capacity as Portfolio Manager and not in its individual corporate capacity

By: AMI (Holdings), LLC, its member

By: /s/ Joseph D. Glatt

Name: Joseph D. Glatt

Title: Vice President

Apollo Kings Alley Credit Fund, L.P., as a Lender 

By: Apollo Kings Alley Credit Advisors, L.P., its general partner

By: Apollo Kings Alley Credit Capital Management, LLC, its general partner

By: /s/ Joseph D. Glatt

Name: Joseph D. Glatt

Title: Vice President

Limited Waiver – 2019 Audited Financial Statements (Term Facility) – Signature Page

TRANQUILIDADE DIVERSIFIED INCOME ICAV,

an Umbrella Irish Collective Asset-Management Vehicle with Segregated Liability between its Sub-Funds,

acting in respect of its Sub-Fund, Tranquilidade Multi-Credit Strategy Fund, as a Lender

By: Apollo Management International LLP,

its portfolio manager, solely in its capacity as Portfolio Manager and not in its individual corporate capacity 

By: AMI (Holdings), LLC, its member

By: /s/ Joseph D. Glatt

Name: Joseph D. Glatt

Title: Vice President

Apollo TR Opportunistic Ltd., as a Lender

By: Apollo Total Return Enhanced Management LLC, its investment manager

And by: Apollo Total Return Management, its investment manager

By: /s/ Joseph D. Glatt

Name: Joseph D. Glatt

Title: Vice President

Apollo Tactical Value SPN Investments, L.P., as a Lender

By: Apollo Tactical Value SPN Advisors (APO DC), L.P., its general partner

By: Apollo Tactical Value SPN Capital Management (APO DC-GP), LLC, its general partner

By: /s/ Joseph D. Glatt

Name: Joseph D. Glatt

Title: Vice President

Limited Waiver – 2019 Audited Financial Statements (Term Facility) – Signature Page

AG Energy Funding, LLC, 

as a Lender

By: /s/ Todd Dittman

Name: Todd Dittman

Title: Authorized Person

Limited Waiver – 2019 Audited Financial Statements (Term Facility) – Signature Page

Ares Capital Corporation

By: /s/ Josh Bloomstein

Name: Josh Bloomstein

Title: Authorized Signatory

CION Ares Diversified Credit Fund

By:  /s/ Josh Bloomstein

Name: Josh Bloomstein

Title: Authorized Signatory

Ares Credit Strategies Insurance Dedicated Fund Series of SALI Multi-Series Fund, L.P.

By:  Ares Management LLC, its investment subadvisor

By:  Ares Capital Management LLC, as subadvisor

By: /s/ Josh Bloomstein

Name: Josh Bloomstein

Title: Authorized Signatory

Ares Direct Finance I LP

By: Ares Capital Management LLC, its investment manager

By: /s/ Josh Bloomstein

Name: Josh Bloomstein

Title: Authorized Signatory

Limited Waiver – 2019 Audited Financial Statements (Term Facility) – Signature Page

EX-21.1

Exhibit 21.1

SUBSIDIARIES OF SUNDANCE ENERGY INC.

Sundance Energy, Inc., a Colorado corporation

Sundance Energy Australia Ltd, an Australian limited company

SEA Eagle Ford, LLC, a Texas limited liability company

Armadillo E&P, Inc., a Delaware corporation

New Standard Energy PEL570 Ltd, an Australian limited company

EX-31.1

Exhibit 31.1

CERTIFICATE OF CHIEF EXECUTIVE OFFICER

I, Eric P. McCrady, certify that:

1.I have reviewed this Annual Report on Form 10-K for the fiscal year ended December 31, 2019, of Sundance Energy Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 14, 2020/s/ Eric P. McCrady

Eric P. McCrady

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATE OF CHIEF FINANCIAL OFFICER

I, Cathy L. Anderson, certify that:

1.I have reviewed this Annual Report on Form 10-K for the fiscal year ended December 31, 2019, of Sundance Energy Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 14, 2020/s/ Cathy L. Anderson

Cathy L. Anderson

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

The undersigned hereby certifies, for the purposes of 18 U.S.C. Section 1350, in his capacity as Chief Executive Officer of Sundance Energy Inc. (the “Company”), that, to such person’s knowledge:

(a)the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2019, as filed with the Securities and Exchange Commission (the “Report”), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(b)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: May 14, 2020

/s/ Eric P. McCrady

Eric P. McCrady
Chief Executive Officer

This certification is not deemed to be “filed” for purposes of section 18 of the Securities Exchange Act of 1934, or otherwise subject to the liability of that section. This certification is not deemed to be incorporated by reference into any filing under the Securities Act of 1933 or Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates it by reference.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

The undersigned hereby certifies, for the purposes of 18 U.S.C. Section 1350, in her capacity as Chief Financial Officer of Sundance Energy Inc. (the “Company”), that, to such person’s knowledge:

(a)the Annual Report on Form 10-K of the Company for the fiscal year ended December 31, 2019, as filed with the Securities and Exchange Commission (the “Report”), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(b)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: May 14, 2020

/s/ Cathy L. Anderson

Cathy L. Anderson
Chief Executive Officer

This certification is not deemed to be “filed” for purposes of section 18 of the Securities Exchange Act of 1934, or otherwise subject to the liability of that section. This certification is not deemed to be incorporated by reference into any filing under the Securities Act of 1933 or Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates it by reference.

EX-99.1

Exhibit 99.1

SUNDANCE ENERGY, INC.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

December 31, 2019

/s/ Stephen E. Gardner

Stephen E. Gardner, P. E.

Colorado License No. 44720

Managing Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F‑1580

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

	TBPE REGISTERED ENGINEERING FIRM F‑1580
	633 17TH STREET    SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339‑8110

February 13, 2020

Sundance Energy, Inc.

1050 17th Street, Suite 700

Denver, CO, 80265

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of Sundance Energy, Inc.  (Sundance) as of December 31, 2019.  The subject properties are located in the state of Texas.  The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).  Our third party study, completed on February 13, 2020 and presented herein, was prepared for public disclosure by Sundance in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and gas reserves of Sundance as of December 31, 2019.

The estimated reserves and future net income amounts presented in this report, as of December 31,  2019 are related to hydrocarbon prices.  The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12‑month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations.  Actual future prices may vary considerably from the prices required by SEC regulations.  The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received;  therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.  The results of this study are summarized as follows.

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE  800,  350  7TH  AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799	FAX (403) 262-2790

Sundance Energy, Inc.

February 13, 2020

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

Sundance Energy, Inc.

As of December 31, 2019

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Reserves
Oil/Condensate – Mbbl		15,997		104		46,687		62,788
Plant Products – Mbbl		4,022		0		14,112		18,134
Gas – MMcf		26,870		60		93,974		120,904
MBOE		24,497		114		76,461		101,072
Income Data ($M)
Future Gross Revenue	$	1,007,888	$	5,861	$	2,945,370	$	3,959,119
Deductions		427,580		2,183		1,961,289		2,391,052
Future Net Income (FNI)	$	580,308	$	3,678	$	984,081	$	1,568,067
Discounted FNI @ 10%	$	364,602	$	1,982	$	386,009	$	752,593

Liquid hydrocarbons are expressed in standard 42 U. S. gallon barrels and shown herein as thousands of barrels (Mbbl).  All gas volumes are reported on an “as sold” basis expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of 60 degrees Fahrenheit and 14.65 psia. The proved gas volumes presented herein include certain volumes of fuel gas consumed in operations as reserves.  However, the equivalent value of these fuel volumes is excluded from the cash flows. The net reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent.  MBOE means thousand barrels of oil equivalent.  In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIESTM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton.  The program was used at the request of Sundance.  Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized.  Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding.  The rounding differences are not material.

The future gross revenue is after the deduction of production taxes.  The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, development costs, and certain abandonment costs net of salvage.  The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Sundance Energy, Inc.

February 13, 2020

Page 3

Liquid hydrocarbon reserves account for approximately 92 percent and gas reserves account for the remaining 8 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly.  Future net income was discounted at four other discount rates which were also compounded monthly.  These results are shown in summary form as follows.

	Discounted Future Net Income ($M)
	As of December 31, 2019
Discount Rate	Total
Percent	Proved
8	$	854,268
9	$	800,993
12	$	668,221
15	$	566,326

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4‑10(a).  An abridged version of the SEC reserves definitions from 210.4‑10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report.  The proved developed non-producing reserves included herein consist of the shut-in status category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.”  All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  At Sundance’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Sundance Energy, Inc.

February 13, 2020

Page 4

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.”  The proved reserves included herein were estimated using deterministic methods.  The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.  For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”  Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks.  Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Sundance’s operations may be subject to various levels of governmental controls and regulations.  These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing,  the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time.  Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Sundance owns an interest; however, we have not made any field examination of the properties.  No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations.  The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4‑10(a).  The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures.  These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy.  These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves.  Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Sundance Energy, Inc.

February 13, 2020

Page 5

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator.  When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves.  If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator.  Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported.  For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.”  The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.”  The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.”  All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available.  Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods or by analogy.  Approximately 80 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods including decline curve analysis, which utilized extrapolations of historical production and pressure data available through December 2019 in those cases where such data were considered to be definitive.  The data utilized in this analysis were furnished to Ryder Scott by Sundance and were considered sufficient for the purpose thereof.  The remaining 20 percent of the proved producing reserves were estimated by analogy or a combination of methods.  These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

All of the proved developed non-producing reserves included herein were based on the historical performance of the wells prior to being shut-in.  All of the proved undeveloped reserves included herein were estimated by analogy, based on data furnished to Ryder Scott by Sundance that were available through December 2019.  As part of this analysis, reservoir simulation was used to help estimate well interference associated with the planned future development spacing.  The data utilized from the analogues and incorporated into our analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.  Under the SEC regulations 210.4‑10(a)(22)(v) and (26), proved reserves

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Sundance Energy, Inc.

February 13, 2020

Page 6

must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined.  While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Sundance has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation.  In preparing our forecast of future proved production and income, we have relied upon data furnished by Sundance with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, development costs, development plans,  abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological cross-sections, and base maps.  Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Sundance.  We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein.  The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.”  In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data.  If no production decline trend has been established, future production rates and decline trends were based on analogous wells.

The historical performance of shut-in wells or the initial performance of analogous wells were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing.  For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Sundance.  Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production.  Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, well completions, and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Sundance Energy, Inc.

February 13, 2020

Page 7

artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12‑month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

Sundance furnished us with the above mentioned average prices in effect on December 31, 2019.  These initial SEC hydrocarbon prices were determined using the 12‑month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold.  These benchmark prices are prior to the adjustments for differentials as described herein.  The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering fees, oil transportation fees, and/or distance from market, referred to herein as “differentials.”  The differentials used in the preparation of this report were furnished to us by Sundance and accepted as factual data.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
	Oil/Condensate	WTI Cushing	$55.69/bbl	$56.05/bbl
United States	NGLs	WTI Cushing	$55.69/bbl	$16.35/bbl
	Gas	Henry Hub	$2.58/MMBTU	$2.75Mcf

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by Sundance, based on their operating expense reports, and include only those costs directly applicable to the leases or wells.  The operating costs include a portion of general and administrative costs allocated directly to the leases and wells.  The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Sundance Energy, Inc.

February 13, 2020

Page 8

operating cost data used by Sundance.  No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Sundance and are based on authorizations for expenditure for the proposed work or actual costs for similar projects.  The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs.  The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material.  The estimates of the net abandonment costs furnished by Sundance were accepted without independent verification.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Sundance’s plans to develop these reserves as of December 31, 2019.  The implementation of Sundance’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Sundance’s management.  As the result of our inquiries during the course of preparing this report, Sundance has informed us that the development activities included herein have been subjected to and received the internal approvals required by Sundance’s management at the appropriate local, regional and/or corporate level.  In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Sundance.  Sundance has provided written documentation supporting their commitment to proceed with the development activities as presented to us.  Additionally, Sundance has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans.  While these plans could change from those under existing economic conditions as of December 31, 2019, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Sundance were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937.  Ryder Scott is employee-owned and maintains offices in Houston,  Texas;  Denver,  Colorado; and Calgary,  Alberta, Canada.  We have approximately eighty engineers and geoscientists on our permanent staff.  By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue.  We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients.  This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations.  Many of our staff have authored or co-authored technical papers on the subject of reserves related topics.  We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Sundance Energy, Inc.

February 13, 2020

Page 9

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.  Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training.  Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to Sundance.  Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott.  The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Sundance.

We have provided Sundance with a digital version of the original signed copy of this report letter.  In the event there are any differences between the digital version included in filings made by Sundance and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices.  Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPE Firm Registration No. F‑1580
	/s/ Stephen E. Gardner
	[SEAL]
	Stephen E. Gardner, P.E.
	Colorado License No. 44720
	Managing Senior Vice President
SEG (FWZ)/pl

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide.  Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation.  For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude).  He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is also a member of the Society of Petroleum Engineers and a former chairman for the Denver Chapter of the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills.  As part of his 2019 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference in Houston, Texas which covered a variety of reserves topics including data analytics, unconventional resource issues, SEC comment letter trends, and others.  In addition, Mr. Gardner attended the 2019 SPEE conference held at Lake Louise, Alberta, Canada, various local SPEE technical seminars, URTeC, and other internal company training courses throughout the year covering topics such as analysis techniques for unconventional reservoirs, ethics, regulatory issues, reserves evaluation, and more.

Based on his educational background, professional training and more than 14 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4‑10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA).  The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4‑10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K.  The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”.  The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010.  Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4‑10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC.  The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods.  Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.  Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids.  Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations.  Petroleum accumulations are considered as either conventional or unconventional

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.  Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits.  These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4‑10(a)(26) defines reserves as follows:

Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances 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.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results).  Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4‑10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and 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, and 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

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4‑10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs.  Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4‑10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4‑10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category 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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals that are open at the time of the estimate but which have not  yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4‑10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category 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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS

XML

ASSETS HELD FOR SALE (Tables)

12 Months Ended

Dec. 31, 2019

ASSETS HELD FOR SALE.

Schedule of assets held for sale

The consolidated balance sheet includes assets and liabilities related to assets held for sale, comprised of the following as of December 31, 2018 (in thousands):

Assets held for sale:	December 31, 2018
Oil and gas properties - Dimmit County, Texas	$	23,471
Liabilities related to assets held for sale:
Asset retirement obligations		(193)
Net assets held for sale	$	23,278

XML

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2019

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Preparation

Basis of Preparation

Prior to the Redomiciliation, SEAL reported its consolidated financial statements in accordance with International Financial Reporting Standards (“IFRS”).  Following the Redomiciliation, the Company retroactively transitioned to accounting principles generally accepted in the United States of America (“GAAP”) and applied GAAP retrospectively for all prior periods presented.  The Company’s consolidated financial statements have been prepared in accordance with GAAP and Securities and Exchange Commission (“SEC”) rules and regulations, and include the accounts of the Company and its consolidated subsidiaries.  All intercompany balances and transactions have been eliminated in consolidation.

Going Concern

Going Concern

The accompanying consolidated financial statements are prepared in accordance with GAAP applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.

In March 2020, the prevailing market price for oil prices decreased from an average of approximately $60 per barrel for December 2019 to less than $20 per barrel.  As described in Note 7, the Company is required to meet certain financial and non-financial covenants as a condition to its credit facilities.  Under the Company’s second lien term loan (“Term Loan”), the Company is required to maintain an Asset Coverage Ratio of not less than 1.5 to 1.0, which is calculated as the value of its Total Proved Reserves (PV 9%)   based upon the forward month prices quoted on the NYMEX, adjusted for basis differentials or premiums and transportation costs and to reflect the Company’s commodity hedging agreements then in effect to Total Debt. The value of the Company’s oil and gas reserves, (including “Total Proved Reserves” as described in the Term Loan agreement) is highly sensitive to future commodity prices.  The Company regularly enters into commodity derivative contracts to protect the cash flows associated with the Company’s proved developed producing wells and to provide supplemental liquidity to mitigate decreases in revenue due to reductions in commodity prices.

Based on the Company’s historical experience, in periods of sustained low commodity prices, the prevailing market price for oil and gas services has also decreased, including the types of costs included in the Company’s lease operating expenses, drilling costs, completion costs and costs to equip its wells.  Subsequent to December 31, 2019, the Company renegotiated pricing with a number of its vendors and entered into contractual arrangements with drilling and completion service providers at reduced costs relative to the assumed costs in the Company’s year-end reserve report.  Additionally, the Company has changed its field operating procedures in response to the material drop in oil prices which further reduces its cost structure relative to that assumed in the Company’s year-end reserve report.  The Company continues to work to secure additional costs reductions.

Commodity hedging that the Company currently has in place, combined with cost reductions are expected to reduce the impact of recent commodity price declines.  However, given the recent decline and continued volatility of commodity prices, the Company cannot assert that it is probable that it will comply with the Asset Coverage Ratio and other covenants within the next 12 months following the date of this report.  A breach of any covenant in Company’s credit agreements will result in default under both the Company’s Term Loan and cross default on the Company’s revolving credit facility, after any applicable grace period, which could result in acceleration of the amounts outstanding under the credit facilities by the Company’s lenders.  

Additionally, the Company’s credit facilities contain the requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception.  The issuance of these consolidated financial statements with the accompanying audit opinion constitutes a default under the senior secured revolving credit facility (“Revolving Facility”) and Term Loan.  The Company obtained waivers from its Revolving Facility and Term Loan lenders, executed on May 8, 2020 and May 11, 2020, respectively, to waive the event of default arising from the inclusion of the going concern explanatory paragraph included in the audit report for the year ended December 31, 2019 and other related defaults.  These waivers were effective April 29, 2020, subject to the conditions set forth in the waivers.  As described in Note 15, in consideration for the waiver under our Revolving Facility, the Company agreed to certain limitations on its ability to effect draws under the revolving credit facility until such time as the second quarter 2020 borrowing base redetermination has been completed.  In addition, in consideration for waiver with respect to the Term Loan, the Company agreed to amend certain covenants in the Term Loan, as to be mutually agreed with the Term Loan lenders, within 15 days from the execution date.  The waiver under our Revolving Facility also provides for a right to require corresponding amendments of that facility manner, as requested by the administrative agent in its discretion, within 90 days from the execution date. Failure to enter into such amendments with respect to our Term Loan within 15 days (or a similar amendment with respect to our Revolving Facility on the date the Term Loan is amended) would constitute an event of default under the credit facilities, in which case the amounts outstanding under the credit facilities could be accelerated and become immediately due and payable.  While management believes that it will finalize such amendments within the required time frame, there can be no assurance that management’s efforts will result in any finalizing these amendments or the ultimate terms of any such amendments. 

Although the Company has obtained these waivers, there is no guarantee that its lenders will agree to waive events of default or potential events of default in the future.    In the event that some or all of the amounts outstanding under its credit facilities are accelerated and become immediately due and payable, the Company does not have sufficient liquidity to repay such outstanding amounts. These conditions and events raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. 

Management is currently pursuing and evaluating several plans to mitigate the conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern, which include the following:

· Renegotiating pricing with a number of its operating expenditure vendors and has realized lower drilling and completion costs on recent development relative to the costs incurred in 2019 and the assumed costs in the Company’s year-end reserve report.

· Negotiating with its lenders to obtain waivers for potential failures in covenants.

· Pursuing further changes to its cost structure in response to the material drop in oil prices. 

· Pursuing additional costs savings with its vendors and other internal costs, including a reduction in force, which occurred in early May 2020.

There can be no assurance that sufficient liquidity can be obtained to meet the outstanding obligations of the Company, if repayment of its credit facilities is accelerated. As a result, and given the recent declines and continued volatility in commodity prices, the Company has concluded that management’s plans do not alleviate substantial doubt about the Company’s ability to continue as a going concern.

The consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.  Items subject to such estimates and assumptions include (i) oil and natural gas reserves; (ii) impairment tests of long-lived assets; (iii) depreciation, depletion and amortization; (iv) asset retirement obligations; (v) assignment of fair value and allocation of purchase price in connection with business combinations; (vi) income taxes; (vii) accrued liabilities; (viii) valuation of derivative instruments; and (ix) accrued revenue and related receivables.  Although management believes these estimates are reasonable, actual results could differ from these estimates.  Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of lower commodity prices, may have a significant negative impact to the Company’s business, financial condition, results of operations and cash flows.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less.

Accounts Receivable Trade and Other

Accounts Receivable Trade and Other

The Company has letters of credit in place with certain of its purchasers, which the Company could draw upon in the event the purchaser defaults.  Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts.  For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.  The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability.  At December 31, 2019 and 2018, the Company had no allowance for doubtful accounts.  At December 31, 2019 and 2018 the accounts receivable trade and other included the following (in thousands):

	December 31,
	2019		2018
Oil, natural gas and NGL sales	$	18,211	$	16,408
Joint interest owners		260		584
Commodity hedge contract receivables and other		4,342		4,257
Receivable due from buyer (Dimmit County oil and gas properties)		4,207		—
Total accounts receivable trade and other	$	27,020	$	21,249

Concentration of Credit Risk

Concentration of Credit Risk

The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries.  The creditworthiness of customers and other counterparties is subject to continuing review.

As of December 31, 2019, the Company had a receivable from one purchaser, a large midstream company and production purchaser, of $13.2 million that accounted for 73% of total accounts receivable for oil, natural gas and NGL sales.  As of December 31, 2019, the Company has a long-term contract in place with this customer, under which the Company is subject to minimum revenue commitments for gathering, processing, transportation and marketing services totaling $54.3 million through 2022.

As of December 31, 2018, the Company had a receivable due from the same customer of $12.1 million that accounted for 74% of total accounts receivable for oil, natural gas and NGL sales.

The following tables present the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 2019 and 2018:

Year Ended December 31, 2019
Purchaser A	60%
Purchaser B	21%
Year Ended December 31, 2018
Purchaser A	34%
Purchaser B	26%
Purchaser C	23%

The Company owns nearly 100% of the working interest in the majority of the wells that it operates; therefore, joint interest billing receivables, and the related credit risk, is minimal.  Further, if payment is not made by a working interest partner, the Company can withhold future payments of revenue to that working interest partner.

Oil and Gas Properties

Oil and Gas Properties

Proved.  The Company follows the successful efforts method of accounting for its oil and gas properties.  Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a unit-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively.  Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful.  For the years ended December 31, 2019 and 2018, the Company recorded depletion, depreciation and amortization expense related to proved oil and gas properties of $91.4 million and $62.1 million, respectively.

The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable.  The impairment test compares undiscounted future net cash flows of the assets to the assets’ net book value.  If the net book value exceeds future net cash flows, then the cost of the property is written down to fair value.  Fair value for oil and gas properties is generally determined based on discounted future net cash flows.  There was no impairment expense during the years ended December 31, 2019 or 2018.

Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income.  Gains or losses from the disposal of complete units of depreciable property are recognized in results of operations.

For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Interest is capitalized until the asset is ready for service.  

Unproved.  Unproved properties consist of costs to acquire undeveloped leases as well as purchases of unproved reserves.  Capitalized costs of unproved property are transferred to proved property when related proved reserves are determined and depleted on a unit-of-production basis.The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage.  There was no unproved property impairment expense during the years ended December 31, 2019 and 2018.

Exploratory.  Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage, are expensed as incurred.  Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs.  Amounts of seismic costs capitalized are based on only those blocks of data used in determining developmental well locations.  To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.

Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves.  If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense.  Costs incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (i) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.  If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed.

Other Property and Equipment

Other Property and Equipment

Other property and equipment consists of office furniture, computer equipment, software and vehicles, which are stated at cost and depreciated using the straight-line method over their estimated useful lives ranging from 3 to 20 years. Leasehold improvements are depreciated over the shorter of the lease term or the estimated useful life of the improvement. Costs that do not extend the useful lives of property and equipment are charged to expense as incurred.  Major replacements, renewals and betterments are capitalized.

Other Current Assets

Other Current Assets

Other current assets consist of oil and equipment inventory and prepaid expenses.  The Company records oil and equipment inventory at the lower of cost or net realizable value.  Prepaid expenses are recorded at cost.

Assets Held for Sale

Assets Held for Sale

Oil and gas properties expected to be sold or otherwise disposed of within one year are classified as assets held for sale and included as current assets in the consolidated balance sheets are separately presented in the accompanying consolidated balance sheets at the lower of carrying value or fair value less estimated costs to sell (“FVLCS”).   The Company continued to extract oil and gas from the assets while held for sale, although in accordance with accounting standards, it did not record DD&A for assets classified as held for sale.

Debt Issuance Costs

Debt Issuance Costs

Debt issuance costs related to the Company’s Term Loan are included as a deduction from the carrying amount of the credit facility in the consolidated balance sheets and are amortized to interest expense using the effective interest method over the term of the related debt.  Debt issuance costs related to the Revolving Facility are included in other long-term assets and are amortized to interest expense on a straight-line basis over the term of the facility.

