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, 2020

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-16071

ABRAXAS PETROLEUM CORPORATION

(Exact name of Registrant as specified in its charter)

Nevada	74-2584033
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification Number)

18803 Meisner Drive

San Antonio, TX 78258

(Address of principal executive offices)

(210) 490-4788

Registrant’s telephone number, including area code

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

Title of each class:	Trading Symbol	Name of each exchange on which registered:
Common Stock, par value $.01 per share	AXAS	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 Section 15(d) of the Exchange 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 if 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   Yes ☐ No ☒   

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

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 is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐ No ☒

As of June 30, 2020, the last day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the common stock held by non-affiliates of the registrant was $31,865,614 based on the closing sale price as reported on The NASDAQ Stock Market.

As of  April 30, 2021, there were 8,421,910 shares of common stock outstanding.

Documents Incorporated by Reference:

Document Parts Into Which Incorporated

ABRAXAS PETROLEUM CORPORATION

FORM 10-K

TABLE OF CONTENTS

		Page
Part  I
Item 1.	Business	5
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	30
Item 2.	Properties	30
Item 3.	Legal Proceedings	36
Item 4.	Mine Safety Disclosures	36
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	37
Item 6.	Selected Financial Data	37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 7A.	Quantitative and Qualitative Disclosure about Market Risk	49
Item 8.	Financial Statements and Supplementary Data	50
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	50
Item 9A.	Controls and Procedures	50
Item 9B.	Other Information	50
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	51
Item 11.	Executive Compensation	51
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	51
Item 13.	Certain Relationships and Related Transactions, and Director Independence	51
Item 14.	Principal Accountant Fees and Services	51
Part IV
Item 15.	Exhibits and Financial Statement Schedules	62
Item 16.	Form 10-K Summary	63

We make forward-looking statements throughout this report.  Whenever you read a statement that is not simply a statement of historical fact (such as statements including words like “believe,” “expect,” “anticipate,” “intend,” “will,” “plan,” “seek,” “may,” “estimate,” “could,” “potentially” or similar expressions), you must remember that these are forward-looking statements, and that our expectations may not be correct, even though we believe they are reasonable.  The forward-looking information contained in this report is generally located in the material set forth under the headings “Business,” “Properties,” “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” but may be found in other locations as well.  These forward-looking statements generally relate to our plans and objectives for future operations and are based upon our management’s reasonable estimates of future results or trends.  The factors that may affect our expectations regarding our operations include, among others, the following:

• the prices we receive for our production and the effectiveness of our hedging activities;

• the availability of capital including under our credit facilities;

• our success in development, exploitation and exploration activities;

• declines in our production of oil and gas;

• our indebtedness and the significant amount of cash required to service our indebtedness,

• the proximity, capacity, cost and availability of pipelines and other transportation facilities,

• limits on our growth and our ability to finance our operations, fund our capital needs and respond to changing conditions imposed by our credit facilities and restrictive debt covenants;

• our ability to make planned capital expenditures;

• ceiling test write-downs resulting, and that could result in the future, from lower oil and gas prices;

• global or national health concerns, including the outbreak of pandemic or contagious disease, such as the coronavirus (COVID-19);

• political and economic conditions in oil producing countries, especially those in the Middle East;

• price and availability of alternative fuels;

• our ability to procure services and equipment for our drilling and completion activities;

• our acquisition and divestiture activities;

• weather conditions and events; and

• other factors discussed elsewhere in this report.

Initial production, or IP, rates, for both our wells and for those wells that are located near our properties, are limited data points in each well’s productive history. These rates are sometimes actual rates and sometimes extrapolated or normalized rates. As such, the rates for a particular well may change as additional data becomes available. Peak production rates are not necessarily indicative or predictive of future production rates, expected ultimate recovery, or EUR, or economic rates of return from such wells and should not be relied upon for such purposes. Equally, the way we calculate and report peak IP rates and the methodologies employed by others may not be consistent, and thus the values reported may not be directly and meaningfully comparable. Lateral lengths described are indicative only. Actual completed lateral lengths depend on various considerations such as lease-line offsets. Abraxas standard length laterals, sometimes referred to as 5,000 foot laterals, are laterals with completed length generally between 4,000 feet and 5,500 feet. Mid-length laterals, sometimes referred to as 7,500 foot laterals, are laterals with completed length generally between 6,500 feet and 8,000 feet. Long laterals, sometimes referred to as 10,000 foot laterals, are laterals with completed length generally longer than 8,000 feet.