Derivative Instruments

Derivative Instruments

The Company enters into derivative contracts, primarily swaps, and costless collars, to manage its exposure to commodity price risk, and follows Financial Accounting Standards Board (“FASB”) ASC Topic 815, Derivatives and Hedging, to account for its derivative financial instruments.  The Company also has interest rate swaps contracts to mitigate its exposure to the floating interest rate charged on its long-term debt.  In addition, the Company historically entered into foreign exchange derivatives to protect cash flows generated during a common stock equity raise in 2018 from changes in currency fluctuations.  Prior to the Company’s redomiciliation, the majority of its common stock issuances were denominated in Australian dollars.  All derivative instruments, other than those that meet the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value.  Gains and losses from changes in the fair value of derivative instruments are recognized immediately in operations. The Company does not apply hedge accounting to any of its outstanding derivative instruments and, as a result, changes in derivative fair values are recognized as an unrealized gain or loss in operations.

Cash flows from derivatives used to manage commodity price risk and interest rate risk are classified in operating activities along with the cash flows of the underlying hedged transactions.  Cash flows from derivatives used to manage foreign currency risk are classified in financing activities.  The Company does not enter into derivative instruments for speculative or trading purposes.  Refer to the Note 10 and Note 11 for further information.

Asset Retirement and Environmental Obligations

Asset Retirement and Environmental Obligations

Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition as specified by the lease or regulatory agencies.  The Company follows FASB ASC Topic 410, Asset Retirement and Environmental Obligations, to determine its asset retirement obligation amounts by calculating the present value of the estimated future cash outflows associated with its plug and abandonment obligations.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is spud or acquired), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount.  The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a unit-of-production basis over the proved developed reserves of the related asset.  Revisions typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells, and such revisions result in adjustments to the related capitalized asset and corresponding liability.

Revenue Recognition

Revenue Recognition

The Company recognizes revenue from the sale of oil, natural gas and NGLs in the period that the performance obligations are satisfied.  The Company’s performance obligations are primarily comprised of the delivery of oil, natural gas or NGLs at a delivery point.  Each barrel of oil, MMBtu of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated.  Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer through delivery of oil, natural gas and NGLs, which differs depending on the contractual terms of each of the Company’s arrangements.

Transfer of control drives the presentation of gathering, processing, transportation, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations, and requires significant judgements. Fees and other deductions incurred prior to control transfer are recorded within the gathering, processing and transportation expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of oil, gas, and NGLs production revenue. The Company has three types of contracts under which oil, gas, and NGLs production revenue is generated, which are summarized below:

1) The Company sells oil production at or near the wellhead and receives an agreed-upon index price from the purchaser, net of basis, quality, and transportation differentials. Under this arrangement, control transfers at or near the wellhead.

2) The Company sells unprocessed natural gas to a midstream processor at the wellhead or inlet of the midstream processing facility. The midstream processor gathers and processes the raw natural gas stream and remits proceeds to the Company from the ultimate sale of the processed NGLs and residue natural gas to third parties. In such arrangements, the midstream processor obtains control of the product at the wellhead or inlet of the facility and is considered the customer. Proceeds received for unprocessed natural gas under these arrangements are reflected as natural gas or NGL revenue and are recorded net of transportation and processing fees incurred by the midstream processor after control has transferred.

3) The Company has certain processing arrangements that include the delivery of unprocessed natural gas to the inlet of a midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind. For the NGLs, control is deemed to have transferred after it has been separated from the residue gas.  The midstream processor remits payment to the Company based on the proceeds it generates from selling the NGLs to other third parties.  The Company recognizes the proceeds as NGL revenue.  For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. The Company recognizes proceeds from the downstream contracts as natural gas revenue.  Under these processing arrangements for both NGL and natural gas, the Company recognizes gathering, transportation, and processing fees incurred prior to control transfer as expense recorded within the gathering, processing and transportation expense line item on the accompanying consolidated statements of operations.

Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received within two months after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, metered sales volumes, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Variances between estimates and the actual amounts received are recorded in the month payment is received, but have not historically been material.  Estimated revenue due to the Company is recorded within accounts receivable trade and other on the accompanying consolidated balance sheets until payment is received. The accounts receivable balance from contracts with customers within the accompanying balance sheet as of December 31, 2019 and 2018 was $18.2 million and $16.4 million, respectively. 

Stock-Based Compensation

Stock-Based Compensation

Equity - Settled Compensation

Prior to the effectiveness of the Redomiciliation, SEAL issued restricted share units (“RSUs”) pursuant to its Long Term Incentive Plan (the “Plan”) to motivate management and employees to make decisions benefiting long-term value creation, retain management and employees and reward the achievement of the Company’s long-term goals.  The RSUs are generally settled based on the achievement of certain goals established by the Compensation Committee and approved by the Board. There were three types of RSU awards:

1) Time based vesting: The fair value of time-based RSUs is determined based on the price of the underlying equity on the date of grant and the expense is recognized over the vesting period.

2) Total shareholder return (“TSR”) or absolute total share-holder return (“ATSR”):  Certain RSUs vest based on the achievement of metrics related to the a three‑year ATSR or TSR as compared to a peer group or a market index. A Monte Carlo simulation model to determine the fair value of such RSUs and the expense is recognized over the vesting period. The Monte Carlo model was used to determine based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The expected volatility used in the model is based on the historical volatility commensurate with the length of the performance period of the award. The risk-free rate used in the model is based on published interest rates relevant to the term of the RSU award. 

3) Performance targets: Certain RSUs vest based on the achievement of Adjusted EBITDAX per debt adjusted share or average daily production volume per debt adjusted share metrics during 2019 and 2020. At the end of each reporting period, the amount of expense recorded is adjusted based on the number of shares it ultimately expects to vest based on the comparison of internal forecasts to the performance conditions.    

The fair value of the equity to which employees become entitled is measured at grant date and recognized as an expense over the vesting period with a corresponding increase in equity.  The Company accounts for forfeitures of RSUs as they occur.  See Note 13 for further discussion of the RSUs.

Defined Contribution Plan

Defined Contribution Plan

The Company has a defined contribution retirement plan for all employees.  The plan is funded by employee contributions and discretionary Company contributions.  The Company’s contributions for the years ended December 31, 2019 and 2018 were $0.6 million and $0.3 million, respectively.

Income Taxes

Income Taxes

Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes.  Deferred income taxes are accounted for using the liability method.  Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s consolidated financial statements.  The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized.  The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense (benefit).

Earnings (Loss) Per Share

Earnings (Loss) Per Share

Basic earnings (loss) per common share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding during each period.  Diluted earnings per common share is calculated by dividing net income by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities.  Potentially dilutive securities for the diluted earnings per share calculations consist of outstanding restricted share units which have been issued to employees, all using the treasury stock method.  When a loss from continuing operations exists, all dilutive securities and potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. 

Industry Segment and Geographic Information

Industry Segment and Geographic Information

The Company’s strategic focus is the exploration, development and production of large, repeatable onshore resource plays in North America. All of the Company’s operations and assets are located in the Eagle Ford area of south Texas.  Management has determined, based upon the reports the Chief Operating Decision Maker (the Company’s Chief Executive Officer) reviews and uses to make strategic decisions, that the Company has one reportable segment being oil and natural gas development and production in North America.

Foreign Currency Transaction Gains and Losses

Foreign Currency Transaction Gains and Losses

The U.S. dollar is the functional currency for the Company.  The Company’s Australian subsidiaries have an Australian dollar functional currency, and asset and liability accounts denominated in foreign currencies are remeasured to their U.S. dollar equivalent at the exchange rate in effect at the end of each reporting period. Foreign currency gains and losses arising from translation are reflected in accumulated other comprehensive (loss) in the consolidated balance sheets.

Business Combinations

Business Combinations

A business combination is a transaction in which an acquirer obtains control of one or more businesses. The Company accounts for business combinations using the acquisition method of accounting, under which the cost of the acquisition is allocated to assets acquired and liabilities assumed based upon their respective fair values as of the acquisition date. Costs directly attributable to the business combination are expensed as incurred, except those directly and incrementally attributable to equity issuance.

Recently Issued and Adopted Accounting Standards

Recently Issued and Adopted Accounting Standards

In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (“ASU 2016-02”). The FASB subsequently issued various ASUs which provided additional implementation guidance, and these ASUs collectively make up FASB ASC Topic 842 – Leases (“ASC 842”). The objective of ASC 842 is to increase transparency and comparability among organizations, by recognizing lease liabilities and right-of-use assets on the balance sheet at the date of initial application and disclosing key information about leasing arrangements. The Company adopted ASC 842 using the modified retrospective method effective January 1, 2019. Accordingly, the 2019 financial statements are not comparable with respect to leases in effect for all periods prior to January 1, 2019. Refer to Note 6 for further information on the Company’s implementation of this standard.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments, which provides a model, known as the current expected credit loss model (“CECL model”), to estimate the expected lifetime credit loss on financial assets, including trade and other receivables.  The Company adopted the ASU effective January 1, 2020, and it did not have a material impact on the Company’s consolidated financial statements as the Company does not have a history of material credit losses. 

XML

COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2019

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

NOTE 14 —COMMITMENTS AND CONTINGENCIES

Marketing, Gathering, Processing and Transportation Commitments

In connection with the Company’s 2018 acquisition, the Company entered into contracts with a large midstream company to gather, process, transport and market oil, NGL and natural gas production for the acquired properties.  The contracts contain a Minimum Revenue Commitment (“MRC”) that requires payment of minimum annual fees for those services. Fixed fees are expensed as incurred and settled with the purchaser on a monthly basis. If, at the end of each calendar year, the Company fails to satisfy the MRC, the Company is required to pay a shortfall. The Company’s MRC for the years ended December 31, 2019 and 2018 totaled $15.8 million and $11.1 million, respectively, and it realized deficiency fees of $2.3 million and $2.8 million, respectively.  The total remaining MRC by fiscal year are as follows (in thousands):

	2020		2021		2022		Total
Hydrocarbon gathering and handling agreement	$	14,297	$	13,972	$	6,675	$	34,944
Crude oil and condensate purchase agreements		4,710		7,513		4,317		16,540
Gas processing agreement		2,017		-		-		2,017
Gas transportation agreements		783		-		-		783
Total MRC	$	21,807	$	21,485	$	10,992	$	54,284

Cooper Basin Capital Commitments

The Company has non-core interest in the petroleum exploration license 570 located in the Cooper Basin, a license located in Australia (PEL 570). The Company has a commitment to fund exploratory drilling in the Cooper Basin of up to approximately A$10.6 million (US$7.5 million) through 2022, of which A$7.1 million (US$5.0 million) has been incurred as of December 31, 2019, with a remaining commitment of A$3.5 million. (US$2.5 million).  The exploratory drilling has not resulted in any proved reserves to date, and less than $0.1 million and $0.7 million incurred during the years ended December 31, 2019 and 2018 was recorded as exploration expense on the consolidated statement of operations. 

Litigation

The Company is involved in various legal proceedings in the ordinary course of business, and recognizes a contingent liability when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. While the outcome of these lawsuits and claims cannot be predicted with certainty, it is the opinion of management that, as of the date of this report, it is not probable that these claims and litigation will have a material adverse impact on the Company, Accordingly, no material amounts for loss contingencies associated with litigation, claims or assessments have been accrued as of December 31, 2019 other than described below. 

In 2013, the Company sold its interests in a non-operated North Dakota property.  During the year ended December 31, 2019, the Company recorded additional expense of $0.7 million for a litigation settlement with the Buyer within other expense (income), net on the consolidated statement of operations.  The settlement was paid in January 2020.

XML

INCOME TAXES - Narrative (Details) - USD ($) $ in Thousands		12 Months Ended
	Mar. 27, 2020	Dec. 31, 2019	Dec. 31, 2018
Income tax expense		$ (4,518)	$ 13,957
Pre-tax loss		(44,108)	(8,976)
Unrecognized tax benefits		0
Withholding tax payable		2,300
EFF
Pre change losses		248,500
Federal NOL		292,400
Australian NOL		$ 26,200
Operating Loss Carryforwards, Limitations on Use		$42.3
Prior To The CARES Act | Tax years beginning January 1, 2019 and 2020
Net interest expense deduction limit as a percentage of adjusted taxable income		30.00%
COVID-19 pandemic | The CARES Act | Subsequent event
Percentage of taxable income limitation eliminated to allow companies to fully utilize NOLs	80.00%
NOLs allowed to be carried back, term	5 years
COVID-19 pandemic | The CARES Act | Subsequent event | Tax years beginning January 1, 2019 and 2020
Net interest expense deduction limit as a percentage of adjusted taxable income	50.00%
UNITED STATES
Deemed interest payments received from US subsidiaries		$ 20,700
AUSTRALIA
Deferred Tax Assets, Operating Loss Carryforwards, Not Subject to Expiration			$ 15,600

XML

LEASES - Summary of future minimum contractual payments for long-term leases (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Operating Leases
2019	$ 2,087
2020	1,376
2021	602
2022	141
2023	83
Thereafter	964
Total lease payments	5,253
Capital Leases
2019	97
2020	98
2021	90
2022	15
2023	12
Total lease payments	312
Less interest	(26)
Total discounted lease payments	$ 286
Financial Position	us-gaap:OperatingLeaseLiabilityCurrent us-gaap:OperatingLeaseLiabilityNoncurrent
Drilling Rig
Operating Leases
2019	$ 4,106
Total lease payments	$ 4,106

XML

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - SEC Oil and Gas Reserve Information Other (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) MBoe location	Dec. 31, 2018 MBoe
Oil and Gas, Delivery Commitment [Line Items]
Proved undeveloped reserves (MBoe)	76,461	66,044
Duration over which future development costs expects to fund with operating cash flows	5 years
Future development costs associated with proved undeveloped reserves | $	$ 1,173.2
Expected proved reserves operating cash flow | $	$ 1,503.7
Revisions of previous estimates (MBoe)	(23,168)	(10,716)
Extensions and discoveries (MBoe)	39,649	11,904
Proved developed reserves, sales of reserves in-place (MBoe)	2,078
Proved undeveloped reserves, sales of reserves in-place (MBoe)	1,736
EFF
Oil and Gas, Delivery Commitment [Line Items]
Proved undeveloped reserves (MBoe)	76,461	66,044
Increase in proved undeveloped reserves (MBoe)	10,417
Extensions and discoveries, undeveloped (MBoe)	36,535
Revisions of previous estimates, undeveloped (MBoe)	19,881
Number of proved undeveloped locations | location	50
Number of locations on acquired assets | location	80
Proved undeveloped reserves on acquired assets	35,630
Conversion to proved developed reserves (MBoe)	4,501
Expected duration within which reserves will be spud	5 years
Revisions of previous estimates (MBoe)	(23,168)	(10,716)
Extensions and discoveries (MBoe)	39,649	11,904

XML

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Description of Operations and Going Concern (Details)			1 Months Ended		12 Months Ended
	Apr. 29, 2020	Nov. 26, 2019 shares	Mar. 31, 2020 $ / bbl	Dec. 31, 2019 $ / shares $ / bbl	Dec. 31, 2019 $ / shares	Dec. 31, 2018 $ / shares
Accounting Policies [Line Items]
Common stock, par value (in dollars per share) | $ / shares				$ 0.001	$ 0.001	$ 0.001
Oil, approximate market price | $ / bbl				60
Total Proved Reserves, PV percentage					9.00%
Common stock
Accounting Policies [Line Items]
Number of shares issued for 100 shares holding | shares		1
Number of shares converted into one share | shares		100
Maximum
Accounting Policies [Line Items]
Oil, approximate market price | $ / bbl			20
Term Loan | Subsequent event
Accounting Policies [Line Items]
Term for new agreement prior to event of default	15 days
Waiver, right to require corresponding amendments within period from execution date	90 days
Term Loan | Minimum
Accounting Policies [Line Items]
Asset Coverage Ratio					1.50

XML

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other Property (Details)	12 Months Ended
	Dec. 31, 2019
Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives	3 years
Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives	20 years

XML

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Industry Segment (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($) segment	Dec. 31, 2018 USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | segment	1
Exploration expense	$ 337	$ 3,339
Cooper Basin
Segment Reporting Information [Line Items]
Exploration expense		$ 700
Cooper Basin | Maximum
Segment Reporting Information [Line Items]
Exploration expense	$ 100

XML

EQUITY - Equity Offerings (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) shares
EQUITY
Number of shares issued | shares	5,614,446
Proceeds from capital raise | $	$ 243

XML

DERIVATIVE FINANCIAL INSTRUMENTS - Offsetting of Derivative Assets (Details) - Not designated as ASC 815 Hedges - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivative Asset
Gross Recognized Assets	$ 5,885	$ 49,503
Net Recognized Fair Value Assets	2,093	32,318
Derivative commodity contracts | Derivative assets current
Derivative Asset
Gross Recognized Assets	2,863	24,877
Gross Amount Offset	(1,648)	(562)
Net Recognized Fair Value Assets	1,215	24,315
Derivative commodity contracts | Derivative assets non-current
Derivative Asset
Gross Recognized Assets	2,637	8,403
Gross Amount Offset	(1,759)	(400)
Net Recognized Fair Value Assets	878	8,003
Derivative interest rate swaps | Derivative assets current
Derivative Asset
Gross Recognized Assets	8	5,081
Gross Amount Offset	(8)	(5,081)
Derivative interest rate swaps | Derivative assets non-current
Derivative Asset
Gross Recognized Assets	377	11,142
Gross Amount Offset	$ (377)	$ (11,142)

XML

FAIR VALUE MEASUREMENT - Transfers Between Levels (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
FAIR VALUE MEASUREMENT
Fair value transfer of assets from level 1 to level 2	$ 0	$ 0
Fair value transfer of assets from level 2 to level 1	0	0
Fair value transfer of liabilities from level 1 to level 2	0	0
Fair value transfer of liabilities from level 2 to level 1	0	0
Fair value transfer of assets into level 3	0	0
Fair value transfer of assets out of level 3	0	0
Fair value transfer of liabilities into level 3	0	0
Fair value transfer of liabilities out of level 3	$ 0	$ 0

XML

COMMITMENTS AND CONTINGENCIES - Narrative (Details) $ in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019 AUD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2019 USD ($)
Lessee, Lease, Description [Line Items]
Exploration costs incurred		$ 335	$ 2,789
Exploration expense		337	3,339
Litigation settlement expense		700
Cooper Basin
Lessee, Lease, Description [Line Items]
Commitment to fund exploratory drilling	$ 10.6			$ 7,500
Exploration costs incurred	7.1	5,000
Remaining commitment to fund exploratory drilling	$ 3.5			$ 2,500
Exploration expense			700
Maximum | Cooper Basin
Lessee, Lease, Description [Line Items]
Exploration expense		100
Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC
Lessee, Lease, Description [Line Items]
Deficiency payment		2,300	$ 2,800
Exploration expense		$ 100

XML

LEASES - Summary of lease terms and discount rates (Details)	Dec. 31, 2019
Weighted Average Remaining Lease Term (years)
Operating Leases	5 years 2 months 19 days
Finance Leases	2 years 6 months 29 days
Weighted Average Discount Rate
Operating Leases	4.73%
Finance Leases	4.69%

XML

ACQUISITIONS AND DISPOSITIONS

12 Months Ended

Dec. 31, 2019

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS

NOTE 3 — ACQUISITIONS AND DISPOSITIONS

2019

The Company did not have any acquisitions during the year ended December 31, 2019.

On October 1, 2019, the Company closed on the sale of its assets located in Dimmit County, Texas, for $21.5 million, of which $4.2 million was a receivable due to Sundance as of December 31, 2019.  The disposed assets included 19 gross producing wells located on approximately 6,100 net acres.  Production from these wells approximated 1,200 Boe/d during 2019 prior to the disposition.  This disposal group was classified as held for sale prior to its sale.  See Note 4 for further discussion.

2018

On April 23, 2018, Sundance Energy Inc. acquired from Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC (collectively the “Sellers”) approximately 21,900 net acres targeting the Eagle Ford Formation in McMullen, Live Oak, Atascosa and La Salle counties, Texas, for cash of $215.8 million, after the effective date to closing date adjustments of $5.8 million.  The acquisition included working interests in 132 gross producing wells, and furthered the Company’s strategy of aggregating assets in the Eagle Ford.

The following table reflects the fair value of the assets acquired and the liabilities assumed (in thousands):

Assets Acquired:	December 31, 2018
Oil and gas properties
Proved	$	173,750
Unproved		43,642
Liabilities Assumed:
Trade and other payables		(80)
Asset retirement obligation		(1,522)
Net assets acquired	$	215,790

For the period from April 23, 2018 through December 31, 2018 the acquired properties generated the following revenues and direct operating expenses, including depletion, depreciation and amortization expense:

Revenues	$	64,507
Direct operating expenses (1)		(45,194)
Income from operations	$	19,313

(1) Direct operating expenses include lease operating and workover expense, gathering, processing and transportation expense, production taxes and depreciation, depletion and amortization expense.

Included in general and administrative expenses in the consolidated statement of operations are transaction costs, including legal, accounting, valuation and other fees incurred to complete the acquisition, totaling $13.7 million, of which $12.4 million and $1.3 million were incurred during the years ended December 31, 2018 and 2017, respectively.

Pro Forma Information (unaudited)

For the years ended December 31, 2018, the pro forma financial information represents the combined results for the Company and the properties acquired as if the acquisition had occurred January 1, 2018.  For the year ended December 31, 2018 the pro forma revenue and loss before income taxes was $174.7 million and $(7.7) million, respectively.  This pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations.

There were no material dispositions in 2018.

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2019	Apr. 24, 2020	Jun. 30, 2019
Document and Entity Information
Document Type	10-K
Document Period End Date	Dec. 31, 2019
Entity Registrant Name	Sundance Energy Inc.
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	true
Entity Ex Transition Period	false
Entity Shell Company	false
Entity Public Float			$ 131,992,965
Entity Common Stock, Shares Outstanding		6,875,672
Entity Central Index Key	0001326089
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false

XML

ASSETS HELD FOR SALE (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Assets held for sale:
Oil and gas properties - Dimmit County, Texas		$ 23,471
Liabilities related to assets held for sale:
Asset retirement obligations		(193)
Impairment expense	$ 9,990	43,828
Assets held for sale
Assets held for sale:
Oil and gas properties - Dimmit County, Texas		23,471
Liabilities related to assets held for sale:
Asset retirement obligations		(193)
Net assets held for sale		23,278
Proved Oil And Gas Eagle Ford Formation assets located in Dimmit County, Texas
Liabilities related to assets held for sale:
Impairment expense	$ 10,000	$ 43,000

XML

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Thousands	Common stock	Additional Paid-In Capital	Accumulated Deficit	Accumulated other comprehensive loss	Total
Balance at the beginning of period at Dec. 31, 2017	$ 1	$ 389,013	$ (216,621)	$ (1,134)	$ 171,259
Balance at the beginning of period (in shares) at Dec. 31, 2017	1,253,250
Fractional shares issued upon reverse split (in shares)	10
Shares issued in connection with private placement	$ 6	253,511			$ 253,517
Shares issued in connection with private placement (in shares)	5,614,446				5,614,446
Private placement offering costs, net of tax		(10,297)			$ (10,297)
Stock-based compensation		515			515
Stock-based compensation (in shares)	6,916
Net loss			(22,933)		(22,933)
Foreign currency translation				428	428
Balance at the end of period at Dec. 31, 2018	$ 7	632,742	(239,554)	(706)	392,489
Balance at the end of period (in shares) at Dec. 31, 2018	6,874,622
Stock-based compensation		504			504
Stock-based compensation (in shares)	1,050
Net loss			(39,590)		(39,590)
Foreign currency translation				(6)	(6)
Balance at the end of period at Dec. 31, 2019	$ 7	$ 633,246	$ (279,144)	$ (712)	$ 353,397
Balance at the end of period (in shares) at Dec. 31, 2019	6,875,672

XML

OIL AND GAS PROPERTIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Oil and gas properties, successful efforts method:
Unproved	$ 25,037	$ 48,049
Proved	1,090,774	925,551
Work in progress	7,097	12,948
Total	1,122,908	986,548
Accumulated depletion, depreciation and amortization	(379,961)	(293,598)
Total oil and gas properties, net	742,947	692,950
Capitalized interest	2,300	1,500
Impairment of proved properties	$ 9,990	$ 43,828

XML

LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2019

LONG-TERM DEBT

Summary of long-term debt

The following is a summary of long-term debt as of December 31, 2019 and 2018 (in thousands):

		December 31,
		2019		2018
Revolving Facility	$	115,000	$	65,000
Term Loan		250,000		250,000
Total long-term debt		365,000		315,000
Deferred financing fees, net of accumulated amortization		(11,510)		(14,196)
Total credit facilities, net of deferred financing fees	$	353,490	$	300,804

XML

FAIR VALUE MEASUREMENT (Tables)

12 Months Ended

Dec. 31, 2019

FAIR VALUE MEASUREMENT

Schedule of balance sheets grouped into the fair value hierarchy

The financial assets and liabilities measured at fair value on a recurring basis in the consolidated balance sheets are grouped into the fair value hierarchy as follows (in thousands):

	December 31, 2019
	Level 1		Level 2		Level 3		Total
Assets measured at fair value
Derivative commodity contracts	$	—	$	2,093	$	—	$	2,093
Liabilities measured at fair value
Derivative commodity contracts		—		(2,300)		—		(2,300)
Derivative interest rate swaps		—		(5,763)		—		(5,763)
		—		(8,063)		—		(8,063)
Net fair value	$	—	$	(5,970)	$	—	$	(5,970)
	December 31, 2018
	Level 1		Level 2		Level 3		Total
Assets measured at fair value
Derivative commodity contracts	$	—	$	32,318	$	—	$	32,318
Liabilities measured at fair value
Derivative commodity contracts		—		(876)		—		(876)
Derivative interest rate swaps		—		(2,138)		—		(2,138)
		—		(3,014)		—		(3,014)
Net fair value	$	—	$	29,304	$	—	$	29,304

Schedule of non-recurring fair value measurements

	Net Carrying Value as of			Fair Value Measurements Using
(in thousands)	December 31, 2018			Level 1	Level 2		Level 3
Assets held for sale	$	23,471	$	—	$	—	$	23,471

XML

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables)

12 Months Ended

Dec. 31, 2019

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Schedule of capitalized cost incurred in oil and gas production, exploration and development activities

The Company’s oil and gas activities for 2019 and 2018 were entirely within the United States.  Costs incurred in oil and gas producing activities were as follows (in thousands):

	Year ended December 31,
	2019		2018
Property acquisition costs
Proved	$	—	$	173,750
Unproved (1)		177		45,252
Exploration costs		335		2,789
Development costs (2) (3)		149,766		181,463

⁽¹⁾ Includes costs incurred related to its Dimmit County assets, which were classified as held for sale during 2018 through their sale in October 2019, of nil and $1.0 million during the years ended December 31, 2019 and 2018, respectively.

⁽²⁾ Development costs include $7.1 million and $12.9 million wells in-progress as of December 31, 2019 and 2018, respectively.  These wells in-progress were either drilling, waiting on hydraulic fracturing or production testing.    

⁽³⁾ Includes costs incurred related to its Dimmit County assets, which were classified as held for sale during 2018 through their sale in October 2019, of $8.4 million and $5.3 million during the years ended December 31, 2019 and 2018, respectively.

Schedule of estimated reserved data

		Natural
	Oil	Gas	NGL	Total
	(MBbl)	(MMcf)	(MBbl)	(MBoe)
Proved reserves:
January 1, 2018	27,987	59,409	9,190	47,079
Revisions of previous estimates	(5,138)	(14,257)	(3,201)	(10,716)
Extensions and discoveries	7,577	12,889	2,179	11,904
Purchases of reserves in-place	30,474	55,367	8,801	48,503
Production	(2,256)	(4,534)	(497)	(3,508)
Sales of reserves in-place	(15)	(33)	-	(21)
December 31, 2018	58,629	108,841	16,472	93,241
Revisions of previous estimates	(14,358)	(27,504)	(4,225)	(23,168)
Extensions and discoveries	23,018	52,297	7,915	39,649
Production	(3,077)	(5,768)	(798)	(4,836)
Sales of reserves in-place	(1,424)	(6,962)	(1,230)	(3,814)
December 31, 2019	62,788	120,904	18,134	101,072
Proved developed reserves:
December 31, 2018	16,742	33,169	4,927	27,197
December 31, 2019	16,101	26,930	4,022	24,611
Proved undeveloped reserves
December 31, 2018	41,887	75,672	11,545	66,044
December 31, 2019	46,687	93,974	14,112	76,461

Summary of standardized measure

The following summary sets forth our Standardized Measure (in thousands):

	December 31,
	2019		2018
Cash inflows	$	4,148,426	$	4,733,751
Production costs		(1,348,892)		(1,318,059)
Development costs		(1,231,467)		(1,143,083)
Income tax expense		(183,680)		(343,068)
Net cash flow		1,384,387		1,929,541
10% annual discount rate		(709,288)		(976,916)
Standardized measure of discounted future net cash flow	$	675,099	$	952,625

Schedule of principal source of change in the standardized measure

The following are the principal sources of change in the Standardized Measure (in thousands):

	Year ended December 31,
	2019		2018
Standardized Measure, beginning of year	$	952,625	$	366,747
Sales, net of production costs		(141,329)		(113,073)
Net change in sales prices, net of production costs		(422,811)		201,784
Extensions and discoveries, net of future production and development costs		258,433		206,179
Changes in future development costs		283,154		63,297
Previously estimated development costs incurred during the period		84,739		94,673
Revision of quantity estimates		(308,312)		(198,956)
Accretion of discount		110,985		38,124
Change in income taxes		79,728		(142,730)
Purchases of reserves in-place		—		525,547
Sales of reserves in-place		(47,059)		(220)
Change in production rates and other		(175,054)		(88,747)
Standardized Measure, end of year	$	675,099	$	952,625

Schedule of average prices used in determining the standardized measure

	Year ended December 31,
	2019		2018
Oil (per Bbl)	$	56.05	$	66.34
Gas (per Mcf)	$	2.75	$	3.50
NGL (per Bbl)	$	16.35	$	28.15

XML

DERIVATIVE FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2019

DERIVATIVE FINANCIAL INSTRUMENTS

DERIVATIVE FINANCIAL INSTRUMENTS

NOTE 10 — DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Derivatives

The Company uses derivative instruments to mitigate volatility in commodity prices.  While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future cash flow from favorable price changes.  The Company’s policy is to hedge at least 50% of its the reasonably projected oil & gas production from the Proved Reserves classified as “Developed Producing Reserves” for a rolling 36 month period, but not more than 85% of the reasonably projected production from the Proved Reserves for a rolling 24 months and not more than 75% of the reasonably projected production from the Proved Reserves for months 25-60, as required by its Revolving Facility agreement.  

As of December 31, 2019, the Company has primarily entered into oil and gas swaps and collars and oil basis swaps. For collars, the Company receives the difference between the published index price and a floor price if the index price is below the floor price, or pays the difference between the ceiling price and the index price if the index price is above the ceiling price.  No amounts are paid or received if the index price is between the floor and the ceiling prices. By using a collar, the minimum and maximum prices on the underlying production are fixed. The oil basis swaps are settled based on the difference between a published index price minus a fixed differential and the applicable local index price under which the underlying production is sold. By using a basis swap, the Company has fixed the differential between the published index price and certain of our physical pricing points. The basis swaps fix the price differential between the WTI NYMEX (Cushing Oklahoma) price and the WTI Houston Argus price.

A summary of the Company’s commodity derivative positions as of December 31, 2019 follows:

Oil Swaps - WTI (1)
Year	Volumes (Bbl)		Weighted Average Price per Bbl
2020	1,074,000	$	57.17
2021	216,000	$	54.84

Oil Collars - WTI
Year	Volumes (Bbl)		Weighted Average Price per Bbl - Floor		Weighted Average Price per Bbl - Ceiling
2020	672,000	$	54.47	$	61.82
2021	216,000	$	45.00	$	65.00
2022	228,000	$	40.00	$	66.00
2023	160,000	$	40.00	$	63.10

Oil Three-Way Collars - WTI
Year	Volumes (Bbl)		Weighted Average Price per Bbl - Floor Sold		Weighted Average Price per Bbl - Floor Purchased		Weighted Average Price per Bbl - Ceiling
2020	300,000	$	35.00	$	50.00	$	59.60
2021	300,000	$	35.00	$	50.00	$	57.50
2022	300,000	$	35.00	$	50.00	$	56.90

Propane Calls Sold - OPIS Propane Mont Belvieu - TET(2)
Year	Volumes (Bbl)		Weighted Average Price per Bbl
2020	271,000	$	0.70

Oil Basis Swaps - WTI-HOU (3)
Year	Volumes (Bbl)		Weighted Average Differential per Bbl
2020	720,000	$	2.98
2021	120,000	$	2.53

Natural Gas Swaps	Price Swaps - HH(4)			Price Swaps - HSC(5)
Year	Volumes (MMBtu)		Weighted Average Price per MMBtu	Volumes (MMBtu)		Weighted Average Price per MMBtu
2020	1,890,000	$	2.70	120,000	$	2.53
2021	1,050,000	$	2.69	240,000	$	2.50
2022	720,000	$	2.76	360,000	$	2.54
2023				240,000	$	2.64

Natural Gas Collars  - HH
Year	Volumes (MMBtu)		Weighted Average Price per MMBtu - Floor		Weighted Average Price per MMBtu - Ceiling
2020	120,000	$	2.50	$	2.95

HSC
Year	Volumes (MMBtu)		Weighted Average Price per MMBtu - Floor		Weighted Average Price per MMBtu - Ceiling
2020	96,000	$	2.60	$	2.91

Subsequent to December 31, 2019, the Company entered into the following commodity derivative positions:

Oil Swaps	Price Swaps - WTI
Year	Volumes (Bbl)		Weighted Average Price per Bbl
2020	720,000	$	49.39
2021	1,980,000	$	48.38

Natural Gas Swaps	Price Swaps - HH
Year	Volumes (MMBtu)		Weighted Average Price per MMBtu
2021	600,000	$	2.67

The following is a list of index prices:

(1) WTI crude oil as quoted on NYMEX.

(2)Mont Belvieu – Texas Eastern Transmission (“TET”) propane as quoted by Oil Price Information Service (“OPIS”). 

(3)WTI Houston Argus (“WTI-HOU”) crude oil as quoted by Argus US Pipeline.

(4)Henry Hub (“HH”) natural gas as quoted on the NYMEX.

(5)Houston Ship Channel (“HSC”) natural gas as quoted in Platt’s Inside FERC.

Interest Rate Derivatives

A summary of the Company’s interest rate swaps as of December 31, 2019 follows (notional amount in thousands):

							Portion of
	Term						Term Loan
Effective Date		Termination Date	Notional Amount		Fixed Rate (1)		Face Amount
July 11, 2019		July 11, 2020	$	187,500	3.016	%	75	%
July 11, 2020		July 11, 2021	$	125,000	3.072	%	50	%
July 11, 2021		July 11, 2022	$	125,000	3.061	%	50	%
July 13, 2022		May 23, 2023	$	125,000	3.042	%	50	%

(1) Each contract has a 1% floor, consistent with the structure of the Term Loan. 

Offsetting of Derivative Assets and Liabilities. 

The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract.  The following tables summarize the location and fair value amounts of all the Company’s derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets (in thousands):

		December 31, 2019
		Gross		Gross		Net Recognized
		Recognized		Amounts		Fair Value
Not Designated as ASC 815 Hedges	Balance Sheet Classification	Assets/Liabilities		Offset		Assets/Liabilities
DERIVATIVE ASSETS:
Current:
Derivative financial instruments — commodity contracts	Derivative assets	$	2,863	$	(1,648)	$	1,215
Derivative financial instruments — interest rate swaps	Derivative assets		8		(8)		—
Long-term:
Derivative financial instruments — commodity contracts	Derivative assets		2,637		(1,759)		878
Derivative financial instruments — interest rate swaps	Derivative assets		377		(377)		—
Total derivative assets			5,885				2,093
DERIVATIVE LIABILITIES:
Current:
Derivative financial instruments — commodity contracts	Derivative liabilities		3,946		(1,648)		2,298
Derivative financial instruments — interest rate swaps	Derivative liabilities		2,104		(8)		2,096
Total current derivative liabilities			6,050				4,394
Long-term:
Derivative financial instruments — commodity contracts	Derivative liabilities		1,761		(1,759)		2
Derivative financial instruments — interest rate swaps	Derivative liabilities		4,044		(377)		3,667
Total long-term derivative liabilities			5,805				3,669
Total derivative liabilities			11,855				8,063
		$	(5,970)			$	(5,970)

		December 31, 2018
		Gross		Gross		Net Recognized
		Recognized		Amounts		Fair Value
Not Designated as ASC 815 Hedges	Balance Sheet Classification	Assets/Liabilities		Offset		Assets/Liabilities
DERIVATIVE ASSETS:
Current:
Derivative financial instruments — commodity contracts	Derivative assets	$	24,877	$	(562)	$	24,315
Derivative financial instruments — interest rate swaps	Derivative assets		5,081		(5,081)		—
Long-term:
Derivative financial instruments — commodity contracts	Derivative assets		8,403		(400)		8,003
Derivative financial instruments — interest rate swaps	Derivative assets		11,142		(11,142)		—
Total derivative assets			49,503				32,318
DERIVATIVE LIABILITIES:
Current:
Derivative financial instruments — commodity contracts	Derivative liabilities		787		(562)		225
Derivative financial instruments — interest rate swaps	Derivative liabilities		5,292		(5,081)		211
Total current derivative liabilities			6,079				436
Long-term:
Derivative financial instruments — commodity contracts	Derivative liabilities		1,051		(400)		651
Derivative financial instruments — interest rate swaps	Derivative liabilities		13,069		(11,142)		1,927
Total long-term derivative liabilities			14,120				2,578
Total derivative liabilities			20,199				3,014
		$	29,304			$	29,304

		Gain (Loss) Recognized in Income Year Ended December 31,
Not designated as ASC 815 Hedges	Statement of Operations Classification	2019		2018
Foreign currency	Gain on foreign currency derivative financial instruments	$	-	$	6,838
Commodity contracts	Gain (loss) on commodity derivative financial instruments		(20,542)		40,216
Interest rate swap	Interest expense		(4,270)		(2,435)
		$	(24,812)	$	44,619

Contingent Features in Financial Derivative Instruments.  None of the Company’s derivative instruments contain credit-risk related contingent features.  Most of the counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions and that are lenders under Sundance’s credit agreement.  The Company uses credit agreement participants to hedge with, since these institutions are secured equally with the holder’s of Sundance’s bank debt, which eliminates the need to post collateral when Sundance is in a derivative liability position.  The Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.

Refer to Note 11 for additional information regarding the valuation of derivative instruments.

XML

LEASES

12 Months Ended

Dec. 31, 2019

LEASES

LEASES

NOTE 6 – LEASES

Lease Accounting

Adoption and transition

Effective January 1, 2019, the Company began accounting for leases in accordance with ASC 842, which requires lessees to recognize lease liabilities and right-of-use assets on the balance sheet for contracts that provide lessees with the right to control the use of identified assets for periods of greater than 12 months. Prior to January 1, 2019, the Company accounted for leases in accordance with ASC Topic 840, Leases (“ASC 840”), under which operating leases were not recorded on the balance sheet. Adoption of ASC 842 resulted in the recognition of lease liabilities of $11.5 million and right-of-use assets (“ROU”) of $11.4 million related to the Company’s operating leases on its consolidated balance sheet, and did not result in the Company recognizing a cumulative-effect adjustment to accumulated deficit, at January 1, 2019.

In connection with the adoption of ASC 842 effective January 1, 2019, the Company applied the following transition practical expedients:

· A package of practical expedients which allowed the Company, for its arrangements in existence prior to the January 1, 2019 application date, to not reassess (1) whether an arrangement was or contained a lease at its commencement date, (2) its previous conclusions regarding classification of a lease as an operating or finance lease at its commencement date, and (3) initial direct costs as recorded;

· A practical expedient which allowed the Company, for its arrangements in existence prior to the January 1, 2019 application date, to not reassess its accounting for land easement arrangements not previously accounted for as leases; and

· A practical expedient to use hindsight in assessing the lease term and impairment.

The scope of ASC 842 excludes leases to explore for or use minerals, oil, natural gas, and similar non-regenerative resources.  However, leases of equipment used to explore for natural resources (for example, drilling equipment) are not part of this scope exception.

Accounting Policies for Leases

The Company has made the following policy elections related to accounting for its leases under ASC 842:

· Exemption from recognition and measurement provisions for short-term leases (a lease that at commencement has a lease term of 12 months or less) in all classes of assets;

· Election to not separate nonlease components, such as amounts for related taxes and common area maintenance charges, in certain classes of assets, including its office facilities and equipment, amine and compression equipment, land right-of-way and surface use arrangements, and employee lodging; and

· Election to apply general provisions and discount rates to certain portfolios of leases with reasonably similar characteristics.

The Company determines whether an arrangement is, or contains, a lease based on the substance of the arrangement at its inception. The Company applies judgment in analyzing the arrangement to determine whether it conveys an enforceable right to control the use of an identified asset or assets for a period of time in exchange for consideration. For the Company as lessee, this assessment includes consideration of whether it has the right to obtain substantially all of the economic benefits from the use of the identified asset, together with the right to direct the use of the asset, and whether there is an enforceable obligation for it to exchange consideration for those rights. 

The Company assesses the classification of its lease arrangements upon commencement of the lease by determining whether the lease contains any one of the following criteria for classification as a finance lease, and if it does not, it is classified as an operating lease:

· Transfer of ownership of the underlying asset to the Company by the end of the lease term;

· An option to purchase the underlying asset that the Company is reasonably certain to exercise;

· A lease term that is for the major part of the remaining economic life of the underlying asset;

· A present value of the sum of lease payments and lessee’s guaranteed residual value equal to or in excess of substantially all of the fair value of the underlying asset; or

· An underlying asset that is of such a specialized nature that it is expected to have no alternative use to the lessor at the end of the lease term.

Operating lease cost is recognized on a straight-line basis over the lease term. Finance lease cost is recognized based on the effective interest method for the lease liability and straight-line amortization of the ROU asset, resulting in more cost being recognized in earlier periods. All payments for short-term leases are recognized on a straight-line basis over the lease term.  Short-term lease cost excludes amounts for rental of equipment for periods less than thirty days in duration. 

Leasing Arrangements and Significant Assumptions and Judgments

The Company enters into leases as lessee to conduct its normal operations. The Company has operating leases primarily for its use of compression equipment, a drilling rig, land right of way and surface use arrangements, office facilities, and other production equipment. The Company has finance leases for its use of field vehicles and office equipment. Most of the Company’s leasing arrangements include extension and termination options, including evergreen provisions, all of which provide the Company flexibility in retaining the underlying facilities and equipment, as well as some protection from future price variability. The Company recognizes options to extend or terminate its leases as part of its assessment of the lease term, when it is reasonably certain to exercise the option. The Company’s leases are typically not significant enough individually or in the aggregate to impose or affect restrictions in its borrowing capacity or financial covenants.

Some of the Company’s contracts have pricing that is variable within a range based on throughput, others have a set rate increase at predetermined intervals, and others are silent as to future increases or have a rate that is undefined for the variable components. The Company’s leases do not have future variable payments related to indices. For contracts with throughput provisions subject to a range, future payments have been included in the calculation of the lease liabilities at the contract minimum rate.  Future payment increases for leases with set rate increases have been incorporated into the calculation of the lease liabilities, including the escalations. Future variable payments such as for movement or demobilization of the underlying leased asset have typically been excluded from the calculation of the lease liabilities unless they are determinable, and are expensed as incurred.

The Company has applied judgment to determine the lease term for some of its lease contracts which include renewal or termination options. Certain of the Company’s leases include an “evergreen” provision that allows the contract term to continue on a month-to-month or year-to-year basis following expiration of the initial term included in the contract. For leases with an evergreen provision that renewed during the year ended December 31, 2019, the term of the lease was re-assessed by the Company and determined to be the non-cancelable period in the contract, plus the period beyond that cancellation period that the Company believes it is reasonably certain it will need the equipment for operational purposes. This re-assessment affects the value of ROU assets and lease liabilities recognized in the balance sheets at December 31, 2019. 

The Company has also applied judgment in determining the discount rate to apply to its lease calculations. The lease liabilities and corresponding ROU assets have been discounted using the Company’s incremental borrowing rate, which has been derived from rates expected to be available under the Company’s Revolving Credit Facility, using available borrowing base capacity and forward curve information over periods comparable to the term of each lease.

Lease Recognition and Measurement

The ROU asset is initially measured to be equal to the lease liability and adjusted for any lease incentives received and initial direct costs and lease prepayments incurred. Subsequently, the ROU asset is measured at cost less any accumulated amortization and adjusted for certain remeasurements of the lease liability or impairments of the ROU asset. 

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date. The lease liability is subsequently increased by the interest cost on the lease liability and decreased by lease payments made. It is re-measured when there is a change in future lease payments arising from a change in the Company’s plans with respect to exercise of options included in terms of the lease, or a modification to the lease arrangement. 

In the event that there is a modification to a lease arrangement, a determination of whether the modification results in a separate lease arrangement being recognized is made. The Company also considers the impact of the modification on classification of the lease.  If the modification results in the recognition of a separate lease arrangement, due to an increase in scope of a lease for example through additional underlying leased assets being added and a commensurate increase in lease payments, the Company measures the new arrangement separately, accounting for it as a new lease. If the modification does not result in a separate lease arrangement, for example due to an extension of the lease term that does not exceed the life of the underlying asset, the Company re-measures the remaining lease liability from the effective date of the modification using the re-determined lease term, remaining future lease payments and applicable discount rate. An adjustment is made to the carrying amount of the associated right-of-use asset for the re-measurement of the corresponding lease liability. If there has been a partial or full termination of a lease, the Company recognizes any resulting gain or loss in the consolidated statement of operations and other comprehensive income (loss).

Lease Supplemental Disclosures

The following tables present the carrying amounts and classifications of the Company’s ROU assets (net of accumulated amortization) and estimated lease liabilities as of December 31, 2019 (in thousands):

Right-of-use assets	Balance Sheet Location	December 31, 2019
Operating lease right-of-use assets	Operating lease right-of-use assets	$	17,331
Finance lease right-of-use assets	Other property and equipment, net of accumulated depreciation		747
Total right-of-use assets		$	18,078
Lease liabilities	Balance Sheet Location	December 31, 2019
Operating lease liabilities - current	Operating lease liabilities - current	$	7,720
Operating lease liabilities - non-current	Operating lease liabilities - non-current		9,611
Finance lease liabilities - current	Accrued expenses		305
Finance lease liabilities - non-current	Other long-term liabilities		429
Total lease liabilities		$	18,065

Information regarding the Company’s lease terms and discount rates as of December 31, 2019 are as follows:

Weighted Average Remaining Lease Term (years)
Operating Leases	5.22
Finance Leases	2.58
Weighted Average Discount Rate
Operating Leases	4.73%
Finance Leases	4.69%

The following summarizes total lease cost, which includes amounts recognized on the consolidated statement of operations and other comprehensive income (loss) and amounts capitalized related to the Company’s leases (in thousands):

	Year ended
	December 31, 2019
Operating lease cost (1)	$	11,729
Finance lease cost:
Amortization of right-of-use assets	$	187
Interest on lease liabilities		20
Total finance lease cost	$	207
Short-term lease cost	$	1,065
Variable lease cost	$	1,395
Sublease income	$	150

(1) Operating lease cost of $6.3 million related to the Company’s drilling rig was capitalized to oil and gas properties on the consolidated balance sheet and will be depleted in accordance with the Company’s policies.

The following summarizes supplemental cash flow information related to the Company’s leases (in thousands):

	December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	5,271
Operating cash flows from finance leases	$	20
Investing cash flows from operating leases	$	6,308
Financing cash flows from finance leases	$	187
Supplemental non-cash information on lease liabilities arising from right of use assets
Operating lease liability additions	$	17,358
Finance lease liability additions	$	640

The Company’s lease obligations as of December 31, 2019 will mature as follows (in thousands):

Year Ending December 31,	Operating Leases		Finance Leases
2020	$	7,848	$	312
2021		4,061		305
2022		2,819		150
2023		2,192		12
2024		845		-
Thereafter		1,481		-
Total lease payments	$	19,246	$	779
Less: Interest		(1,915)		(45)
Total discounted lease payments	$	17,331	$	734

As of December 31, 2018, future minimum contractual payments for long-term leases under the scope of ASC 840 were as follows (in thousands):

Year Ending December 31,	Drilling  Rig		Operating Leases		Capital Leases
2019	$	4,106	$	2,087	$	97
2020		-		1,376		98
2021		-		602		90
2022		-		141		15
2023		-		83		12
Thereafter		-		964		-
Total lease payments	$	4,106	$	5,253	$	312
Less interest						(26)
Total discounted lease payments					$	286

Capital leases at December 31, 2018 included $0.2 million related to field vehicles and $0.1 million related to office equipment.  Rent expense for the year ended December 31, 2018 was $3.6 million.