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GLOSSARY OF TERMS

Unless otherwise indicated in this report, gas volumes are stated at the legal pressure base of the state or area in which the reserves are located at 60 degrees Fahrenheit.  Oil and gas equivalents are determined using the ratio of six Mcf of gas to one barrel of oil.

The following definitions shall apply to the technical terms used in this report.

Terms used to describe quantities of oil and gas:

“Bbl” – barrel or barrels.

“Bcf” – billion cubic feet of gas.

“Bcfe” – billion cubic feet of gas equivalent.

“Boe” – barrels of oil equivalent.

“Boepd" - barrels of oil equivalents per day.

“MBbl” – thousand barrels.

“MBoe” – thousand barrels of oil equivalent.

“Mcf” – thousand cubic feet of gas.

“Mcfe” – thousand cubic feet of gas equivalent.

“MMBbl” – million barrels.

“MMBoe” – million barrels of oil equivalent.

“MMBtu” – million British Thermal Units of gas.

“MMcf” – million cubic feet of gas.

“MMcfe” – million cubic feet of gas equivalent.

“NGL” – natural gas liquids measured in barrels.

 Terms used to describe our interests in wells and acreage:

“Developed acreage” means acreage which consists of leased acres spaced or assignable to productive wells.

“Development well” is a well drilled within the proved area of an oil or gas reservoir to the depth or stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting reserves.

“Dry hole” is an exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion.

“Exploratory well” is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be producing in another reservoir, or to extend a known reservoir.

“Gross acres” are the number of acres in which we own a working interest.

“Gross well” is a well in which we own an interest.

“Net acres” are the sum of fractional ownership working interests in gross acres (e.g., a 50% working interest in a lease covering 320 gross acres is equivalent to 160 net acres).

“Net well” is the sum of fractional ownership working interests in gross wells.

“Productive well” is an exploratory or a development well that is not a dry hole.

“Undeveloped acreage” means those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.

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Terms used to assign a present value to or to classify our reserves:

“Developed oil and gas reserves*” 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.

“Proved developed non-producing reserves*”  are those quantities of oil and gas reserves that are developed behind pipe in an existing well bore, from a shut-in well bore or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

“Proved developed reserves*” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved oil and gas reserves*” Reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

“Proved undeveloped reserves” or “PUDs*”  Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells, in each case where a relatively major expenditure is required.

“PV-10” means estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation, calculated in accordance with guidelines promulgated by the Securities and Exchange Commission (“SEC”). PV-10 is considered a non-GAAP financial measure under SEC regulations 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. We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and gas properties and that PV-10 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, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes.

“Standardized Measure” means estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price or cost escalation or de-escalation, calculated in accordance with Accounting Standards Codification (“ASC”) 932, “Disclosures About Oil and Gas Producing Activities.”

“Undeveloped oil and gas reserves*"” 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.

* This definition is an abbreviated version of the complete definition set forth in Rule 4-10(a) of Regulation S-X. For the complete definition, see: http://www.ecfr.gov/cgi-bin/retrieveECFR?gp=1&SID=7aa25d3cede06103c0ecec861362497d&ty=HTML&h=L&n=pt17.3.210&r=PART#se17.3.210_14_610

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Part I

Information contained in this report represents the consolidated operations of Abraxas Petroleum Corporation. The terms “Abraxas,”  “we,” “us,” “our,” or the “Company,” refer to Abraxas Petroleum Corporation, together with its consolidated subsidiaries including Raven Drilling, LLC  which is a wholly owned subsidiary that owns a drilling rig. Unless otherwise noted, all disclosures are for Continuing Operations.