XML

EQUITY - Reverse Stock Split (Details)	1 Months Ended	12 Months Ended
	Nov. 30, 2019	Dec. 31, 2019 shares	Nov. 01, 2019 shares	Oct. 31, 2019 shares	Dec. 31, 2018 shares
EQUITY
Reverse stock split	0.01	0.01
Number of ordinary outstanding shares		6,875,672	6,900,000	687,000,000	6,874,622

XML

DERIVATIVE FINANCIAL INSTRUMENTS - Interest Rate Swaps (Details) - Derivative interest rate swaps $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Derivative
Floor interest rate	1.00%
July 11, 2019 - July 11, 2020
Derivative
Notional Amount	$ 187,500
Fixed Rate	3.016%
Portion of Term Loan Face Amount	75.00%
July 11, 2020 - July 11, 2021
Derivative
Notional Amount	$ 125,000
Fixed Rate	3.072%
Portion of Term Loan Face Amount	50.00%
July 11, 2021 - July 11, 2022
Derivative
Notional Amount	$ 125,000
Fixed Rate	3.061%
Portion of Term Loan Face Amount	50.00%
July 13, 2022 - May 23, 2023
Derivative
Notional Amount	$ 125,000
Fixed Rate	3.042%
Portion of Term Loan Face Amount	50.00%

XML

FAIR VALUE MEASUREMENT - Assets and Liabilities (Details) - Fair Value, Recurring - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Liabilities measured at fair value
Derivative liabilities	$ (8,063)	$ (3,014)
Net fair value	(5,970)	29,304
Derivative commodity contracts
Assets measured at fair value
Derivative assets	2,093	32,318
Liabilities measured at fair value
Derivative liabilities	(2,300)	(876)
Derivative interest rate swaps
Liabilities measured at fair value
Derivative liabilities	(5,763)	(2,138)
Level 2
Liabilities measured at fair value
Derivative liabilities	(8,063)	(3,014)
Net fair value	(5,970)	29,304
Level 2 | Derivative commodity contracts
Assets measured at fair value
Derivative assets	2,093	32,318
Liabilities measured at fair value
Derivative liabilities	(2,300)	(876)
Level 2 | Derivative interest rate swaps
Liabilities measured at fair value
Derivative liabilities	$ (5,763)	$ (2,138)

XML

EQUITY - RSUs Grant Date, Fair Value and Vesting Conditions (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation	$ 504	$ 515
Restricted Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of RSUs	38,373	71,175
Fair Value at Grant Date	$ 20.31	$ 18.80
Unvested compensation expense	$ 500
Weighted average prices	$ 22.02	$ 70.85
Weighted average remaining contractual life (in years)	1 year
Fair value, expected to vest	$ 100
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date May 5, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of RSUs	5,325
Fair Value at Grant Date	$ 16.35
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date May 5, 2019 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	200.00%
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date May 5, 2019 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	0.00%
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date May 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of RSUs	15,637
Fair Value at Grant Date	$ 16.13
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date May 31, 2019 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	200.00%
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date May 31, 2019 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	0.00%
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date December 26, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of RSUs		35,587
Fair Value at Grant Date		$ 16.44
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date December 26, 2018 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage		0.00%
Restricted Share Units | Vesting Based on 2019 EBITDA per Debt Adjusted Share
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of RSUs	3,909	8,897
Fair Value at Grant Date	$ 24.92	$ 21.16
Restricted Share Units | Vesting Based on 2019 EBITDA per Debt Adjusted Share | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	200.00%	200.00%
Restricted Share Units | Vesting Based on 2019 EBITDA per Debt Adjusted Share | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	0.00%	0.00%
Restricted Share Units | Vesting Based on 2020 EBITDA per Debt Adjusted Share
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of RSUs	3,909	8,897
Fair Value at Grant Date	$ 24.92	$ 21.16
Restricted Share Units | Vesting Based on 2020 EBITDA per Debt Adjusted Share | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	200.00%	200.00%
Restricted Share Units | Vesting Based on 2020 EBITDA per Debt Adjusted Share | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	0.00%	0.00%
Restricted Share Units | Vesting Based on 2019 Production per Debt Adjusted Share
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of RSUs	3,909	8,897
Fair Value at Grant Date	$ 24.92	$ 21.16
Restricted Share Units | Vesting Based on 2019 Production per Debt Adjusted Share | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	200.00%	200.00%
Restricted Share Units | Vesting Based on 2019 Production per Debt Adjusted Share | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	0.00%	0.00%
Restricted Share Units | Vesting Based on 2020 Production per Debt Adjusted Share
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of RSUs	3,909	8,897
Fair Value at Grant Date	$ 24.92	$ 21.16
Restricted Share Units | Vesting Based on 2020 Production per Debt Adjusted Share | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	200.00%	200.00%
Restricted Share Units | Vesting Based on 2020 Production per Debt Adjusted Share | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	0.00%	0.00%
Restricted Share Units | Vests on 3rd anniversary of award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of RSUs	1,775
Fair Value at Grant Date	$ 29.49

XML

ACCRUED LIABILITIES (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016 item	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Oil and natural gas properties:
Capital expenditures		$ 4,168	$ 12,879
Re-fracture liability		764	900
Lease operating and workover expenses and other		7,393	6,586
Accrued interest payable		6,885	458
General and administrative expense		6,894	4,462
Finance lease liabilities		305
Total accrued liabilities		26,409	25,285
Number of wells to be refractured | item	5
Agreement term	5 years
Long-term re-fracture liability		$ 700	$ 1,100

XML

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenues:
Total revenues	$ 203,580	$ 164,933
Operating expenses:
Lease operating and workover expense	33,681	33,957
Gathering, processing and transportation expense	17,086	8,633
Production taxes	11,484	9,270
Exploration expense	337	3,339
Depreciation, depletion and amortization expense	92,334	62,814
Impairment expense	9,990	43,828
General and administrative expense	22,276	30,539
Loss (gain) on commodity derivative financial instruments	(20,542)	40,216
Other expense (income), net	1,900	(48)
Total operating expenses	209,630	152,116
Income (loss) from operations:	(6,050)	12,817
Other income (expense)
Interest expense	(38,058)	(28,631)
Gain on foreign currency derivative financial instruments		6,838
Total other expense	(38,058)	(21,793)
Loss before income taxes	(44,108)	(8,976)
Income taxes
Current expense		(2,301)
Deferred benefit (expense)	4,518	(11,656)
Total income tax benefit (expense)	4,518	(13,957)
Net loss	$ (39,590)	$ (22,933)
Loss per common share
Basic and diluted	$ (5.76)	$ (4.38)
Weighted average shares outstanding
Basic and diluted	6,874,170	5,236,524
Comprehensive loss
Net loss	$ (39,590)	$ (22,933)
Other comprehensive income (loss):
Foreign currency translation	(6)	428
Total comprehensive loss	(39,596)	(22,505)
Oil sales
Revenues:
Total revenues	177,853	140,240
Natural gas sales
Revenues:
Total revenues	12,553	12,025
Natural gas liquid sales
Revenues:
Total revenues	$ 13,174	$ 12,668

XML

ACQUISITIONS AND DISPOSITIONS - Narrative (Details) - Discontinued operations closed by sale $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) a Boe item	Oct. 01, 2019 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of producing wells | item	19
Area of wells | a	6,100
Production of wells per day | Boe	1,200
Dimmit County, Texas
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration		$ 21.5
Consideration receivable	$ 4.2

XML

LEASES - Summary of total lease cost (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Property, Plant and Equipment [Line Items]
Operating lease cost	$ 11,729
Finance lease cost:
Amortization of right-of-use assets	187
Interest on lease liabilities	20
Total finance lease cost	207
Shot-term lease cost	1,065
Variable lease cost	1,395
Sublease income	150
Drilling Rig
Property, Plant and Equipment [Line Items]
Operating lease cost	$ 6,300

XML

OIL AND GAS PROPERTIES

12 Months Ended

Dec. 31, 2019

OIL AND GAS PROPERTIES.

OIL AND GAS PROPERTIES

NOTE 2 — OIL AND GAS PROPERTIES

Net capitalized costs related to the Company’s oil and gas producing activities at December 31, 2019 and 2018 are as follows (in thousands):

	December 31,
	2019		2018
Oil and gas properties, successful efforts method:
Unproved	$	25,037	$	48,049
Proved		1,090,774		925,551
Work in progress		7,097		12,948
		1,122,908		986,548
Accumulated depletion, depreciation and amortization		(379,961)		(293,598)
Oil and gas properties, net	$	742,947	$	692,950

Capitalized Interest

For the years ended December 31, 2019 and 2018, the Company capitalized interest of $2.3 million and $1.5 million, respectively.

XML

COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2019

COMMITMENTS AND CONTINGENCIES

Schedule of the commitments that have initial or remaining noncancelable terms in excess of one year

	2020		2021		2022		Total
Hydrocarbon gathering and handling agreement	$	14,297	$	13,972	$	6,675	$	34,944
Crude oil and condensate purchase agreements		4,710		7,513		4,317		16,540
Gas processing agreement		2,017		-		-		2,017
Gas transportation agreements		783		-		-		783
Total MRC	$	21,807	$	21,485	$	10,992	$	54,284

XML

LEASES (Tables)

12 Months Ended

Dec. 31, 2019

LEASES

Schedule of classification of lease assets and liabilities

Right-of-use assets	Balance Sheet Location	December 31, 2019
Operating lease right-of-use assets	Operating lease right-of-use assets	$	17,331
Finance lease right-of-use assets	Other property and equipment, net of accumulated depreciation		747
Total right-of-use assets		$	18,078
Lease liabilities	Balance Sheet Location	December 31, 2019
Operating lease liabilities - current	Operating lease liabilities - current	$	7,720
Operating lease liabilities - non-current	Operating lease liabilities - non-current		9,611
Finance lease liabilities - current	Accrued expenses		305
Finance lease liabilities - non-current	Other long-term liabilities		429
Total lease liabilities		$	18,065

Schedule of lease terms and discount rates

Weighted Average Remaining Lease Term (years)
Operating Leases	5.22
Finance Leases	2.58
Weighted Average Discount Rate
Operating Leases	4.73%
Finance Leases	4.69%

Schedule of total lease cost

Weighted Average Remaining Lease Term (years)
Operating Leases	5.22
Finance Leases	2.58
Weighted Average Discount Rate
Operating Leases	4.73%
Finance Leases	4.69%

The following summarizes total lease cost, which includes amounts recognized on the consolidated statement of operations and other comprehensive income (loss) and amounts capitalized related to the Company’s leases (in thousands):

	Year ended
	December 31, 2019
Operating lease cost (1)	$	11,729
Finance lease cost:
Amortization of right-of-use assets	$	187
Interest on lease liabilities		20
Total finance lease cost	$	207
Short-term lease cost	$	1,065
Variable lease cost	$	1,395
Sublease income	$	150

(1) Operating lease cost of $6.3 million related to the Company’s drilling rig was capitalized to oil and gas properties on the consolidated balance sheet and will be depleted in accordance with the Company’s policies.

Schedule of supplemental cash flow information related to the Company’s leases

	December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	5,271
Operating cash flows from finance leases	$	20
Investing cash flows from operating leases	$	6,308
Financing cash flows from finance leases	$	187
Supplemental non-cash information on lease liabilities arising from right of use assets
Operating lease liability additions	$	17,358
Finance lease liability additions	$	640

Schedule of operating lease obligations

Year Ending December 31,	Operating Leases		Finance Leases
2020	$	7,848	$	312
2021		4,061		305
2022		2,819		150
2023		2,192		12
2024		845		-
Thereafter		1,481		-
Total lease payments	$	19,246	$	779
Less: Interest		(1,915)		(45)
Total discounted lease payments	$	17,331	$	734

Schedule of finance lease obligations

Year Ending December 31,	Operating Leases		Finance Leases
2020	$	7,848	$	312
2021		4,061		305
2022		2,819		150
2023		2,192		12
2024		845		-
Thereafter		1,481		-
Total lease payments	$	19,246	$	779
Less: Interest		(1,915)		(45)
Total discounted lease payments	$	17,331	$	734

Schedule of future minimum contractual payments for operating leases under the scope of ASC 840

Year Ending December 31,	Drilling  Rig		Operating Leases		Capital Leases
2019	$	4,106	$	2,087	$	97
2020		-		1,376		98
2021		-		602		90
2022		-		141		15
2023		-		83		12
Thereafter		-		964		-
Total lease payments	$	4,106	$	5,253	$	312
Less interest						(26)
Total discounted lease payments					$	286

Schedule of future minimum contractual payments for capital leases under the scope of ASC 840

Year Ending December 31,	Drilling  Rig		Operating Leases		Capital Leases
2019	$	4,106	$	2,087	$	97
2020		-		1,376		98
2021		-		602		90
2022		-		141		15
2023		-		83		12
Thereafter		-		964		-
Total lease payments	$	4,106	$	5,253	$	312
Less interest						(26)
Total discounted lease payments					$	286

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2019

DERIVATIVE FINANCIAL INSTRUMENTS

Summary of commodity derivative positions

Oil Swaps - WTI (1)
Year	Volumes (Bbl)		Weighted Average Price per Bbl
2020	1,074,000	$	57.17
2021	216,000	$	54.84

Oil Collars - WTI
Year	Volumes (Bbl)		Weighted Average Price per Bbl - Floor		Weighted Average Price per Bbl - Ceiling
2020	672,000	$	54.47	$	61.82
2021	216,000	$	45.00	$	65.00
2022	228,000	$	40.00	$	66.00
2023	160,000	$	40.00	$	63.10

Oil Three-Way Collars - WTI
Year	Volumes (Bbl)		Weighted Average Price per Bbl - Floor Sold		Weighted Average Price per Bbl - Floor Purchased		Weighted Average Price per Bbl - Ceiling
2020	300,000	$	35.00	$	50.00	$	59.60
2021	300,000	$	35.00	$	50.00	$	57.50
2022	300,000	$	35.00	$	50.00	$	56.90

Propane Calls Sold - OPIS Propane Mont Belvieu - TET(2)
Year	Volumes (Bbl)		Weighted Average Price per Bbl
2020	271,000	$	0.70

Oil Basis Swaps - WTI-HOU (3)
Year	Volumes (Bbl)		Weighted Average Differential per Bbl
2020	720,000	$	2.98
2021	120,000	$	2.53

Natural Gas Swaps	Price Swaps - HH(4)			Price Swaps - HSC(5)
Year	Volumes (MMBtu)		Weighted Average Price per MMBtu	Volumes (MMBtu)		Weighted Average Price per MMBtu
2020	1,890,000	$	2.70	120,000	$	2.53
2021	1,050,000	$	2.69	240,000	$	2.50
2022	720,000	$	2.76	360,000	$	2.54
2023				240,000	$	2.64

Natural Gas Collars  - HH
Year	Volumes (MMBtu)		Weighted Average Price per MMBtu - Floor		Weighted Average Price per MMBtu - Ceiling
2020	120,000	$	2.50	$	2.95

HSC
Year	Volumes (MMBtu)		Weighted Average Price per MMBtu - Floor		Weighted Average Price per MMBtu - Ceiling
2020	96,000	$	2.60	$	2.91

Subsequent to December 31, 2019, the Company entered into the following commodity derivative positions:

Oil Swaps	Price Swaps - WTI
Year	Volumes (Bbl)		Weighted Average Price per Bbl
2020	720,000	$	49.39
2021	1,980,000	$	48.38

Natural Gas Swaps	Price Swaps - HH
Year	Volumes (MMBtu)		Weighted Average Price per MMBtu
2021	600,000	$	2.67

The following is a list of index prices:

(1) WTI crude oil as quoted on NYMEX.

(2)Mont Belvieu – Texas Eastern Transmission (“TET”) propane as quoted by Oil Price Information Service (“OPIS”). 

(3)WTI Houston Argus (“WTI-HOU”) crude oil as quoted by Argus US Pipeline.

(4)Henry Hub (“HH”) natural gas as quoted on the NYMEX.

(5)Houston Ship Channel (“HSC”) natural gas as quoted in Platt’s Inside FERC.

Summary of interest rate swaps

Interest Rate Derivatives

A summary of the Company’s interest rate swaps as of December 31, 2019 follows (notional amount in thousands):

							Portion of
	Term						Term Loan
Effective Date		Termination Date	Notional Amount		Fixed Rate (1)		Face Amount
July 11, 2019		July 11, 2020	$	187,500	3.016	%	75	%
July 11, 2020		July 11, 2021	$	125,000	3.072	%	50	%
July 11, 2021		July 11, 2022	$	125,000	3.061	%	50	%
July 13, 2022		May 23, 2023	$	125,000	3.042	%	50	%

(1) Each contract has a 1% floor, consistent with the structure of the Term Loan. 

Summary of derivative instruments offset in the consolidated balance sheets

The following tables summarize the location and fair value amounts of all the Company’s derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets (in thousands):

		December 31, 2019
		Gross		Gross		Net Recognized
		Recognized		Amounts		Fair Value
Not Designated as ASC 815 Hedges	Balance Sheet Classification	Assets/Liabilities		Offset		Assets/Liabilities
DERIVATIVE ASSETS:
Current:
Derivative financial instruments — commodity contracts	Derivative assets	$	2,863	$	(1,648)	$	1,215
Derivative financial instruments — interest rate swaps	Derivative assets		8		(8)		—
Long-term:
Derivative financial instruments — commodity contracts	Derivative assets		2,637		(1,759)		878
Derivative financial instruments — interest rate swaps	Derivative assets		377		(377)		—
Total derivative assets			5,885				2,093
DERIVATIVE LIABILITIES:
Current:
Derivative financial instruments — commodity contracts	Derivative liabilities		3,946		(1,648)		2,298
Derivative financial instruments — interest rate swaps	Derivative liabilities		2,104		(8)		2,096
Total current derivative liabilities			6,050				4,394
Long-term:
Derivative financial instruments — commodity contracts	Derivative liabilities		1,761		(1,759)		2
Derivative financial instruments — interest rate swaps	Derivative liabilities		4,044		(377)		3,667
Total long-term derivative liabilities			5,805				3,669
Total derivative liabilities			11,855				8,063
		$	(5,970)			$	(5,970)

		December 31, 2018
		Gross		Gross		Net Recognized
		Recognized		Amounts		Fair Value
Not Designated as ASC 815 Hedges	Balance Sheet Classification	Assets/Liabilities		Offset		Assets/Liabilities
DERIVATIVE ASSETS:
Current:
Derivative financial instruments — commodity contracts	Derivative assets	$	24,877	$	(562)	$	24,315
Derivative financial instruments — interest rate swaps	Derivative assets		5,081		(5,081)		—
Long-term:
Derivative financial instruments — commodity contracts	Derivative assets		8,403		(400)		8,003
Derivative financial instruments — interest rate swaps	Derivative assets		11,142		(11,142)		—
Total derivative assets			49,503				32,318
DERIVATIVE LIABILITIES:
Current:
Derivative financial instruments — commodity contracts	Derivative liabilities		787		(562)		225
Derivative financial instruments — interest rate swaps	Derivative liabilities		5,292		(5,081)		211
Total current derivative liabilities			6,079				436
Long-term:
Derivative financial instruments — commodity contracts	Derivative liabilities		1,051		(400)		651
Derivative financial instruments — interest rate swaps	Derivative liabilities		13,069		(11,142)		1,927
Total long-term derivative liabilities			14,120				2,578
Total derivative liabilities			20,199				3,014
		$	29,304			$	29,304

Summary of derivative instruments in statement of operations

		Gain (Loss) Recognized in Income Year Ended December 31,
Not designated as ASC 815 Hedges	Statement of Operations Classification	2019		2018
Foreign currency	Gain on foreign currency derivative financial instruments	$	-	$	6,838
Commodity contracts	Gain (loss) on commodity derivative financial instruments		(20,542)		40,216
Interest rate swap	Interest expense		(4,270)		(2,435)
		$	(24,812)	$	44,619

XML

FAIR VALUE MEASUREMENT

12 Months Ended

Dec. 31, 2019

FAIR VALUE MEASUREMENT

FAIR VALUE MEASUREMENT

NOTE 11 — FAIR VALUE MEASUREMENT

The Company follows FASB ASC Topic 820 – Fair Value Measurement and Disclosure which establishes a three-level valuation hierarchy for disclosure of fair value measurements.  The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.  The three levels are defined as follows:

Level 1:        Quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2:        Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.

Level 3:        inputs for the asset or liability that are not based on observable market data (unobservable inputs).

The Level within which the financial asset or liability is classified is determined based on the lowest level of significant input to the fair value measurement. The financial assets and liabilities measured at fair value on a recurring basis in the consolidated balance sheets are grouped into the fair value hierarchy as follows (in thousands):

	December 31, 2019
	Level 1		Level 2		Level 3		Total
Assets measured at fair value
Derivative commodity contracts	$	—	$	2,093	$	—	$	2,093
Liabilities measured at fair value
Derivative commodity contracts		—		(2,300)		—		(2,300)
Derivative interest rate swaps		—		(5,763)		—		(5,763)
		—		(8,063)		—		(8,063)
Net fair value	$	—	$	(5,970)	$	—	$	(5,970)
	December 31, 2018
	Level 1		Level 2		Level 3		Total
Assets measured at fair value
Derivative commodity contracts	$	—	$	32,318	$	—	$	32,318
Liabilities measured at fair value
Derivative commodity contracts		—		(876)		—		(876)
Derivative interest rate swaps		—		(2,138)		—		(2,138)
		—		(3,014)		—		(3,014)
Net fair value	$	—	$	29,304	$	—	$	29,304

During the years ended December 31, 2019 and 2018, there were no transfers between Level 1 and Level 2 fair value measurements, and no transfer into or out of Level 3 fair value measurements.

Measurement of Fair Value

a) Derivatives

The Company’s derivative instruments consist of commodity contracts (primarily swaps and collars) and interest rate swaps. The Company utilizes present value techniques and option-pricing models for valuing its derivatives. Inputs to these valuation techniques include published forward prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy.

b)           Credit Facilities

As of December 31, 2019 and 2018, the Company had $250 million and $115 million, and $250 million and $65 million of principal debt outstanding on its Term Loan and Revolving Facility, respectively. The Company estimated that the fair value of its Term Loan at December 31, 2019 was $249 million.  The fair value of the Term Loan was determined by using a discounted cash flow model using a discount rate that reflects the Company’s assumed borrowing rate at the end of the reporting period. The carrying value of the Company’s Revolving Facility approximates its fair value as its variable interest rate is tied to current market rates and the applicable margins of 2.25%‑3.25% approximate market rates.

c)           Other Financial Instruments

The carrying amounts of cash, accounts receivable, accounts payable, and accrued liabilities approximate fair value due to their short-term nature.

d)Non-recurring Fair Value Measurements

The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties and assets held for sale. 

Assets held for sale.  Oil and gas properties classified as held for sale, including any corresponding asset retirement obligation, are valued using a market approach, based on an estimated net selling price.  If an estimated selling price is not available, the Company utilizes valuation techniques depending on whether the properties are proved or unproved.  These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances.

	Net Carrying Value as of			Fair Value Measurements Using
(in thousands)	December 31, 2018			Level 1	Level 2		Level 3
Assets held for sale	$	23,471	$	—	$	—	$	23,471

The Company wrote down its Dimmit County oil and gas properties, which were classified as held for sale, to the expected purchase price proceeds, less anticipated external broker marketing costs.  The Company’s estimate of the expected purchase price proceeds was based upon comparable transaction data.  The Company disposed of the Dimmit County properties in October 2019. 

Business Combinations. In estimating the fair values of assets acquired and liabilities assumed, the Company makes various assumptions, which include Level 3 inputs. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved oil and gas properties. To derive fair value, the Company prepares estimates of oil and gas reserves, applying forward strip prices to reserve quantities acquired, and estimating future operating and development costs to arrive at an estimate of undiscounted future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital (“WACC”) rate at the time of the acquisition. The market-based WACC rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, the Company reduces the discounted future net revenues of probable and possible reserves by higher discount rates or additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, the Company reviews comparable purchases and sales of oil and gas properties within the same regions and uses that data as a basis for fair market value. 

XML

LONG-TERM DEBT

12 Months Ended

Dec. 31, 2019

LONG-TERM DEBT

LONG-TERM DEBT

NOTE 7 — LONG-TERM DEBT

The following is a summary of long-term debt as of December 31, 2019 and 2018 (in thousands):

		December 31,
		2019		2018
Revolving Facility	$	115,000	$	65,000
Term Loan		250,000		250,000
Total long-term debt		365,000		315,000
Deferred financing fees, net of accumulated amortization		(11,510)		(14,196)
Total credit facilities, net of deferred financing fees	$	353,490	$	300,804

On April 23, 2018, contemporaneous with the closing of its Eagle Ford acquisition, the Company entered into the $250.0 million syndicated Term Loan with Morgan Stanley Energy Capital, as administrative agent, and the syndicated Revolving Facility with Natixis, New York Branch, as administrative agent, with initial availability of $87.5 million ($250.0 million face).  The proceeds of the refinanced debt facilities were used to retire the Company’s previous credit facilities of $192.0 million, repay the Company’s production prepayment of $11.8 million and pay deferred financing fees on the Term Loan and Revolving Facility of $16.7 million, with the balance being used for the Company’s working capital needs at the time of closing the acquisition.

The Revolving Facility and Term Loan are secured by certain of the Company’s oil and gas properties.  The Revolving Facility is subject to a borrowing base, which is redetermined at least semi-annually; the next of such redeterminations will occur in the second quarter of 2020.  The Revolving Facility will mature in October 2022, and the Term Loan will mature in April 2023.  If, upon any downward adjustment of the borrowing base, the outstanding borrowings are in excess of the revised borrowing base, the Company may have to repay its indebtedness in excess of the borrowing base immediately, or in five monthly installments.

As of December 31, 2019, the Company had letters of credit of $16.4 million outstanding on the Revolving Facility, and $38.6 million of available borrowing capacity.   

Interest on the Revolving Facility accrues at a rate equal to LIBOR, plus a margin, depending on the level of funds borrowed. As of December 31, 2019, the margin ranged from 2.25% to 3.25%  (2.5% to 3.5% prior to May 2019).  Interest on the Term Loan accrues at a rate equal to the greater of (i) LIBOR plus 8% or (ii) 9%.  As of December 31, 2019, the stated interest rates on the Revolving Facility and the Term Loan were 4.75%, and 10.1%, respectively.  As of December 31, 2018, the stated interest rates on the Revolving Facility and the Term Loan were 5.40% and 10.81%, respectively.

Subsequent to December 31, 2019, the Company entered into the fourth amendment to the Revolving Facility, which increased the borrowing base to $210 million (with elected borrowing commitments of $190 million), increased the maximum credit amount from $250 million to $500 million, revised the Leverage Ratio and Interest Coverage Ratio covenant (as reflected below) and appointed Toronto Dominion (Texas) LLC, as the administrative agent.  The amendment increased the Company’s undrawn borrowing capacity to $58.6 million as of the date of this report.   The Company is currently restricted in its ability to make draws until the finalization of its second quarter borrowing base redetermination.  Refer to Note 15 for additional information. 

Under the Revolving Facility, the Company is required to maintain the following financial ratios:

· a minimum Current Ratio, consisting of consolidated current assets (as defined in the Revolving Facility) including undrawn borrowing capacity to consolidated current liabilities (as defined in the Revolving Facility), of not less than 1.0 to 1.0 as of the last day of any fiscal quarter;

· a maximum Leverage Ratio, consisting of consolidated Total Debt to adjusted consolidated EBITDAX (as defined in the Revolving Facility), of not greater than 3.5 to 1.0 as of the last day of any fiscal quarter; and

· a minimum Interest Coverage Ratio, consisting of EBITDAX to Consolidated Interest Expense (as defined in the Revolving Facility), of not less than 1.5 to 1.0 as of the last day of any fiscal quarter (for such time as there a similar covenant under the Company’s or SEI’s subordinated indebtedness).

Under the Term Loan, the Company is required to maintain the following financial ratios:

· a minimum Interest Coverage Ratio, consisting of EBITDAX to Consolidated Interest Expense (as defined in the Term Loan), of not less than 1.5 to 1.0 as of the last day of any fiscal quarter (for such time as there a similar covenant under the Company’s or SEI’s subordinated indebtedness); and

· An Asset Coverage Ratio, consisting of Total Proved PV9% to Total Debt (as defined in the Term Loan agreement), of not less than 1.50 to 1.0.

As of December 31, 2019 and 2018, the Company was in compliance with all restrictive financial and other covenants under the Revolving Facility and Term Loan.  The Company’s credit facilities contain the requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception.  The issuance of these consolidated financial statements with the accompanying audit opinion constitutes a default under the Revolving Facility and Term Loan agreements.  The Company obtained waivers from its Revolving Facility and Term Loan lenders on May 8, 2020 and May 11, 2020, respectively, to waive the event of default arising from the inclusion of the going concern explanatory paragraph included in the audit report for the year ended December 31, 2019 and with respect to the defaults arising from a failure to deliver audited consolidated financial statements for the year ended December 31, 2019 and related reports and certificates by the applicable deadline.  These waivers were effective as of April 29, 2020, subject to the conditions set forth in the waivers.  Refer to Note 1 and Note 15 for additional information. 

XML

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2019

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Schedule of accounts receivable trade and other

	December 31,
	2019		2018
Oil, natural gas and NGL sales	$	18,211	$	16,408
Joint interest owners		260		584
Commodity hedge contract receivables and other		4,342		4,257
Receivable due from buyer (Dimmit County oil and gas properties)		4,207		—
Total accounts receivable trade and other	$	27,020	$	21,249

Schedule of percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales

Year Ended December 31, 2019
Purchaser A	60%
Purchaser B	21%
Year Ended December 31, 2018
Purchaser A	34%
Purchaser B	26%
Purchaser C	23%

XML

SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2019

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

NOTE 15 — SUBSEQUENT EVENTS

As discussed in Note 1, the Company’s credit facilities contain the requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception.  The issuance of these consolidated financial statements with the accompanying audit opinion constitutes a default under the Revolving Facility and Term Loan agreements. The Company obtained waivers from its Revolving Facility and Term Loan lenders on May 8, 2020 and May 11, 2020, respectively, to waive the event of default arising from the inclusion of the going concern explanatory paragraph included in the audit report for the year ended December 31, 2019 and with respect to the defaults arising from a failure to deliver audited consolidated financial statements for the year ended December 31, 2019 and related reports and certificates by the applicable deadline.  These waivers were effective as of April 29, 2020, subject to the conditions set forth in the waivers.  

Under the Revolving Facility waiver, the Company may not draw any additional funds on the Revolving Facility until completion of the Company’s second quarter 2020 borrowing base redetermination.     

Under the Term Loan waiver, the Company agreed to amend certain provisions in the Term Loan, as to be mutually agreed with the Term Loan lenders, within 15 days from the execution date.  The waiver under the Revolving Facility also provides for a right to require corresponding amendments of that facility manner, as requested by the administrative agent in its discretion. Failure to enter into such amendment with respect to the Term Loan within 15 days (or a similar amendment with respect to the Revolving Facility on the date the Term Loan is amended) would constitute an event of default under the credit facilities, in which case the amounts outstanding under the credit facilities could be accelerated and become immediately due and payable.  While management believes that it will finalize such amendments within the required time frame, there can be no assurance that management’s efforts will result in any finalizing these amendments or the ultimate terms of any such amendments. 

With respect to the Term Loan, the Company has engaged in preliminary discussions regarding the terms of the required amendment.  In addition, the Company has agreed to explore in good faith with its Term Loan lenders options to reduce the Company’s overall level of indebtedness and leverage and limit capital and general and administrative expenditures for some specified period of time.  As described above, the lenders under the Revolving Facility may request corresponding amendments under the Revolving Facility.

XML

ACCRUED LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2019

ACCRUED LIABILITIES

Summary of accrued liabilities

The following is a summary of accrued liabilities as of December 31, 2019 and 2018 (in thousands):

	December 31,
	2019		2018
Oil and natural gas properties:
Capital expenditures	$	4,168	$	12,879
Re-fracture liability		764		900
Lease operating and workover expenses and other		7,393		6,586
Accrued interest payable		6,885		458
General and administrative expense		6,894		4,462
Finance lease liabilities		305		—
Total accrued liabilities	$	26,409	$	25,285

XML

INCOME TAXES - Provision (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
INCOME TAXES
Current income tax expense - Federal		$ 2,301
Deferred income tax expense (benefit)
Federal	$ (8,281)	(5,555)
State	11	318
Foreign	(503)	(2,929)
Total deferred income tax (expense) benefit	(8,773)	(8,166)
Income tax provision (benefit)	4,255	19,822
Total income tax expense (benefit)	$ (4,518)	$ 13,957

XML

LONG-TERM DEBT - Summary of long-term debt (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Apr. 23, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Total long-term debt	$ 365,000	$ 315,000		$ 192,000
Deferred financing fees, net of accumulated amortization	(11,510)	(14,196)	$ (16,700)
Total credit facilities, net of deferred financing fees	353,490	300,804
Revolving Facility
Line of Credit Facility [Line Items]
Total long-term debt	115,000	65,000
Term Loan
Line of Credit Facility [Line Items]
Total long-term debt	$ 250,000	$ 250,000

XML

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Standardized Measure of Future Net Cash Flow (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Discounted rate	10.00%	10.00%
Cash inflows			$ 4,148,426	$ 4,733,751
Production costs			(1,348,892)	(1,318,059)
Development costs			(1,231,467)	(1,143,083)
Income tax expense			(183,680)	(343,068)
Net cash flow			1,384,387	1,929,541
10% annual discount rate			(709,288)	(976,916)
Standardized measure of discounted future net cash flow	$ 675,099	$ 952,625	$ 675,099	$ 952,625
Standardized Measure, beginning of year	952,625	366,747
Sales, net of production costs	(141,329)	(113,073)
Net change in sales prices, net of production costs	(422,811)	201,784
Extensions and discoveries, net of future production and development costs	258,433	206,179
Changes in future development costs	283,154	63,297
Previously estimated development costs incurred during the period	84,739	94,673
Revision of quantity estimates	(308,312)	(198,956)
Accretion of discount	110,985	38,124
Change in income taxes	79,728	(142,730)
Purchases of reserves in-place		525,547
Sales of reserves in-place	(47,059)	(220)
Change in production rates and other	(175,054)	(88,747)
Standardized Measure, end of year	$ 675,099	$ 952,625

XML

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Defined Contribution Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Company contributions	$ 0.6	$ 0.3

XML

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)

12 Months Ended

Dec. 31, 2019

QUARTERLY FINANCIAL DATA (UNAUDITED)

Summary of the unaudited quarterly financial data

The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2019 and 2018 (in thousands, except per share data):

	Three Months Ended
	March 31, 2019		June 30, 2019		September 30, 2019		December 31, 2019
Revenues	$	47,740	$	52,901	$	51,097	$	51,842
Income (loss) from operations	$	(31,804)	$	13,572	$	24,126	$	(11,944)
Net income (loss)	$	(37,209)	$	2,643	$	13,297	$	(18,321)
Income (loss) per share - basic	$	(5.41)	$	0.38	$	1.93	$	(2.67)
Income (loss) per share - diluted	$	(5.41)	$	0.38	$	1.93	$	(2.67)
	Three Months Ended
	March 31, 2018		June 30, 2018		September 30, 2018		December 31, 2018
Revenues	$	24,036	$	28,737	$	53,824	$	58,336
Income (loss) from operations	$	(9,738)	$	(47,852)	$	(13,202)	$	83,609
Net income (loss)	$	(25,731)	$	(49,673)	$	(20,249)	$	72,720
Income (loss) per share - basic	$	(19.75)	$	(8.63)	$	(2.95)	$	10.58
Income (loss) per share - diluted	$	(19.75)	$	(8.63)	$	(2.95)	$	10.58

Per share amounts have been retroactively adjusted for periods prior to the fourth quarter of 2019 to reflect the Company’s one-for-100 reverse stock split in November 2019, as described in Note 13 to these consolidated financial statements.

XML

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Oil and Gas Properties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Depletion, depreciation and amortization expense	$ 92,334	$ 62,814
Impairment expenses of proved oil and gas properties	0	0
Impairment expenses of unproved oil and gas properties	0	0
Oil and gas properties
Property, Plant and Equipment [Line Items]
Depletion, depreciation and amortization expense	$ 91,400	$ 62,100

XML

LEASES - Summary of right-of-use assets and estimated lease liabilities (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Right-of-use assets
Operating lease right-of-use assets	$ 17,331
Financial Position	us-gaap:OperatingLeaseRightOfUseAsset
Finance lease right-of-use assets	$ 747
Financial Position	us-gaap:PropertyPlantAndEquipmentNet
Total right-of-use assets	$ 18,078
Lease liabilities
Operating lease liabilities - current	$ 7,720
Financial Position	us-gaap:OperatingLeaseLiabilityCurrent
Operating lease liabilities - non-current	$ 9,611
Financial Position	us-gaap:OperatingLeaseLiabilityNoncurrent
Finance lease liabilities - current	$ 305
Financial Position	us-gaap:AccruedLiabilitiesCurrent
Finance lease liabilities - non-current	$ 429
Financial Position	us-gaap:OtherLiabilitiesNoncurrent
Total lease liabilities	$ 18,065
Additions of operating and finance lease right-of-use	18,078
Right-of-use assets in exchange for new operating lease obligations	17,358
Right-of-use assets in exchange for new finance lease obligations	$ 640

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 12,382	$ 1,581
Accounts receivable trade and other	27,020	21,249
Derivative financial instruments	1,215	24,315
Income tax receivable	3,555	2,384
Other current assets	3,616	3,547
Assets held for sale		23,471
Total current assets	47,788	76,547
Oil and gas properties, successful efforts method	1,122,908	986,548
Less: accumulated depletion, depreciation and amortization	(379,961)	(293,598)
Total oil and gas properties, net	742,947	692,950
Other long-term assets:
Other property and equipment, net of accumulated depreciation of $3,419 and $2,823	1,963	1,354
Income tax receivable	1,172	2,344
Operating lease right-of-use assets	17,331
Derivative financial instruments	878	8,003
Other long-term assets	1,835	2,150
TOTAL ASSETS	813,914	783,348
Current liabilities:
Accounts payable trade	43,284	45,137
Accrued liabilities	26,409	25,285
Derivative liabilities	4,394	436
Operating lease liabilities - current	7,720
Liabilities related to assets held for sale		193
Total current liabilities	81,807	71,051
Long-term liabilities:
Long-term debt	353,490	300,804
Asset retirement obligations	3,653	3,296
Operating lease liabilities - long term	9,611
Derivative financial instruments	3,669	2,578
Deferred tax liabilities	7,138	11,656
Other long-term liabilities	1,149	1,474
Total long-term liabilities	378,710	319,808
Total liabilities	460,517	390,859
Commitments and contingencies (Note 14)
Stockholders' Equity:
Common stock, $0.001 value, 100,000,000 shares authorized; 6,875,672 issued and outstanding at December 31, 2019 and 6,874,622 shares issued and outstanding at December 31, 2018	7	7
Additional paid-in capital	633,246	632,742
Accumulated deficit	(279,144)	(239,554)
Accumulated other comprehensive loss	(712)	(706)
Total stockholders' equity	353,397	392,489
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 813,914	$ 783,348

XML

ACQUISITIONS AND DISPOSITIONS - Revenues And Direct Operating Expenses (Details) - USD ($) $ in Thousands	3 Months Ended								8 Months Ended	12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Income (loss) from operations:	$ (11,944)	$ 24,126	$ 13,572	$ (31,804)	$ 83,609	$ (13,202)	$ (47,852)	$ (9,738)		$ (6,050)	$ 12,817
Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC
Business Acquisition [Line Items]
Revenues									$ 64,507
Direct Operating Expenses									(45,194)
Income (loss) from operations:									$ 19,313

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$ (39,590)	$ (22,933)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization expense	92,334	62,814
Impairment expense	9,990	43,828
Loss on abandonment of unproved oil and gas properties		550
Stock-based compensation	504	515
Deferred income tax (benefit) expense	(4,518)	11,656
Gain on foreign currency derivative financial instruments		(6,838)
Loss (gain) on commodity derivative financial instruments	20,542	(40,216)
Net cash settlements received on commodity derivative contracts	11,258	(599)
Premiums (paid) received on commodity derivative contracts	(152)	634
Unrealized loss on interest rate swaps	3,625	2,137
Amortization of deferred financing fees	3,234	2,281
Write-off of deferred financing fees		251
Other	(83)
Changes in assets and liabilities:
Accounts receivable trade and other	2,539	(17,728)
Accounts payable trade	2,512	9,014
Accrued liabilities	9,803	(1,144)
Other assets and liabilities, net	(769)	(408)
Net cash provided by operating activities	111,229	43,814
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for proved oil and gas properties	(166,646)	(168,956)
Capital expenditures for unproved oil and gas properties	(319)	(1,790)
Acquisition of oil and gas properties		(215,790)
Proceeds from the sale of oil and gas properties	17,383	100
Other property and equipment	(407)	(352)
Net cash used in investing activities	(149,989)	(386,788)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	50,000	315,000
Repayments of borrowings		(210,194)
Payments of debt issuance costs	(232)	(16,040)
Proceeds from issuance of common shares		253,517
Equity offering costs		(10,293)
Receipts from foreign currency derivatives		6,838
Principal payments on finance lease obligations	(187)	(11)
Net cash provided by financing activities	49,581	338,817
Net change in cash and cash equivalents	10,821	(4,157)
CASH AND CASH EQUIVALENTS
Beginning of year	1,581	5,761
Effect of exchange rates on cash	(20)	(23)
End of year	12,382	1,581
SUPPLEMENTAL CASH FLOW DISCLOSURES
Income taxes paid		2,301
Interest paid, net of amounts capitalized	26,203	26,359
NON-CASH INVESTING AND FINANCING ACTIVITIES
Accounts payable and accrued expenses for oil and gas properties	$ 25,000	$ 38,508

XML

EARNINGS PER SHARE - Reconciliation (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
EARNINGS PER SHARE
Net loss	$ (18,321)	$ 13,297	$ 2,643	$ (37,209)	$ 72,720	$ (20,249)	$ (49,673)	$ (25,731)	$ (39,590)	$ (22,933)
Weighted average shares :
Weighted average common shares outstanding, basic									6,874,170	5,236,524
Weighted average common shares outstanding, diluted									6,874,170	5,236,524
Net loss per share:
Basic and diluted									$ (5.76)	$ (4.38)

XML

DERIVATIVE FINANCIAL INSTRUMENTS - Narrative (Details) - Revolving Facility	12 Months Ended
	Dec. 31, 2019
Projected Period Thirty Six Months
Derivative
Hedging period of proved reserves classified as Developed Producing Reserves	36 months
Maximum | Projected Period Thirty Six Months
Derivative
Hedging percentage of reasonably projected oil and gas production	85.00%
Maximum | Projected Period Thirty Seven to Sixty Months
Derivative
Hedging percentage of reasonably projected oil and gas production	75.00%
Hedging period of proved reserves classified as Developed Producing Reserves	60 months
Minimum | Projected Period Thirty Six Months
Derivative
Hedging percentage of reasonably projected oil and gas production	50.00%
Minimum | Projected Period Thirty Seven to Sixty Months
Derivative
Hedging period of proved reserves classified as Developed Producing Reserves	25 months

XML

DERIVATIVE FINANCIAL INSTRUMENTS - Offsetting of Derivative Liabilities (Details) - Not designated as ASC 815 Hedges - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Offsetting Liabilities
Gross Recognized Liabilities	$ 11,855	$ 20,199
Net Recognized Fair Value Liabilities	8,063	3,014
Gross Recognized Assets/ Liabilities	(5,970)	29,304
Net Recognized Fair Value Assets/ Liabilities	(5,970)	29,304
Derivative liabilities current
Offsetting Liabilities
Gross Recognized Liabilities	6,050	6,079
Net Recognized Fair Value Liabilities	4,394	436
Derivative liabilities non-current
Offsetting Liabilities
Gross Recognized Liabilities	5,805	14,120
Net Recognized Fair Value Liabilities	3,669	2,578
Derivative commodity contracts | Derivative liabilities current
Offsetting Liabilities
Gross Recognized Liabilities	3,946	787
Gross Amounts Offset	(1,648)	(562)
Net Recognized Fair Value Liabilities	2,298	225
Derivative commodity contracts | Derivative liabilities non-current
Offsetting Liabilities
Gross Recognized Liabilities	1,761	1,051
Gross Amounts Offset	(1,759)	(400)
Net Recognized Fair Value Liabilities	2	651
Derivative interest rate swaps | Derivative liabilities current
Offsetting Liabilities
Gross Recognized Liabilities	2,104	5,292
Gross Amounts Offset	(8)	(5,081)
Net Recognized Fair Value Liabilities	2,096	211
Derivative interest rate swaps | Derivative liabilities non-current
Offsetting Liabilities
Gross Recognized Liabilities	4,044	13,069
Gross Amounts Offset	(377)	(11,142)
Net Recognized Fair Value Liabilities	$ 3,667	$ 1,927

XML

EQUITY - Stock Based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
EQUITY
Recognized stock based compensation expense	$ 504	$ 515

XML

COMMITMENTS AND CONTINGENCIES - Total Commitments (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Minimum revenue commitment
2020	$ 21,807
2021	21,485
2022	10,992
Total	54,284
Hydrocarbon gathering and handling agreement
Minimum revenue commitment
2020	14,297
2021	13,972
2022	6,675
Total	34,944
Crude oil and condensate purchase agreements
Minimum revenue commitment
2020	4,710
2021	7,513
2022	4,317
Total	16,540
Gas processing agreement
Minimum revenue commitment
2020	2,017
Total	2,017
Gas transportation agreements
Minimum revenue commitment
2020	783
Total	783
Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC
Minimum revenue commitment
Total	$ 15,800	$ 11,100

XML

FAIR VALUE MEASUREMENT - Credit Facilities (Details) $ in Thousands	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Debt Instrument [Line Items]
Principal debt outstanding	$ 365,000	$ 315,000	$ 192,000
Debt, valuation technique	Us-gaap:ValuationTechniqueDiscountedCashFlowMember
Debt, Input	Us-gaap:MeasurementInputPrepaymentRateMember
Maximum
Debt Instrument [Line Items]
Debt measurement input	0.0325
Minimum
Debt Instrument [Line Items]
Debt measurement input	0.0225
Revolving Facility
Debt Instrument [Line Items]
Principal debt outstanding	$ 115,000	65,000
Term Loan
Debt Instrument [Line Items]
Principal debt outstanding	250,000	$ 250,000
Fair value of its Term Loan	$ 249,000

XML

EQUITY

12 Months Ended

Dec. 31, 2019

EQUITY

EQUITY

NOTE 13 — EQUITY

Reverse Stock Split

In conjunction with the Company’s Redomiciliation, the Company acquired all of the outstanding ordinary shares of SEAL on the basis of one share of the Company’s stock for every 100 ordinary shares outstanding, which had the effect of a 1-for-100 reverse stock split.  On the effective date of the Redomiciliation, the number of ordinary outstanding shares was reduced from 687 million to 6.9 million.  All share and per share amounts in these consolidated financial statements and related notes for periods prior to the Redomiciliation have been retroactively adjusted to reflect the effect of the exchange ratio.

Equity Offerings

During 2018, the Company issued 5,614,446 shares in connection with a $243 million capital raise (net of offering costs), proceeds of which were used to complete the 2018 acquisition of Eagle Ford oil and gas properties.

Stock-Based Compensation

For the years ended December 31, 2019 and 2018, the Company recognized stock-based compensation expense of $0.5 million and $0.5 million, respectively, related to RSUs (equity-settled).

During the years ended December 31, 2019 and 2018, the Board of Directors awarded 38,373 and 71,175 RSUs, respectively, to certain employees. These awards were made in accordance with SEAL’s Plan.  In connection with the Redomiciliation, in November 2019 Sundance Energy Inc. assumed SEAL’s obligations with respect to the settlement of the RSUs that were granted pursuant to the Plan prior to the effective date of the Redomiciliation.  Accordingly, the RSUs will be settled in shares of common stock of Sundance Energy Inc. rather than ordinary shares of SEAL.  Following the effective date of the Redomiciliation, no new awards or grants have been or will be made pursuant to the Plan.  Historical RSU information is summarized below:

		Weighted Average
		Fair Value at
	Number of RSUs	Grant Date
Outstanding at December 31, 2017	33,804	$	166.87
Granted	71,175	$	18.80
Vested	(6,916)	$	361.03
Forfeited	(6,724)	$	198.37
Outstanding at December 31, 2018	91,339	$	34.37
Granted	38,373	$	20.31
Vested (1)	(1,425)	$	61.56
Forfeited	(43,358)	$	51.20
Outstanding at December 31, 2019	84,929	$	22.97

⁽¹⁾ Includes 375 RSUs that have vested, but will be settled in 2020.

Restricted Share Units on Issue

Details of the RSUs outstanding as of December 31, 2019 and 2018:

	Number of RSUs
Grant Date	2019	2018
March 15, 2016 (1)	—	4,428
May 27, 2016 (1)	—	4,342
June 29, 2016 (1)	—	497
February 17, 2017 (1)(2)	3,411	4,572
May 25, 2017 (1)(2)	3,724	3,724
October 23, 2017 (1)	745	745
October 23, 2017	375	750
December 29, 2017	497	1,106
December 26, 2018 (3)	30,414	35,587
December 26, 2018 (4)	15,207	35,588
May 5, 2019	1,775	—
May 5, 2019 (1)	5,325	—
May 31, 2019 (3)	15,637	—
May 31, 2019 (4)	7,819	—
Total RSUs outstanding	84,929	91,339

⁽¹⁾ RSUs vest based on three‑year absolute total shareholder return (“ATSR”).

⁽²⁾ ATSR RSUs were evaluated for vesting subsequent to December 31, 2019.  The vesting conditions were not met and the outstanding awards will be forfeited in 2020.

⁽³⁾ RSUs vest based on three-year total shareholder return (“TSR”) as compared to the XOP index.

⁽⁴⁾ Company performance-based RSUs vest based on 2019 and 2020 EBITDA per debt adjusted share and production per debt adjusted share.

The following tables summarize the RSUs issued and their related grant date, fair value and vesting conditions. RSUs awarded during the year ended December 31, 2019:

		Fair Value at
Grant Date	Number of RSUs	Grant Date		Vesting Conditions
May 5, 2019	1,775	$	29.49	Vests on 3rd anniversary of award
May 5, 2019	5,325	$	16.35	0 % - 200% based on 3 year TSR as compared to the XOP index.
May 31, 2019	15,637	$	16.13	0 % - 200% based on 3 year TSR as compared to the XOP index.
May 31, 2019	3,909	$	24.92	0 % - 200% based on 2019 EBITDA per Debt Adjusted Share
May 31, 2019	3,909	$	24.92	0 % - 200% based on 2020 EBITDA per Debt Adjusted Share
May 31, 2019	3,909	$	24.92	0 % - 200% based on 2019 Production per Debt Adjusted Share
May 31, 2019	3,909	$	24.92	0 % - 200% based on 2020 Production per Debt Adjusted Share
	38,373

The following tables summarize the RSUs issued and their related grant date, fair value and vesting conditions. RSUs awarded during the year ended December 31, 2018:

		Fair Value at
Grant Date	Number of RSUs	Grant Date		Vesting Conditions
December 26, 2018	35,587	$	16.44	0 % - 200% based on 3 year TSR as compared to the XOP index
December 26, 2018	8,897	$	21.16	0 % - 200% based on 2019 EBITDA per Debt Adjusted Share
December 26, 2018	8,897	$	21.16	0 % - 200% based on 2020 EBITDA per Debt Adjusted Share
December 26, 2018	8,897	$	21.16	0 % - 200% based on 2019 Production per Debt Adjusted Share
December 26, 2018	8,897	$	21.16	0 % - 200% based on 2020 Production per Debt Adjusted Share
	71,175

Upon vesting, and after a certain administrative period, the RSUs are settled in newly issued common stock of the Company. Once settled, the RSUs are no longer restricted. As of December 31, 2019, the remaining expense associated with unvested RSUs was $0.5 million, which will be recognized over the weighted average remaining contractual life of the RSUs of 1.0 years. For the years ended December 31, 2019 and 2018, the weighted average prices of the RSUs at the date of conversion were $22.02 and $70.85, per share, respectively. At December 31, 2019, the fair value of the RSU awards expected to vest was $0.1 million. 

XML

INCOME TAXES

12 Months Ended

Dec. 31, 2019

INCOME TAXES

INCOME TAXES

NOTE 9 — INCOME TAXES

Income taxes are computed using the asset and liability method.  Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits, and tax credit carryforwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.

The income tax provision is comprised of the following (in thousands):

	Year Ended December 31,
	2019		2018
Current income tax expense - Federal	$	—	$	2,301
Deferred income tax expense (benefit)
Federal		(8,281)		(5,555)
State		11		318
Foreign		(503)		(2,929)
Total deferred income tax expense (benefit)		(8,773)		(8,166)
Valuation Allowance
Income tax provision (benefit)		4,255		19,822
Total income tax expense (benefit)	$	(4,518)	$	13,957

A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands):

	Year Ended December 31,
		2019		2018
Income tax benefit at the federal statutory rate	$	(9,263)	$	(1,885)
State income taxes - net of federal income tax benefits		10		290
Stock-based compensation		114		839
Nondeductible expenses		519		1,055
Change in valuation allowance		4,255		19,822
Foreign tax rates		(166)		(877)
Australian tax losses on U.S. Restructuring		—		(3,284)
Deemed interest payment due to U.S. restructuring		—		(4,350)
U.S. withholding tax net of foreign tax credit		—		2,301
Other		13		46
Total income tax expense (benefit)	$	(4,518)	$	13,957

In 2018 in connection with the equity raise to fund the Company’s Eagle Ford acquisition, the Company had a greater than 50% ownership change pursuant to Section 382 of the Internal Revenue Code.  As a result of the ownership change, the Company’s ability to use pre-change net operating losses (“NOLs”) and credits against post-change taxable income is limited to an annual amount plus any built-in gains recognized within five years of the ownership change.  The Company’s use of pre-change losses of $248.5 million will be limited to approximately $42.3 million.  Accordingly, the Company recorded a valuation allowance to reduce its deferred tax assets.

As of December 31, 2019, the Company had U.S. federal NOL carryforwards of $292.4 million.   The Company also has various state NOL carryforwards. The determination of the state NOL carryforwards is dependent upon apportionment percentages and state laws that can change from year to year and that can thereby impact the amount of such carryforwards.  If unutilized, the majority of the federal NOLs will expire between 2033 and 2037 and the state NOLs will expire between 2021 and 2037.  Any federal NOLs generated in 2018 or subsequent do not expire.  The Company also has Australian NOLs of $26.2 million that do not expire.

The Company completed a restructuring of its U.S. subsidiaries during the year ended December 31, 2018.  The restructuring resulted in recognized tax losses under Australian tax law of $15.6 million creating loss carryover available to offset future income.  As the Company does not believe it is more likely than not that these carryovers will be utilized in the future, it has recorded a valuation allowance against the Australian deferred tax assets. Additionally, the restructuring resulted in a deemed payment of interest from the U.S. subsidiaries to the Company of $20.7 million which required the Company to pay a $2.3 million withholding tax. 

In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized.  Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required.  Such evidence includes the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making this assessment.  Judgment is required in considering the relative weight of negative and positive evidence.  The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits, and other deferred tax assets will be utilized prior to their expiration.  As a result, it may be determined that a deferred tax asset valuation allowance should be established or released.  Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense.

The tax effects of temporary differences that give rise to significant components of the deferred income tax assets and deferred tax liabilities at each of the period ends is presented in the following table (in thousands):

	December 31,
		2019		2018
Deferred tax assets:
Net operating loss carryforward	$	76,624	$	70,560
Business interest carryforward		10,474		7,054
Stock-based compensation		93		102
Statutory depletion carryforward		2,927		2,977
Unrealized (gain) loss on commodity derivative		1,147		(6,453)
Lease obligations		3,735		—
Property, plant and equipment		82		(122)
Other assets		524		1,688
Total deferred tax assets		95,606		75,806
Valuation allowance		(64,898)		(60,643)
Deferred tax assets, net		30,708		15,163
Deferred tax liabilities:
Basis of oil and gas properties		(33,950)		(26,819)
Lease assets		(3,896)		—
Total deferred tax liabilities		(37,846)		(26,819)
Deferred tax liabilities, net	$	(7,138)	$	(11,656)

As of December 31, 2019, the Company had no unrecognized tax benefits.  The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position.  Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards, and would not result in significant interest expense or penalties.  The Company’s federal and state tax returns filed since December 31, 2016 and December 31, 2015, respectively, remain subject to examination by tax authorities.  The Company's Australian tax returns filed since December 31, 2015 also remain subject to examination.

On March 27, 2020, President Trump signed into U.S. federal law the CARES Act, which is aimed at providing emergency assistance and health care for individuals, families, and businesses affected by the COVID-19 pandemic and generally supporting the U.S. economy. 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  (“AMT”) refunds, modifications to the net interest deduction limitations and technical corrections to tax depreciation methods for qualified improvement property. In particular, the CARES Act, (i) eliminates the 80% of taxable income limitation by allowing corporate entities to fully utilize NOLs to offset taxable income in 2018, 2019 or 2020, (ii) allows for NOLs generated in 2018, 2019, or 2020 to be carried back 5 years, (iii) increases the net interest expense deduction limit to 50% of adjusted taxable income from 30% for tax years beginning January 1, 2019 and 2020, and (iv) allows taxpayers with AMT credits to claim a refund in 2019 for the entire amount of the credit instead of recovering the credit through refunds over a period of years, as originally enacted by the Tax Cuts and Jobs Act in 2017.  The Company is in the process of analyzing the different aspects of the CARES Act to quantify the impact of these provisions.

XML

ACCRUED LIABILITIES

12 Months Ended

Dec. 31, 2019

ACCRUED LIABILITIES

ACCRUED LIABILITIES

NOTE 5 — ACCRUED LIABILITIES

The following is a summary of accrued liabilities as of December 31, 2019 and 2018 (in thousands):

	December 31,
	2019		2018
Oil and natural gas properties:
Capital expenditures	$	4,168	$	12,879
Re-fracture liability		764		900
Lease operating and workover expenses and other		7,393		6,586
Accrued interest payable		6,885		458
General and administrative expense		6,894		4,462
Finance lease liabilities		305		—
Total accrued liabilities	$	26,409	$	25,285

The Company entered into an agreement with Schlumberger Limited (“Schlumberger”) to re‐fracture five Eagle Ford wells in 2016. Under the terms of the agreement, Schlumberger will be paid for the services, plus a premium (if applicable), from the cash flow resulting from the incremental production generated by the re‐fractured wells above the forecasted base production prior to the re‐fracture work. The term of the agreement is five years and expires in 2021. The estimate of the remaining payout amount requires judgements regarding future production, pricing, operating costs and discount rates.  The estimate of the related current liability is included above as the re-fracture liability.  In addition, the Company recorded a long term liability related to the refracture services of $0.7 million and $1.1 million as of December 31, 2019 and 2018, respectively, which is included in other long-term liabilities on the consolidated balance sheets.

XML

ASSET RETIREMENT OBLIGATIONS (Tables)

12 Months Ended

Dec. 31, 2019

ASSET RETIREMENT OBLIGATIONS

Schedule of reconciliation of the Company’s asset retirement obligations

The following table provides a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2019 and 2018 (in thousands):

	December 31,
	2019		2018
Balance, beginning of year	$	3,489	$	1,549
Additional liability incurred		145		195
Obligations settled		(85)		(29)
Obligations on assets acquired		—		1,522
Obligations on assets sold		(232)		—
Accretion expense		336		252
Balance, end of year	$	3,653	$	3,489
Liabilities related to assets held for sale	$	—	$	193
Long-term		3,653		3,296
	$	3,653	$	3,489

XML

EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2019

EARNINGS PER SHARE

Schedule of reconciliation between basic and diluted earnings per share

The reconciliations between basic and diluted earnings (loss) per share are as follows (in thousands, except per share data):

	Year Ended December 31,
	2019		2018
Net loss	$	(39,590)	$	(22,933)
Weighted average shares (1):
Weighted average common shares outstanding, basic		6,874,170		5,236,524
Diluted effect of incremental shares related to restricted share units (2)		—		—
Weighted average common shares outstanding, diluted		6,874,170		5,236,524
Net loss per share:
Basic and diluted	$	(5.76)	$	(4.38)

(1) All share numbers have been retroactively adjusted for the 2019 and 2018 periods to reflect the Company’s one for 100 share consolidation in November 2019, as described in Note 13. 

For the year ended December 31, 2019, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes anti-dilutive shares of 320 shares of service-based awards.  For the year ended December 31, 2018, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes anti-dilutive shares of 786 shares of service-based awards.

XML

ACQUISITIONS AND DISPOSITIONS (Tables)

12 Months Ended

Dec. 31, 2019

Business Acquisition [Line Items]

Schedule of fair value of the assets acquired and the liabilities assumed

The following table reflects the fair value of the assets acquired and the liabilities assumed (in thousands):

Assets Acquired:	December 31, 2018
Oil and gas properties
Proved	$	173,750
Unproved		43,642
Liabilities Assumed:
Trade and other payables		(80)
Asset retirement obligation		(1,522)
Net assets acquired	$	215,790

Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC

Business Acquisition [Line Items]

Schedule of revenues and direct operating expenses, including depletion, depreciation and amortization expense from acquired properties.

Revenues	$	64,507
Direct operating expenses (1)		(45,194)
Income from operations	$	19,313

(1) Direct operating expenses include lease operating and workover expense, gathering, processing and transportation expense, production taxes and depreciation, depletion and amortization expense.

XML

QUARTERLY FINANCIAL DATA (UNAUDITED)

12 Months Ended

Dec. 31, 2019

QUARTERLY FINANCIAL DATA (UNAUDITED)

QUARTERLY FINANCIAL DATA (UNAUDITED)

NOTE 17—QUARTERLY FINANCIALDATA (UNAUDITED)

The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2019 and 2018 (in thousands, except per share data):

	Three Months Ended
	March 31, 2019		June 30, 2019		September 30, 2019		December 31, 2019
Revenues	$	47,740	$	52,901	$	51,097	$	51,842
Income (loss) from operations	$	(31,804)	$	13,572	$	24,126	$	(11,944)
Net income (loss)	$	(37,209)	$	2,643	$	13,297	$	(18,321)
Income (loss) per share - basic	$	(5.41)	$	0.38	$	1.93	$	(2.67)
Income (loss) per share - diluted	$	(5.41)	$	0.38	$	1.93	$	(2.67)
	Three Months Ended
	March 31, 2018		June 30, 2018		September 30, 2018		December 31, 2018
Revenues	$	24,036	$	28,737	$	53,824	$	58,336
Income (loss) from operations	$	(9,738)	$	(47,852)	$	(13,202)	$	83,609
Net income (loss)	$	(25,731)	$	(49,673)	$	(20,249)	$	72,720
Income (loss) per share - basic	$	(19.75)	$	(8.63)	$	(2.95)	$	10.58
Income (loss) per share - diluted	$	(19.75)	$	(8.63)	$	(2.95)	$	10.58

⁽¹⁾ Per share amounts have been retroactively adjusted for periods prior to the fourth quarter of 2019 to reflect the Company’s one-for-100 reverse stock split in November 2019, as described in Note 13 to these consolidated financial statements.

XML

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Accounts Receivable Trade and Other (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Allowance for doubtful accounts	$ 0	$ 0
Oil , natural gas and NGL sales	18,211	16,408
Joint interest owners	260	584
Commodity hedge contract receivables and other	4,342	4,257
Receivable from sale of assets held for sale	4,207
Total accounts receivable trade and other	$ 27,020	$ 21,249

XML

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Revenue Recognition (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) item	Dec. 31, 2018 USD ($)
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Number of types of contracts | item	3
Period within which settlement is received	2 months
Accounts receivable balance from contracts with customers | $	$ 18.2	$ 16.4

XML

INCOME TAXES - Net Deferred Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets (liabilities):
Net operating loss carryforward	$ 76,624	$ 70,560
Business interest carryforward	10,474	7,054
Stock-based compensation	93	102
Statutory depletion carryforward	2,927	2,977
Unrealized (gain) loss on commodity derivative	1,147	(6,453)
Lease obligations	3,735
Property, plant and equipment	82
Property, plant and equipment		(122)
Other assets	524	1,688
Total deferred tax assets	95,606	75,806
Valuation allowance	(64,898)	(60,643)
Deferred tax assets, net	30,708	15,163
Basis of oil and gas properties	(33,950)	(26,819)
Lease assets	(3,896)
Total deferred tax liabilities	(37,846)	(26,819)
Deferred tax liabilities, net	$ (7,138)	$ (11,656)

XML

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended								12 Months Ended
	Nov. 30, 2019	Dec. 31, 2019 USD ($) $ / shares	Sep. 30, 2019 USD ($) $ / shares	Jun. 30, 2019 USD ($) $ / shares	Mar. 31, 2019 USD ($) $ / shares	Dec. 31, 2018 USD ($) $ / shares	Sep. 30, 2018 USD ($) $ / shares	Jun. 30, 2018 USD ($) $ / shares	Mar. 31, 2018 USD ($) $ / shares	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
QUARTERLY FINANCIAL DATA (UNAUDITED)
Revenues		$ 51,842	$ 51,097	$ 52,901	$ 47,740	$ 58,336	$ 53,824	$ 28,737	$ 24,036	$ 203,580	$ 164,933
Income (loss) from operations		(11,944)	24,126	13,572	(31,804)	83,609	(13,202)	(47,852)	(9,738)	(6,050)	12,817
Net income (loss)		$ (18,321)	$ 13,297	$ 2,643	$ (37,209)	$ 72,720	$ (20,249)	$ (49,673)	$ (25,731)	$ (39,590)	$ (22,933)
Income (loss) per share - basic | $ / shares		$ (2.67)	$ 1.93	$ 0.38	$ (5.41)	$ 10.58	$ (2.95)	$ (8.63)	$ (19.75)
Income (loss) per share - diluted | $ / shares		$ (2.67)	$ 1.93	$ 0.38	$ (5.41)	$ 10.58	$ (2.95)	$ (8.63)	$ (19.75)
Conversion ratio	0.01									0.01

XML

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance, beginning of year	$ 3,489	$ 1,549
Additional liability incurred	145	195
Obligations settled	(85)	(29)
Obligations on assets acquired		1,522
Obligations on assets sold	(232)
Accretion expense	336	252
Balance, end of year	3,653	3,489
Liabilities related to assets held for sale				$ 193
Long-term			$ 3,653	3,296
Total	$ 3,653	$ 3,489	$ 3,653	$ 3,489

XML

LEASES - Summary of lease obligations (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Operating leases
2020	$ 7,848
2021	4,061
2022	2,819
2023	2,192
2024	845
Thereafter	1,481
Total	19,246
Less interest	(1,915)
Total discounted lease payments	17,331
Finance Leases
2020	312
2021	305
2022	150
2023	12
Total	779
Less interest	(45)
Total discounted lease payments	734
Additions of operating and finance lease right-of-use	18,078
Additional lease obligations	$ 18,065

XML

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - SEC Oil and Gas Reserve Information (Details)	12 Months Ended
	Dec. 31, 2019 MBoe MMcf MBbls	Dec. 31, 2018 MBoe MMcf MBbls
Proved reserves:
Discounted rate	10.00%	10.00%
Proved developed and undeveloped reserve, net energy, beginning balance (MBoe) | MBoe	93,241	47,079
Revisions of previous estimates (MBoe) | MBoe	(23,168)	(10,716)
Extensions and discoveries (MBoe) | MBoe	39,649	11,904
Purchases of reserves in-place (MBoe) | MBoe		48,503
Production (MBoe) | MBoe	(4,836)	(3,508)
Sales of reserves in-place (MBoe) | MBoe	(3,814)	(21)
Proved developed and undeveloped reserve, net energy, ending balance (MBoe) | MBoe	101,072	93,241
Proved developed reserves (MBoe) | MBoe	24,611	27,197
Proved undeveloped reserves (MBoe) | MBoe	76,461	66,044
Oil
Proved reserves:
Proved developed and undeveloped reserve, net, beginning balance	58,629	27,987
Revisions of previous estimates	(14,358)	(5,138)
Extensions and discoveries	23,018	7,577
Purchases of reserves in-place		30,474
Production	(3,077)	(2,256)
Sales of reserves in-place	(1,424)	(15)
Proved developed and undeveloped reserve, net, ending balance	62,788	58,629
Proved developed reserves	16,101	16,742
Proved undeveloped reserves	46,687	41,887
Gas
Proved reserves:
Proved developed and undeveloped reserve, net, beginning balance | MMcf	108,841	59,409
Revisions of previous estimates | MMcf	(27,504)	(14,257)
Extensions and discoveries | MMcf	52,297	12,889
Purchases of reserves in-place | MMcf		55,367
Production | MMcf	(5,768)	(4,534)
Sales of reserves in-place | MMcf	(6,962)	(33)
Proved developed and undeveloped reserve, net, ending balance | MMcf	120,904	108,841
Proved developed reserves | MMcf	26,930	33,169
Proved undeveloped reserves | MMcf	93,974	75,672
Natural gas liquid sales
Proved reserves:
Proved developed and undeveloped reserve, net, beginning balance	16,472	9,190
Revisions of previous estimates	(4,225)	(3,201)
Extensions and discoveries	7,915	2,179
Purchases of reserves in-place		8,801
Production	(798)	(497)
Sales of reserves in-place	(1,230)
Proved developed and undeveloped reserve, net, ending balance	18,134	16,472
Proved developed reserves	4,022	4,927
Proved undeveloped reserves	14,112	11,545

XML

OIL AND GAS PROPERTIES (Tables)

12 Months Ended

Dec. 31, 2019

OIL AND GAS PROPERTIES.

Schedule of oil and gas producing activities

	December 31,
	2019		2018
Oil and gas properties, successful efforts method:
Unproved	$	25,037	$	48,049
Proved		1,090,774		925,551
Work in progress		7,097		12,948
		1,122,908		986,548
Accumulated depletion, depreciation and amortization		(379,961)		(293,598)
Oil and gas properties, net	$	742,947	$	692,950

XML

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

12 Months Ended

Dec. 31, 2019

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

NOTE 16 — SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Costs Incurred

The Company’s oil and gas activities for 2019 and 2018 were entirely within the United States.  Costs incurred in oil and gas producing activities were as follows (in thousands):

	Year ended December 31,
	2019		2018
Property acquisition costs
Proved	$	—	$	173,750
Unproved (1)		177		45,252
Exploration costs		335		2,789
Development costs (2) (3)		149,766		181,463

⁽¹⁾ Includes costs incurred related to its Dimmit County assets, which were classified as held for sale during 2018 through their sale in October 2019, of nil and $1.0 million during the years ended December 31, 2019 and 2018, respectively.

⁽²⁾ Development costs include $7.1 million and $12.9 million wells in-progress as of December 31, 2019 and 2018, respectively.  These wells in-progress were either drilling, waiting on hydraulic fracturing or production testing.    

⁽³⁾ Includes costs incurred related to its Dimmit County assets, which were classified as held for sale during 2018 through their sale in October 2019, of $8.4 million and $5.3 million during the years ended December 31, 2019 and 2018, respectively.

SEC Oil and Gas Reserve Information

Ryder Scott Company, L.P., an independent petroleum engineering consulting firm, prepared estimates of all of the Company’s proved reserve quantities and pre-tax future net cash flows discounted at 10% as of December 31, 2019 and 2018.

Proved reserves are those quantities of oil and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and 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.

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The estimation of our proved reserves employs one or more of the following: production trend extrapolation, analogy, volumetric assessment and material balance analysis. Techniques including review of production and pressure histories, analysis of electric logs and fluid tests, and interpretations of geologic and geophysical data are also involved in this estimation process.

The following reserve data represents estimates only and should not be construed as being exact. All such reserves are located in the continental United States.

		Natural
	Oil	Gas	NGL	Total
	(MBbl)	(MMcf)	(MBbl)	(MBoe)
Proved reserves:
January 1, 2018	27,987	59,409	9,190	47,079
Revisions of previous estimates	(5,138)	(14,257)	(3,201)	(10,716)
Extensions and discoveries	7,577	12,889	2,179	11,904
Purchases of reserves in-place	30,474	55,367	8,801	48,503
Production	(2,256)	(4,534)	(497)	(3,508)
Sales of reserves in-place	(15)	(33)	-	(21)
December 31, 2018	58,629	108,841	16,472	93,241
Revisions of previous estimates	(14,358)	(27,504)	(4,225)	(23,168)
Extensions and discoveries	23,018	52,297	7,915	39,649
Production	(3,077)	(5,768)	(798)	(4,836)
Sales of reserves in-place	(1,424)	(6,962)	(1,230)	(3,814)
December 31, 2019	62,788	120,904	18,134	101,072
Proved developed reserves:
December 31, 2018	16,742	33,169	4,927	27,197
December 31, 2019	16,101	26,930	4,022	24,611
Proved undeveloped reserves
December 31, 2018	41,887	75,672	11,545	66,044
December 31, 2019	46,687	93,974	14,112	76,461

Notable changes in proved reserves for the years ended December 31, 2019 and 2018 included the following:

Proved Undeveloped Reserves

As of December 31, 2019, the Company’s proved undeveloped reserves were approximately 76,461 MBoe, an increase of 10,417 MBoe over its December 31, 2018 proved undeveloped reserves estimate of approximately 66,044 MBoe.  The change primarily resulted from proved undeveloped locations added in 2019 as result of the Company’s technical evaluation of wells drilled and completed in late 2018 and in 2019 on properties acquired in 2018 (extensions and discoveries totaled 36,535 MBoe during the year).  As of December 31, 2018, the Company was still in the process of evaluating many of the undeveloped locations acquired in 2018. As of December 31, 2018 approximately half of the undeveloped locations in its development plan were on acreage acquired in the 2018 acquisition.  The remainder of the December 31, 2018 proved undeveloped locations were on properties that the Company owned prior to the 2018 acquisition (legacy properties or legacy locations).  As a result of the Company’s additional technical evaluation of the acquired properties during 2019, the focus of its development plan shifted to properties acquired in 2018 with higher projected returns.  Approximately 19,881 MBoe primarily associated with approximately 50 proved undeveloped locations on legacy properties were removed and 80 locations on the acquired assets with 35,630 MBoe were added to the Company’s five-year development plan.  During 2019, the Company converted 4,501 MBoe of proved undeveloped reserves to proved developed producing reserves. 

Over the next five years, the Company expects to fund future development costs of $1,173.2 million associated with proved undeveloped reserves with operating cash flows from its existing proved developed reserves, cash flows from proved undeveloped reserves converted to proved developed reserves and with capacity available under its Revolving Credit Facility as of December 31, 2019. Using December 31, 2019 SEC price assumptions, the Company’s undiscounted operating cash flows from its proved reserves are expected to be approximately $1,503.7 million over the next five years which is adequate to fund projected future development costs, administrative expenses and interest.  The Company’s development plan does not contemplate a uniform conversion of proved undeveloped reserves. At December 31, 2019, the Company’s five-year development plan assumed a slower development pace in 2020 and 2021, which would allow operating cash flow to accumulate.  The Company intends to use the accumulated cash flow to fund an increased pace of development in later years such that all remaining proved undeveloped locations would be developed within the five-year period. 

Revisions of Previous Estimates

The Company’s previous estimates of Proved Reserves decreased by 23,168 MBoe in 2019.  This decrease was primarily due to the removal of certain proved undeveloped legacy locations as they were no longer scheduled to be drilled within their initial five year window as a result of redirecting the Company’s development plan to focus on locations with better economics that were acquired in 2018.

The Company’s previous estimates of Proved Reserves related to the Eagle Ford Formation decreased by 10,716 MBoe in 2018. This decrease was primarily due to the removal of certain proved undeveloped reserves as they were not planned to be drilled within their initial five year window as a result of redirecting drilling efforts toward more locations that were part of the 2018 acquisition.

Extensions and Discoveries

The Company had extensions and discoveries of 39,649 MBoe during 2019, which were primarily proved undeveloped reserves, that were the result of the Company’s technical evaluation of wells drilled and completed in late 2018 and in 2019 on properties acquired in 2018.  The 2019 drilling program was focused primarily in Live Oak County, Texas, and, to a lesser extent, in McMullen and Atascosa Counties, Texas.  The Company’s total proved undeveloped locations as of December 31, 2019 were relatively consistent with that of prior year as a result of the removal of proved undeveloped legacy locations discussed in revisions of previous estimates.  The Company had extensions and discoveries of 11,904 MBoe during 2018, resulting from the 2018 drilling program primarily in Live Oak County, Texas, and, to a lesser extent, in McMullen and LaSalle Counties, Texas, targeting the Eagle Ford Formation. 

Purchase of Reserves In-Place

The Company did not purchase any reserves in place during 2019.  In 2018, the Company’s purchases of reserves in place were located in the Eagle Ford in South Texas. 

Sales of Reserves In-Place

During 2019, the Company’s sales of reserves were located in Dimmit County, Texas, which consisted of 2,078 Mboe of proved developed reserves, and 1,736 MBoe of proved undeveloped reserves.  

During 2018, the Company’s sales of reserves were located in Maverick County, Texas. 

Standardized Measure of Future Net Cash Flow

The Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport, nor should it be interpreted, to present the fair value of a company’s proved oil and natural gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value of money, and risks inherent in reserve estimates.

Under the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves which are based on SEC-defined pricing as discussed further below. Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. The Company calculatesthe projected income tax effect using the “year- by-year” method for purposes of the supplemental oil and gas disclosures.  Future net cash flow after income taxes is discounted using a 10% annual discount rate to arrive at the Standardized Measure.

The following summary sets forth our Standardized Measure (in thousands):

	December 31,
	2019		2018
Cash inflows	$	4,148,426	$	4,733,751
Production costs		(1,348,892)		(1,318,059)
Development costs		(1,231,467)		(1,143,083)
Income tax expense		(183,680)		(343,068)
Net cash flow		1,384,387		1,929,541
10% annual discount rate		(709,288)		(976,916)
Standardized measure of discounted future net cash flow	$	675,099	$	952,625

The following are the principal sources of change in the Standardized Measure (in thousands):

	Year ended December 31,
	2019		2018
Standardized Measure, beginning of year	$	952,625	$	366,747
Sales, net of production costs		(141,329)		(113,073)
Net change in sales prices, net of production costs		(422,811)		201,784
Extensions and discoveries, net of future production and development costs		258,433		206,179
Changes in future development costs		283,154		63,297
Previously estimated development costs incurred during the period		84,739		94,673
Revision of quantity estimates		(308,312)		(198,956)
Accretion of discount		110,985		38,124
Change in income taxes		79,728		(142,730)
Purchases of reserves in-place		—		525,547
Sales of reserves in-place		(47,059)		(220)
Change in production rates and other		(175,054)		(88,747)
Standardized Measure, end of year	$	675,099	$	952,625

Impact of Pricing

The estimates of cash flows and reserve quantities shown above are based upon the unweighted average first-day-of-the-month prices for the previous twelve months, inclusive of adjustments for quality and location. If future gas sales are covered by contracts at specified prices, the contract prices are used. Fluctuations in prices are due to supply and demand and are beyond our control.

The following average prices were used in determining the Standardized Measure:

	Year ended December 31,
	2019		2018
Oil (per Bbl)	$	56.05	$	66.34
Gas (per Mcf)	$	2.75	$	3.50
NGL (per Bbl)	$	16.35	$	28.15

XML

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentration of Credit Risk (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Concentration Risk [Line Items]
Long-term contract	$ 54,284
Percentage of working interest in wells	100.00%
Customer concentration risk | Oil, natural gas and NGL
Concentration Risk [Line Items]
Exposure to risk (percentage)		74.00%
Account receivable amount		$ 12,100
Customer concentration risk | Gathering, processing, transportation and marketing services
Concentration Risk [Line Items]
Long-term contract	$ 54,300
Accounts receivable | Customer concentration risk | Oil, natural gas and NGL
Concentration Risk [Line Items]
Exposure to risk (percentage)	73.00%
Account receivable amount	$ 13,200
Sales | Customer concentration risk | Purchaser A
Concentration Risk [Line Items]
Exposure to risk (percentage)	60.00%	34.00%
Sales | Customer concentration risk | Purchaser B
Concentration Risk [Line Items]
Exposure to risk (percentage)	21.00%	26.00%
Sales | Customer concentration risk | Purchaser C
Concentration Risk [Line Items]
Exposure to risk (percentage)		23.00%

XML

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Stock Based Compensation (Details)	12 Months Ended
	Dec. 31, 2019
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Period of share holder return	3 years

XML

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Impact of Pricing (Details)	12 Months Ended
	Dec. 31, 2019 $ / Mcf $ / bbl	Dec. 31, 2018 $ / Mcf $ / bbl
Oil
Reserve Quantities [Line Items]
Average prices	56.05	66.34
Gas
Reserve Quantities [Line Items]
Average prices | $ / Mcf	2.75	3.50
Natural gas liquid sales
Reserve Quantities [Line Items]
Average prices	16.35	28.15

XML

LONG-TERM DEBT - Narrative (Details) $ in Thousands		4 Months Ended	12 Months Ended
	Apr. 23, 2018 USD ($)	Apr. 30, 2019	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Jan. 31, 2020 USD ($)	Dec. 31, 2017 USD ($)
Line of Credit Facility [Line Items]
Current borrowing capacity	$ 87,500
Maximum borrowing capacity	250,000
Debt instrument, carrying amount			$ 365,000	$ 315,000		$ 192,000
Production prepayment	11,800
Deferred finance fee	$ 16,700		11,510	14,196
Available borrowing capacity			$ 38,600
Write-off of deferred financing fees				251
Total Proved Reserves, PV percentage			9.00%
Revolving Facility
Line of Credit Facility [Line Items]
Maximum borrowing capacity			$ 250,000
Debt instrument, carrying amount			$ 115,000	$ 65,000
Interest rate			4.75%	5.40%
Letters of credit outstanding			$ 16,400
Elected borrowing commitment			$ 190,000
Revolving Facility | Subsequent event
Line of Credit Facility [Line Items]
Maximum borrowing capacity					$ 500,000
Available borrowing capacity					58,600
Borrowing base					$ 210,000
Revolving Facility | Maximum
Line of Credit Facility [Line Items]
Leverage Ratio			3.5
Revolving Facility | Minimum
Line of Credit Facility [Line Items]
Current Ratio			1.0
Interest Coverage Ratio			1.5
Revolving Facility | LIBOR | Maximum
Line of Credit Facility [Line Items]
Debt instrument, variable rate		3.50%	3.25%
Revolving Facility | LIBOR | Minimum
Line of Credit Facility [Line Items]
Debt instrument, variable rate		2.50%	2.25%
Term Loan
Line of Credit Facility [Line Items]
Debt instrument, carrying amount			$ 250,000	$ 250,000
Interest rate			10.10%	10.81%
Term Loan | Minimum
Line of Credit Facility [Line Items]
Interest Coverage Ratio			1.5
Asset Coverage Ratio			1.50
Term Loan | LIBOR
Line of Credit Facility [Line Items]
Debt instrument, variable rate			8.00%
Term Loan | Base Rate | Minimum
Line of Credit Facility [Line Items]
Interest rate			9.00%

XML

LEASES - Summary of supplemental cash flow information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$ 5,271
Operating cash flows from finance leases	20
Investing cash flows from operating leases	6,308
Financing cash flows from finance leases	187	$ 11
Operating lease liability additions	17,358
Finance lease liability additions	$ 640

XML

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Costs Incurred (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Proved		$ 173,750
Unproved	$ 177	45,252
Exploration costs	335	2,789
Development costs	149,766	181,463
Development costs associated with non-producing wells in progress	7,100	12,900
Cost incurred relating to unproved properties held for sale	0	1,000
Development cost related to assets held for sale	$ 8,400	$ 5,300

XML

INCOME TAXES - Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
INCOME TAXES
Income tax benefit at the federal statutory rate	$ (9,263)	$ (1,885)
State income taxes - net of federal income tax benefits	10	290
Stock-based compensation	114	839
Nondeductible expenses	519	1,055
Change in valuation allowance	4,255	19,822
Foreign tax rates	(166)	(877)
Australian Tax Losses on U.S. Restructuring		(3,284)
Deemed interest payment due to U.S. restructuring		(4,350)
U.S. withholding tax net of foreign tax credit		2,301
Other	13	46
Total income tax expense (benefit)	$ (4,518)	$ 13,957

XML

LEASES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2019
Practical expedients	true
Easement arrangements	true
Use hindsight	true
Lease liability	$ 17,331
Lease right-of-use assets	17,331
Finance Lease, Liability	$ 734
Rent expense		$ 3,600
Option to extend the lease	True
Option to terminate the lease	True
ASU 2016-02 | Restatement adjustment
Lease liability			$ 11,500
Lease right-of-use assets			$ 11,400
Vehicles
Finance Lease, Liability		200
Office Equipment
Finance Lease, Liability		$ 100

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
CONSOLIDATED BALANCE SHEETS
Accumulated depreciation, other property and equipment	$ 3,419	$ 2,823
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, authorized shares	100,000,000	100,000,000
Common stock, shares issued	6,875,672	6,874,622
Common stock, shares outstanding	6,875,672	6,874,622

XML

ACQUISITIONS AND DISPOSITIONS - Assets and Liabilities (Details) $ in Thousands		12 Months Ended
	Apr. 23, 2018 USD ($) a item	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Oil and gas properties
Proved		$ 173,750
Unproved		43,642
Liabilities Assumed:
Trade and other payables		(80)
Asset retirement obligation		(1,522)
Net assets acquired		215,790
Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC
Business Acquisition [Line Items]
Area of wells acquired | a	21,900
Cash paid for consideration	$ 215,800
Adjustments to consideration	$ 5,800
Gross production wells | item	132
pro forma financial information
Revenue		174,700
Income (loss) before income taxes		(7,700)
Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC | General and administrative expenses
Liabilities Assumed:
Acquisition costs		13,700
Acquisition costs expensed		$ 12,400	$ 1,300

XML

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2019

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 1 – BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Operations

On November 26, 2019, a new Delaware corporation named Sundance Energy Inc. (the “Company”) acquired all of the issued and outstanding ordinary shares of Sundance Energy Australia Limited (“SEAL”), an Australian Company, pursuant to a Scheme of Arrangement under Australian law (the “Scheme”) which was approved by SEAL’s shareholders on November 8, 2019 and the Federal Court of Australia on November 14, 2019.  These events are collectively referred to as the “Redomiciliation”.  Prior to the Redomiciliation, the Company’s ordinary shares were listed on the Australian Securities Exchange (“ASX”) and Sundance Energy Inc. had no business or operations. Following the Redomiciliation, the business and the operations of Sundance Energy Inc. consist solely of the historical business and operations of SEAL and its subsidiaries.  

In the Redomiciliation, all outstanding SEAL ordinary shares on November 26, 2019, were cancelled and shares of the Company’s common stock, par value $0.001 per share, were issued.  Each of SEAL’s shareholders received one share of the Company’s common stock in exchange for 100 SEAL ordinary shares held.

The purpose of the Redomiciliation was to reorganize the operations of SEAL, a public company incorporated under the laws of the State of South Australia, into a structure whereby the ultimate parent company of the Sundance group of companies would be a Delaware corporation. In connection with the Redomiciliation, the ordinary shares of SEAL were delisted from the ASX, and the common stock of Sundance Energy Inc. began trading on the Nasdaq Global Market on November 26, 2019 under the ticker symbol “SNDE”, the same symbol under which SEAL’s American Depository Shares were traded on Nasdaq Global Market prior to the implementation of the Redomiciliation.  Immediately following the effectiveness of the Redomiciliation, SEAL distributed all of its assets to Sundance Energy Inc., and Sundance Energy Inc. assumed all of the liabilities of SEAL.

Sundance Energy Inc. is an independent oil and gas company engaged in the development, production and exploration of oil, natural gas and natural gas liquids (“NGLs”) primarily targeting the Eagle Ford basin in South Texas.

Basis of Preparation

Prior to the Redomiciliation, SEAL reported its consolidated financial statements in accordance with International Financial Reporting Standards (“IFRS”).  Following the Redomiciliation, the Company retroactively transitioned to accounting principles generally accepted in the United States of America (“GAAP”) and applied GAAP retrospectively for all prior periods presented.  The Company’s consolidated financial statements have been prepared in accordance with GAAP and Securities and Exchange Commission (“SEC”) rules and regulations, and include the accounts of the Company and its consolidated subsidiaries.  All intercompany balances and transactions have been eliminated in consolidation.

Going Concern

The accompanying consolidated financial statements are prepared in accordance with GAAP applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.

In March 2020, the prevailing market price for oil prices decreased from an average of approximately $60 per barrel for December 2019 to less than $20 per barrel.  As described in Note 7, the Company is required to meet certain financial and non-financial covenants as a condition to its credit facilities.  Under the Company’s second lien term loan (“Term Loan”), the Company is required to maintain an Asset Coverage Ratio of not less than 1.5 to 1.0, which is calculated as the value of its Total Proved Reserves (PV 9%)   based upon the forward month prices quoted on the NYMEX, adjusted for basis differentials or premiums and transportation costs and to reflect the Company’s commodity hedging agreements then in effect to Total Debt. The value of the Company’s oil and gas reserves, (including “Total Proved Reserves” as described in the Term Loan agreement) is highly sensitive to future commodity prices.  The Company regularly enters into commodity derivative contracts to protect the cash flows associated with the Company’s proved developed producing wells and to provide supplemental liquidity to mitigate decreases in revenue due to reductions in commodity prices.

Based on the Company’s historical experience, in periods of sustained low commodity prices, the prevailing market price for oil and gas services has also decreased, including the types of costs included in the Company’s lease operating expenses, drilling costs, completion costs and costs to equip its wells.  Subsequent to December 31, 2019, the Company renegotiated pricing with a number of its vendors and entered into contractual arrangements with drilling and completion service providers at reduced costs relative to the assumed costs in the Company’s year-end reserve report.  Additionally, the Company has changed its field operating procedures in response to the material drop in oil prices which further reduces its cost structure relative to that assumed in the Company’s year-end reserve report.  The Company continues to work to secure additional costs reductions.

Commodity hedging that the Company currently has in place, combined with cost reductions are expected to reduce the impact of recent commodity price declines.  However, given the recent decline and continued volatility of commodity prices, the Company cannot assert that it is probable that it will comply with the Asset Coverage Ratio and other covenants within the next 12 months following the date of this report.  A breach of any covenant in Company’s credit agreements will result in default under both the Company’s Term Loan and cross default on the Company’s revolving credit facility, after any applicable grace period, which could result in acceleration of the amounts outstanding under the credit facilities by the Company’s lenders.  

Additionally, the Company’s credit facilities contain the requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception.  The issuance of these consolidated financial statements with the accompanying audit opinion constitutes a default under the senior secured revolving credit facility (“Revolving Facility”) and Term Loan.  The Company obtained waivers from its Revolving Facility and Term Loan lenders, executed on May 8, 2020 and May 11, 2020, respectively, to waive the event of default arising from the inclusion of the going concern explanatory paragraph included in the audit report for the year ended December 31, 2019 and other related defaults.  These waivers were effective April 29, 2020, subject to the conditions set forth in the waivers.  As described in Note 15, in consideration for the waiver under our Revolving Facility, the Company agreed to certain limitations on its ability to effect draws under the revolving credit facility until such time as the second quarter 2020 borrowing base redetermination has been completed.  In addition, in consideration for waiver with respect to the Term Loan, the Company agreed to amend certain covenants in the Term Loan, as to be mutually agreed with the Term Loan lenders, within 15 days from the execution date.  The waiver under our Revolving Facility also provides for a right to require corresponding amendments of that facility manner, as requested by the administrative agent in its discretion, within 90 days from the execution date. Failure to enter into such amendments with respect to our Term Loan within 15 days (or a similar amendment with respect to our Revolving Facility on the date the Term Loan is amended) would constitute an event of default under the credit facilities, in which case the amounts outstanding under the credit facilities could be accelerated and become immediately due and payable.  While management believes that it will finalize such amendments within the required time frame, there can be no assurance that management’s efforts will result in any finalizing these amendments or the ultimate terms of any such amendments. 

Although the Company has obtained these waivers, there is no guarantee that its lenders will agree to waive events of default or potential events of default in the future.    In the event that some or all of the amounts outstanding under its credit facilities are accelerated and become immediately due and payable, the Company does not have sufficient liquidity to repay such outstanding amounts. These conditions and events raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. 

Management is currently pursuing and evaluating several plans to mitigate the conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern, which include the following:

· Renegotiating pricing with a number of its operating expenditure vendors and has realized lower drilling and completion costs on recent development relative to the costs incurred in 2019 and the assumed costs in the Company’s year-end reserve report.

· Negotiating with its lenders to obtain waivers for potential failures in covenants.

· Pursuing further changes to its cost structure in response to the material drop in oil prices. 

· Pursuing additional costs savings with its vendors and other internal costs, including a reduction in force, which occurred in early May 2020.

There can be no assurance that sufficient liquidity can be obtained to meet the outstanding obligations of the Company, if repayment of its credit facilities is accelerated. As a result, and given the recent declines and continued volatility in commodity prices, the Company has concluded that management’s plans do not alleviate substantial doubt about the Company’s ability to continue as a going concern.

The consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.  Items subject to such estimates and assumptions include (i) oil and natural gas reserves; (ii) impairment tests of long-lived assets; (iii) depreciation, depletion and amortization; (iv) asset retirement obligations; (v) assignment of fair value and allocation of purchase price in connection with business combinations; (vi) income taxes; (vii) accrued liabilities; (viii) valuation of derivative instruments; and (ix) accrued revenue and related receivables.  Although management believes these estimates are reasonable, actual results could differ from these estimates.  Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of lower commodity prices, may have a significant negative impact to the Company’s business, financial condition, results of operations and cash flows.

Cash and Cash Equivalents

Cash and cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less.

Accounts Receivable Trade and Other

The Company has letters of credit in place with certain of its purchasers, which the Company could draw upon in the event the purchaser defaults.  Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts.  For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.  The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability.  At December 31, 2019 and 2018, the Company had no allowance for doubtful accounts.  At December 31, 2019 and 2018 the accounts receivable trade and other included the following (in thousands):

	December 31,
	2019		2018
Oil, natural gas and NGL sales	$	18,211	$	16,408
Joint interest owners		260		584
Commodity hedge contract receivables and other		4,342		4,257
Receivable due from buyer (Dimmit County oil and gas properties)		4,207		—
Total accounts receivable trade and other	$	27,020	$	21,249

Concentration of Credit Risk

The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries.  The creditworthiness of customers and other counterparties is subject to continuing review.

As of December 31, 2019, the Company had a receivable from one purchaser, a large midstream company and production purchaser, of $13.2 million that accounted for 73% of total accounts receivable for oil, natural gas and NGL sales.  As of December 31, 2019, the Company has a long-term contract in place with this customer, under which the Company is subject to minimum revenue commitments for gathering, processing, transportation and marketing services totaling $54.3 million through 2022.

As of December 31, 2018, the Company had a receivable due from the same customer of $12.1 million that accounted for 74% of total accounts receivable for oil, natural gas and NGL sales.

The following tables present the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 2019 and 2018:

Year Ended December 31, 2019
Purchaser A	60%
Purchaser B	21%
Year Ended December 31, 2018
Purchaser A	34%
Purchaser B	26%
Purchaser C	23%

The Company owns nearly 100% of the working interest in the majority of the wells that it operates; therefore, joint interest billing receivables, and the related credit risk, is minimal.  Further, if payment is not made by a working interest partner, the Company can withhold future payments of revenue to that working interest partner.

Oil and Gas Properties

Proved.  The Company follows the successful efforts method of accounting for its oil and gas properties.  Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a unit-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively.  Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful.  For the years ended December 31, 2019 and 2018, the Company recorded depletion, depreciation and amortization expense related to proved oil and gas properties of $91.4 million and $62.1 million, respectively.

The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable.  The impairment test compares undiscounted future net cash flows of the assets to the assets’ net book value.  If the net book value exceeds future net cash flows, then the cost of the property is written down to fair value.  Fair value for oil and gas properties is generally determined based on discounted future net cash flows.  There was no impairment expense during the years ended December 31, 2019 or 2018.

Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income.  Gains or losses from the disposal of complete units of depreciable property are recognized in results of operations.

For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Interest is capitalized until the asset is ready for service.  

Unproved.  Unproved properties consist of costs to acquire undeveloped leases as well as purchases of unproved reserves.  Capitalized costs of unproved property are transferred to proved property when related proved reserves are determined and depleted on a unit-of-production basis.The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage.  There was no unproved property impairment expense during the years ended December 31, 2019 and 2018.

Exploratory.  Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage, are expensed as incurred.  Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs.  Amounts of seismic costs capitalized are based on only those blocks of data used in determining developmental well locations.  To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.

Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves.  If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense.  Costs incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (i) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.  If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed.

Other Property and Equipment

Other property and equipment consists of office furniture, computer equipment, software and vehicles, which are stated at cost and depreciated using the straight-line method over their estimated useful lives ranging from 3 to 20 years. Leasehold improvements are depreciated over the shorter of the lease term or the estimated useful life of the improvement. Costs that do not extend the useful lives of property and equipment are charged to expense as incurred.  Major replacements, renewals and betterments are capitalized.

Other Current Assets

Other current assets consist of oil and equipment inventory and prepaid expenses.  The Company records oil and equipment inventory at the lower of cost or net realizable value.  Prepaid expenses are recorded at cost.

Assets Held for Sale

Oil and gas properties expected to be sold or otherwise disposed of within one year are classified as assets held for sale and included as current assets in the consolidated balance sheets are separately presented in the accompanying consolidated balance sheets at the lower of carrying value or fair value less estimated costs to sell (“FVLCS”).   The Company continued to extract oil and gas from the assets while held for sale, although in accordance with accounting standards, it did not record DD&A for assets classified as held for sale.  

Debt Issuance Costs

Debt issuance costs related to the Company’s Term Loan are included as a deduction from the carrying amount of the credit facility in the consolidated balance sheets and are amortized to interest expense using the effective interest method over the term of the related debt.  Debt issuance costs related to the Revolving Facility are included in other long-term assets and are amortized to interest expense on a straight-line basis over the term of the facility.

Derivative Instruments

The Company enters into derivative contracts, primarily swaps, and costless collars, to manage its exposure to commodity price risk, and follows Financial Accounting Standards Board (“FASB”) ASC Topic 815, Derivatives and Hedging, to account for its derivative financial instruments.  The Company also has interest rate swaps contracts to mitigate its exposure to the floating interest rate charged on its long-term debt.  In addition, the Company historically entered into foreign exchange derivatives to protect cash flows generated during a common stock equity raise in 2018 from changes in currency fluctuations.  Prior to the Company’s redomiciliation, the majority of its common stock issuances were denominated in Australian dollars.  All derivative instruments, other than those that meet the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value.  Gains and losses from changes in the fair value of derivative instruments are recognized immediately in operations. The Company does not apply hedge accounting to any of its outstanding derivative instruments and, as a result, changes in derivative fair values are recognized as an unrealized gain or loss in operations.

Cash flows from derivatives used to manage commodity price risk and interest rate risk are classified in operating activities along with the cash flows of the underlying hedged transactions.  Cash flows from derivatives used to manage foreign currency risk are classified in financing activities.  The Company does not enter into derivative instruments for speculative or trading purposes.  Refer to the Note 10 and Note 11 for further information.

Asset Retirement and Environmental Obligations

Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition as specified by the lease or regulatory agencies.  The Company follows FASB ASC Topic 410, Asset Retirement and Environmental Obligations, to determine its asset retirement obligation amounts by calculating the present value of the estimated future cash outflows associated with its plug and abandonment obligations.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is spud or acquired), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount.  The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a unit-of-production basis over the proved developed reserves of the related asset.  Revisions typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells, and such revisions result in adjustments to the related capitalized asset and corresponding liability.

Revenue Recognition

The Company recognizes revenue from the sale of oil, natural gas and NGLs in the period that the performance obligations are satisfied.  The Company’s performance obligations are primarily comprised of the delivery of oil, natural gas or NGLs at a delivery point.  Each barrel of oil, MMBtu of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated.  Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer through delivery of oil, natural gas and NGLs, which differs depending on the contractual terms of each of the Company’s arrangements.

Transfer of control drives the presentation of gathering, processing, transportation, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations, and requires significant judgements. Fees and other deductions incurred prior to control transfer are recorded within the gathering, processing and transportation expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of oil, gas, and NGLs production revenue. The Company has three types of contracts under which oil, gas, and NGLs production revenue is generated, which are summarized below:

1) The Company sells oil production at or near the wellhead and receives an agreed-upon index price from the purchaser, net of basis, quality, and transportation differentials. Under this arrangement, control transfers at or near the wellhead.

2) The Company sells unprocessed natural gas to a midstream processor at the wellhead or inlet of the midstream processing facility. The midstream processor gathers and processes the raw natural gas stream and remits proceeds to the Company from the ultimate sale of the processed NGLs and residue natural gas to third parties. In such arrangements, the midstream processor obtains control of the product at the wellhead or inlet of the facility and is considered the customer. Proceeds received for unprocessed natural gas under these arrangements are reflected as natural gas or NGL revenue and are recorded net of transportation and processing fees incurred by the midstream processor after control has transferred.

3) The Company has certain processing arrangements that include the delivery of unprocessed natural gas to the inlet of a midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind. For the NGLs, control is deemed to have transferred after it has been separated from the residue gas.  The midstream processor remits payment to the Company based on the proceeds it generates from selling the NGLs to other third parties.  The Company recognizes the proceeds as NGL revenue.  For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. The Company recognizes proceeds from the downstream contracts as natural gas revenue.  Under these processing arrangements for both NGL and natural gas, the Company recognizes gathering, transportation, and processing fees incurred prior to control transfer as expense recorded within the gathering, processing and transportation expense line item on the accompanying consolidated statements of operations.

Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received within two months after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, metered sales volumes, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Variances between estimates and the actual amounts received are recorded in the month payment is received, but have not historically been material.  Estimated revenue due to the Company is recorded within accounts receivable trade and other on the accompanying consolidated balance sheets until payment is received. The accounts receivable balance from contracts with customers within the accompanying balance sheet as of December 31, 2019 and 2018 was $18.2 million and $16.4 million, respectively. 

Stock-Based Compensation

Equity - Settled Compensation

Prior to the effectiveness of the Redomiciliation, SEAL issued restricted share units (“RSUs”) pursuant to its Long Term Incentive Plan (the “Plan”) to motivate management and employees to make decisions benefiting long-term value creation, retain management and employees and reward the achievement of the Company’s long-term goals.  The RSUs are generally settled based on the achievement of certain goals established by the Compensation Committee and approved by the Board. There were three types of RSU awards:

1) Time based vesting: The fair value of time-based RSUs is determined based on the price of the underlying equity on the date of grant and the expense is recognized over the vesting period.

2) Total shareholder return (“TSR”) or absolute total share-holder return (“ATSR”):  Certain RSUs vest based on the achievement of metrics related to the a three‑year ATSR or TSR as compared to a peer group or a market index. A Monte Carlo simulation model to determine the fair value of such RSUs and the expense is recognized over the vesting period. The Monte Carlo model was used to determine based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The expected volatility used in the model is based on the historical volatility commensurate with the length of the performance period of the award. The risk-free rate used in the model is based on published interest rates relevant to the term of the RSU award. 

3) Performance targets: Certain RSUs vest based on the achievement of Adjusted EBITDAX per debt adjusted share or average daily production volume per debt adjusted share metrics during 2019 and 2020. At the end of each reporting period, the amount of expense recorded is adjusted based on the number of shares it ultimately expects to vest based on the comparison of internal forecasts to the performance conditions.    

The fair value of the equity to which employees become entitled is measured at grant date and recognized as an expense over the vesting period with a corresponding increase in equity.  The Company accounts for forfeitures of RSUs as they occur.  See Note 13 for further discussion of the RSUs.

Defined Contribution Plan

The Company has a defined contribution retirement plan for all employees.  The plan is funded by employee contributions and discretionary Company contributions.  The Company’s contributions for the years ended December 31, 2019 and 2018 were $0.6 million and $0.3 million, respectively.

Income Taxes

Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes.  Deferred income taxes are accounted for using the liability method.  Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s consolidated financial statements.  The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized.  The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense (benefit).

Earnings (Loss) Per Share

Basic earnings (loss) per common share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding during each period.  Diluted earnings per common share is calculated by dividing net income by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities.  Potentially dilutive securities for the diluted earnings per share calculations consist of outstanding restricted share units which have been issued to employees, all using the treasury stock method.  When a loss from continuing operations exists, all dilutive securities and potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. 

Industry Segment and Geographic Information

The Company’s strategic focus is the exploration, development and production of large, repeatable onshore resource plays in North America. All of the Company’s operations and assets are located in the Eagle Ford area of south Texas.  Management has determined, based upon the reports the Chief Operating Decision Maker (the Company’s Chief Executive Officer) reviews and uses to make strategic decisions, that the Company has one reportable segment being oil and natural gas development and production in North America.

Foreign Currency Transaction Gains and Losses

The U.S. dollar is the functional currency for the Company.  The Company’s Australian subsidiaries have an Australian dollar functional currency, and asset and liability accounts denominated in foreign currencies are remeasured to their U.S. dollar equivalent at the exchange rate in effect at the end of each reporting period. Foreign currency gains and losses arising from translation are reflected in accumulated other comprehensive (loss) in the consolidated balance sheets.

Business Combinations

A business combination is a transaction in which an acquirer obtains control of one or more businesses. The Company accounts for business combinations using the acquisition method of accounting, under which the cost of the acquisition is allocated to assets acquired and liabilities assumed based upon their respective fair values as of the acquisition date. Costs directly attributable to the business combination are expensed as incurred, except those directly and incrementally attributable to equity issuance.

Recently Issued and Adopted Accounting Standards

In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (“ASU 2016-02”). The FASB subsequently issued various ASUs which provided additional implementation guidance, and these ASUs collectively make up FASB ASC Topic 842 – Leases (“ASC 842”). The objective of ASC 842 is to increase transparency and comparability among organizations, by recognizing lease liabilities and right-of-use assets on the balance sheet at the date of initial application and disclosing key information about leasing arrangements. The Company adopted ASC 842 using the modified retrospective method effective January 1, 2019. Accordingly, the 2019 financial statements are not comparable with respect to leases in effect for all periods prior to January 1, 2019. Refer to Note 6 for further information on the Company’s implementation of this standard.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments, which provides a model, known as the current expected credit loss model (“CECL model”), to estimate the expected lifetime credit loss on financial assets, including trade and other receivables.  The Company adopted the ASU effective January 1, 2020, and it did not have a material impact on the Company’s consolidated financial statements as the Company does not have a history of material credit losses.    

XML

SUBSEQUENT EVENTS (Details) - Term Loan		12 Months Ended
	Apr. 29, 2020	Dec. 31, 2019
Subsequent event
Subsequent Event [Line Items]
Term for new agreement prior to event of default	15 days
LIBOR
Subsequent Event [Line Items]
Debt instrument, variable rate		8.00%

XML

FAIR VALUE MEASUREMENT - Non Recurring (Details) $ in Thousands	Dec. 31, 2018 USD ($)
FAIR VALUE MEASUREMENT
Assets held for sale	$ 23,471
Fair Value, Nonrecurring | Net Carrying Value
FAIR VALUE MEASUREMENT
Assets held for sale	23,471
Fair Value, Nonrecurring | Level 3 | Fair Value
FAIR VALUE MEASUREMENT
Assets held for sale	$ 23,471

XML

EARNINGS PER SHARE - Narrative (Details)	1 Months Ended	12 Months Ended
	Nov. 30, 2019	Dec. 31, 2019 shares	Dec. 31, 2018 shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Conversion ratio	0.01	0.01
Service - based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Diluted effect of Incremental shares related to restricted share units		320	786

XML

DERIVATIVE FINANCIAL INSTRUMENTS - Derivative Positions (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2020 MMBTU $ / MMBTU $ / bbl bbl	Dec. 31, 2019 MMBTU $ / MMBTU $ / bbl bbl
Propane | 2020
Derivative
Volumes (Bbl) | bbl		271,000
Weighted Average Price per Bbl, MMBtu		0.70
WTI - HOU | 2020
Derivative
Volumes (Bbl) | bbl		720,000
Weighted Average Price per Bbl, MMBtu		2.98
WTI - HOU | 2021
Derivative
Volumes (Bbl) | bbl		120,000
Weighted Average Price per Bbl, MMBtu		2.53
Swaps | WTI | 2020
Derivative
Volumes (Bbl) | bbl		1,074,000
Weighted Average Price per Bbl, MMBtu		57.17
Swaps | WTI | 2020 | Subsequent event
Derivative
Volumes (Bbl) | bbl	720,000
Weighted Average Price per Bbl, MMBtu	49.39
Swaps | WTI | 2021
Derivative
Volumes (Bbl) | bbl		216,000
Weighted Average Price per Bbl, MMBtu		54.84
Swaps | WTI | 2021 | Subsequent event
Derivative
Volumes (Bbl) | bbl	1,980,000
Weighted Average Price per Bbl, MMBtu	48.38
Swaps | HH | 2020
Derivative
Volumes (MMBtu) | MMBTU		1,890,000
Weighted Average Price per Bbl, MMBtu | $ / MMBTU		2.70
Swaps | HH | 2021
Derivative
Volumes (MMBtu) | MMBTU		1,050,000
Weighted Average Price per Bbl, MMBtu | $ / MMBTU		2.69
Swaps | HH | 2021 | Subsequent event
Derivative
Volumes (MMBtu) | MMBTU	600,000
Weighted Average Price per Bbl, MMBtu | $ / MMBTU	2.67
Swaps | HH | 2022
Derivative
Volumes (MMBtu) | MMBTU		720,000
Weighted Average Price per Bbl, MMBtu | $ / MMBTU		2.76
Swaps | HSC | 2020
Derivative
Volumes (MMBtu) | MMBTU		120,000
Weighted Average Price per Bbl, MMBtu | $ / MMBTU		2.53
Swaps | HSC | 2021
Derivative
Volumes (MMBtu) | MMBTU		240,000
Weighted Average Price per Bbl, MMBtu | $ / MMBTU		2.50
Swaps | HSC | 2022
Derivative
Volumes (MMBtu) | MMBTU		360,000
Weighted Average Price per Bbl, MMBtu | $ / MMBTU		2.54
Swaps | HSC | 2023
Derivative
Volumes (MMBtu) | MMBTU		240,000
Weighted Average Price per Bbl, MMBtu | $ / MMBTU		2.64
Collars [Member] | WTI | 2020
Derivative
Volumes (Bbl) | bbl		672,000
Weighted Average Price per Bbl, MMBtu - Floor		54.47
Weighted Average Price per Bbl, MMBtu - Ceiling		61.82
Collars [Member] | WTI | 2021
Derivative
Volumes (Bbl) | bbl		216,000
Weighted Average Price per Bbl, MMBtu - Floor		45.00
Weighted Average Price per Bbl, MMBtu - Ceiling		65.00
Collars [Member] | WTI | 2022
Derivative
Volumes (Bbl) | bbl		228,000
Weighted Average Price per Bbl, MMBtu - Floor		40.00
Weighted Average Price per Bbl, MMBtu - Ceiling		66.00
Collars [Member] | WTI | 2023
Derivative
Volumes (Bbl) | bbl		160,000
Weighted Average Price per Bbl, MMBtu - Floor		40.00
Weighted Average Price per Bbl, MMBtu - Ceiling		63.10
Collars [Member] | HH | 2020
Derivative
Volumes (MMBtu) | MMBTU		120,000
Weighted Average Price per Bbl, MMBtu - Floor | $ / MMBTU		2.50
Weighted Average Price per Bbl, MMBtu - Ceiling | $ / MMBTU		2.95
Collars [Member] | HSC | 2020
Derivative
Volumes (MMBtu) | MMBTU		96,000
Weighted Average Price per Bbl, MMBtu - Floor | $ / MMBTU		2.60
Weighted Average Price per Bbl, MMBtu - Ceiling | $ / MMBTU		2.91
Three-Way Collars | WTI | 2020
Derivative
Volumes (Bbl) | bbl		300,000
Weighted Average Price per Bbl, MMBtu - Ceiling		59.60
Three-Way Collars | WTI | 2021
Derivative
Volumes (Bbl) | bbl		300,000
Weighted Average Price per Bbl, MMBtu - Ceiling		57.50
Three-Way Collars | WTI | 2022
Derivative
Volumes (Bbl) | bbl		300,000
Weighted Average Price per Bbl, MMBtu - Ceiling		56.90
Three-Way Collars | WTI | Purchased | 2020
Derivative
Weighted Average Price per Bbl, MMBtu - Floor		50.00
Three-Way Collars | WTI | Purchased | 2021
Derivative
Weighted Average Price per Bbl, MMBtu - Floor		50.00
Three-Way Collars | WTI | Purchased | 2022
Derivative
Weighted Average Price per Bbl, MMBtu - Floor		50.00
Three-Way Collars | WTI | Sold | 2020
Derivative
Weighted Average Price per Bbl, MMBtu - Floor		35.00
Three-Way Collars | WTI | Sold | 2021
Derivative
Weighted Average Price per Bbl, MMBtu - Floor		35.00
Three-Way Collars | WTI | Sold | 2022
Derivative
Weighted Average Price per Bbl, MMBtu - Floor		35.00

XML

DERIVATIVE FINANCIAL INSTRUMENTS - Gain (Loss) Recognized (Details) - Not designated as ASC 815 Hedges - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	$ (24,812)	$ 44,619
Foreign currency | Gain on foreign currency derivative financial instruments
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income		6,838
Derivative commodity contracts | Gain (loss) on commodity derivative financial instruments
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	(20,542)	40,216
Derivative interest rate swaps | Interest expense
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	$ (4,270)	$ (2,435)

XML

EQUITY - Restricted Share Units (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Recognized stock based compensation expense		$ 504	$ 515
Forecast
Weighted Average Fair Value at Grant Date
Vested RSUs that will be issued	375
Restricted Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded		38,373	71,175
Number of RSUs
Outstanding at beginning (in shares)	84,929	91,339	33,804
Granted (in shares)		38,373	71,175
Vested (in shares)		(1,425)	(6,916)
Forfeited (in shares)		(43,358)	(6,724)
Outstanding at ending (in shares)		84,929	91,339
Weighted Average Fair Value at Grant Date
Outstanding at beginning (per share)	$ 22.97	$ 34.37	$ 166.87
Granted (per share)		20.31	18.80
Vested (per share)		61.56	361.03
Forfeited (per share)		51.20	198.37
Outstanding at ending (per share)		$ 22.97	$ 34.37
Total RSUs outstanding		84,929	91,339
Restricted Share Units | March 15, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded			4,428
Restricted Share Units | May 27, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded			4,342
Restricted Share Units | June 29, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded			497
Restricted Share Units | February 17, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded		3,411	4,572
Restricted Share Units | May 25, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded		3,724	3,724
Restricted Share Units | October 23, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded		745	745
Weighted Average Fair Value at Grant Date
Vesting period (in years)			3 years
Restricted Share Units | October 23, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded		375	750
Restricted Share Units | December 29, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded		497	1,106
Restricted Share Units | December 26, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded		30,414	35,587
Weighted Average Fair Value at Grant Date
Vesting period (in years)			3 years
Restricted Share Units | December 26, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded		15,207	35,588
Restricted Share Units | May 5, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded		1,775
Restricted Share Units | May 5, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded		5,325
Restricted Share Units | May 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded		15,637
Restricted Share Units | May 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units awarded		7,819

XML

ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Dec. 31, 2019

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

NOTE 8 — ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration in accordance with applicable lease terms, local, state and federal laws. The following table provides a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2019 and 2018 (in thousands):

	December 31,
	2019		2018
Balance, beginning of year	$	3,489	$	1,549
Additional liability incurred		145		195
Obligations settled		(85)		(29)
Obligations on assets acquired		—		1,522
Obligations on assets sold		(232)		—
Accretion expense		336		252
Balance, end of year	$	3,653	$	3,489
Liabilities related to assets held for sale	$	—	$	193
Long-term		3,653		3,296
	$	3,653	$	3,489

XML

ASSETS HELD FOR SALE

12 Months Ended

Dec. 31, 2019

ASSETS HELD FOR SALE.

ASSETS HELD FOR SALE

NOTE 4 — ASSETS HELD FOR SALE

The consolidated balance sheet includes assets and liabilities related to assets held for sale, comprised of the following as of December 31, 2018 (in thousands):

Assets held for sale:	December 31, 2018
Oil and gas properties - Dimmit County, Texas	$	23,471
Liabilities related to assets held for sale:
Asset retirement obligations		(193)
Net assets held for sale	$	23,278

The Dimmit County assets were divested in October 2019.  See Note 3.  As of December 31, 2019, the Company’s balance sheet did not include assets or liabilities related to assets held for sale.

Impairment of Assets Held for Sale

For the years ended December 31, 2019 and 2018, the Company recorded impairment expense of $10.0 million and $43.0 million, respectively, related to assets held for sale as discussed in Note 11. 

XML

EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2019

EARNINGS PER SHARE

EARNINGS PER SHARE

NOTE 12 — EARNINGS PER SHARE

The reconciliations between basic and diluted earnings (loss) per share are as follows (in thousands, except per share data):

	Year Ended December 31,
	2019		2018
Net loss	$	(39,590)	$	(22,933)
Weighted average shares (1):
Weighted average common shares outstanding, basic		6,874,170		5,236,524
Diluted effect of incremental shares related to restricted share units (2)		—		—
Weighted average common shares outstanding, diluted		6,874,170		5,236,524
Net loss per share:
Basic and diluted	$	(5.76)	$	(4.38)

(1) All share numbers have been retroactively adjusted for the 2019 and 2018 periods to reflect the Company’s one for 100 share consolidation in November 2019, as described in Note 13. 

(2) For the year ended December 31, 2019, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes anti-dilutive shares of 320 shares of service-based awards.  For the year ended December 31, 2018, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes anti-dilutive shares of 786 shares of service-based awards.    

XML

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2019

INCOME TAXES

Schedule of components of the provision for income taxes

	Year Ended December 31,
	2019		2018
Current income tax expense - Federal	$	—	$	2,301
Deferred income tax expense (benefit)
Federal		(8,281)		(5,555)
State		11		318
Foreign		(503)		(2,929)
Total deferred income tax expense (benefit)		(8,773)		(8,166)
Valuation Allowance
Income tax provision (benefit)		4,255		19,822
Total income tax expense (benefit)	$	(4,518)	$	13,957

Schedule of reconciliations of the income tax (expense) benefit

	Year Ended December 31,
		2019		2018
Income tax benefit at the federal statutory rate	$	(9,263)	$	(1,885)
State income taxes - net of federal income tax benefits		10		290
Stock-based compensation		114		839
Nondeductible expenses		519		1,055
Change in valuation allowance		4,255		19,822
Foreign tax rates		(166)		(877)
Australian tax losses on U.S. Restructuring		—		(3,284)
Deemed interest payment due to U.S. restructuring		—		(4,350)
U.S. withholding tax net of foreign tax credit		—		2,301
Other		13		46
Total income tax expense (benefit)	$	(4,518)	$	13,957

Schedule of components of net deferred taxes

	December 31,
		2019		2018
Deferred tax assets:
Net operating loss carryforward	$	76,624	$	70,560
Business interest carryforward		10,474		7,054
Stock-based compensation		93		102
Statutory depletion carryforward		2,927		2,977
Unrealized (gain) loss on commodity derivative		1,147		(6,453)
Lease obligations		3,735		—
Property, plant and equipment		82		(122)
Other assets		524		1,688
Total deferred tax assets		95,606		75,806
Valuation allowance		(64,898)		(60,643)
Deferred tax assets, net		30,708		15,163
Deferred tax liabilities:
Basis of oil and gas properties		(33,950)		(26,819)
Lease assets		(3,896)		—
Total deferred tax liabilities		(37,846)		(26,819)
Deferred tax liabilities, net	$	(7,138)	$	(11,656)

XML

EQUITY (Tables)

12 Months Ended

Dec. 31, 2019

EQUITY

Schedule of restricted share units

		Weighted Average
		Fair Value at
	Number of RSUs	Grant Date
Outstanding at December 31, 2017	33,804	$	166.87
Granted	71,175	$	18.80
Vested	(6,916)	$	361.03
Forfeited	(6,724)	$	198.37
Outstanding at December 31, 2018	91,339	$	34.37
Granted	38,373	$	20.31
Vested (1)	(1,425)	$	61.56
Forfeited	(43,358)	$	51.20
Outstanding at December 31, 2019	84,929	$	22.97

⁽¹⁾ Includes 375 RSUs that have vested, but will be settled in 2020.

Schedule of RSUs outstanding

	Number of RSUs
Grant Date	2019	2018
March 15, 2016 (1)	—	4,428
May 27, 2016 (1)	—	4,342
June 29, 2016 (1)	—	497
February 17, 2017 (1)(2)	3,411	4,572
May 25, 2017 (1)(2)	3,724	3,724
October 23, 2017 (1)	745	745
October 23, 2017	375	750
December 29, 2017	497	1,106
December 26, 2018 (3)	30,414	35,587
December 26, 2018 (4)	15,207	35,588
May 5, 2019	1,775	—
May 5, 2019 (1)	5,325	—
May 31, 2019 (3)	15,637	—
May 31, 2019 (4)	7,819	—
Total RSUs outstanding	84,929	91,339

⁽¹⁾ RSUs vest based on three‑year absolute total shareholder return (“ATSR”).

⁽²⁾ ATSR RSUs were evaluated for vesting subsequent to December 31, 2019.  The vesting conditions were not met and the outstanding awards will be forfeited in 2020.

⁽³⁾ RSUs vest based on three-year total shareholder return (“TSR”) as compared to the XOP index.

⁽⁴⁾ Company performance-based RSUs vest based on 2019 and 2020 EBITDA per debt adjusted share and production per debt adjusted share.

Schedule of restricted share awards vesting conditions

The following tables summarize the RSUs issued and their related grant date, fair value and vesting conditions. RSUs awarded during the year ended December 31, 2019:

		Fair Value at
Grant Date	Number of RSUs	Grant Date		Vesting Conditions
May 5, 2019	1,775	$	29.49	Vests on 3rd anniversary of award
May 5, 2019	5,325	$	16.35	0 % - 200% based on 3 year TSR as compared to the XOP index.
May 31, 2019	15,637	$	16.13	0 % - 200% based on 3 year TSR as compared to the XOP index.
May 31, 2019	3,909	$	24.92	0 % - 200% based on 2019 EBITDA per Debt Adjusted Share
May 31, 2019	3,909	$	24.92	0 % - 200% based on 2020 EBITDA per Debt Adjusted Share
May 31, 2019	3,909	$	24.92	0 % - 200% based on 2019 Production per Debt Adjusted Share
May 31, 2019	3,909	$	24.92	0 % - 200% based on 2020 Production per Debt Adjusted Share
	38,373

The following tables summarize the RSUs issued and their related grant date, fair value and vesting conditions. RSUs awarded during the year ended December 31, 2018:

		Fair Value at
Grant Date	Number of RSUs	Grant Date		Vesting Conditions
December 26, 2018	35,587	$	16.44	0 % - 200% based on 3 year TSR as compared to the XOP index
December 26, 2018	8,897	$	21.16	0 % - 200% based on 2019 EBITDA per Debt Adjusted Share
December 26, 2018	8,897	$	21.16	0 % - 200% based on 2020 EBITDA per Debt Adjusted Share
December 26, 2018	8,897	$	21.16	0 % - 200% based on 2019 Production per Debt Adjusted Share
December 26, 2018	8,897	$	21.16	0 % - 200% based on 2020 Production per Debt Adjusted Share
	71,175