Item 1. Business

General

We are an independent energy company primarily engaged in the acquisition, exploration, development and production of oil and gas.  At December 31, 2020, our estimated net proved reserves were 16.8 MMBoe, of which 100% were classified as proved developed, 57% were oil and 97% of which (on a Boe basis) were operated by us.  Our daily net production for the year ended December 31, 2020 was 4,922 Boepd, of which 63% was oil. Abraxas Petroleum Corporation was incorporated in Nevada in 1990. Our address is 18803 Meisner Drive, San Antonio, Texas 78258 and our phone number is (210) 490-4788.

COVID-19 Overview

In the first quarter of 2020, a new strain of coronavirus (“COVID-19”) emerged, creating a global health emergency that has been classified by the World Health Organization as a pandemic. As a result of the COVID-19 pandemic, consumer demand for both oil and gas has decreased as a direct result of travel restrictions placed by governments in an effort to curtail the spread of COVID-19. In addition, in March 2020, members of Organization of Petroleum Exporting Countries ("OPEC") failed to agree on production levels, which caused an increased supply of oil and gas and led to a substantial decrease in oil prices and an increasingly volatile market. OPEC agreed to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand. As a result of this decrease in demand and increase in supply, the price of oil and gas has decreased, which has affected our liquidity. On one hand, the Company’s commodity hedges protected its cash flows in 2020 from such price decline but, on the other hand, if oil or natural gas prices remain depressed or decline the Company will be required to record oil and gas property write-downs.

In early March 2020, global oil and natural gas prices declined sharply, have since been volatile, rising in recent months, but may decline again. The Company expects ongoing oil and gas price volatility over the short term. The full impact of COVID-19 and the decrease in oil prices continues to evolve as of the date of this report. As such, it is uncertain as to the full magnitude that will have on the Company. Management is actively monitoring the global situation and the impact on the Company’s future operations, financial position and liquidity in fiscal year 2021. In response to the price volatility, the Company has taken action to reduce general and administrative costs, as well as  shutting in production in mid-March 2020, but subsequently started restoring production in mid-June, a majority of such wells were back on production in early September 2020. We have also suspended our capital expenditures indefinitely. 

Going Concern 

As discussed under Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, our present level of indebtedness and the recent commodity price environment present challenges to our ability to comply with certain covenants in our credit facilities and under applicable auditing standards the independent accountants' opinion on our  financial statements for the year ended December 31, 2020 contains an explanatory paragraph regarding the Company's ability to continue as a "going concern".  At December 31, 2020, we had a total of $95.0  million outstanding under our First Lien Credit Facility, $112.7 million under our Second Lien Credit facility, and total indebtedness of  $220.5 million, including $10.0 million exit fee. As of April 30, 2021, we had a total of $89.5 million outstanding under our First Lien Credit Facility,  $127.2  million under our Second Lien Credit Facility, including a $10.0 million exit fee, and total indebtedness of $219.4 million. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements.

Specifically, with regard to our credit agreements, we did not satisfy the first lien debt to consolidated EBITDAX ratio covenant under our First Lien Credit Facility as of the December 31, 2020 measurement date and such failure represented an event of default under our First Lien Credit Facility. In addition,  we do not anticipate that we will  maintain compliance with the Second Lien Credit Facility total leverage ratio covenant or the minimum asset coverage ratio (as defined in Note 4), both of which will be  first tested as of September 30, 2021 over the next twelve months and, accordingly, the audit report prepared by our auditors with respect to the financial statements in this Form 10-K includes an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern” as a result of events of default under our credit facilities. The inability to maintain compliance with certain covenants of our Second Lien Credit Facility would represent an additional default under our First Lien Credit Facility as of the end of any such future fiscal quarters. The consolidated financial statements do not include any adjustments that might result from the outcome of the "going concern" uncertainty.

We are evaluating the available financial alternatives and are in discussion with our lenders seeking additional waivers or amendments to the covenants or other provisions of our credit facilities to address any current and future default relating to the covenants in question. The existing defaults at March 31, 2021 are subject to forbearance agreements with our lenders that currently expire on May 6, 2021. No assurance can be provided that the forbearance agreements will be further extended. If, upon a future default, the Company is unable reach an agreement with its lenders or find acceptable alternative financing, the lenders under the Company's First Lien Credit Facility may choose to accelerate repayment. If the Company's lenders accelerate the payment of amounts outstanding under its credit facilities, the Company does not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so. The Company could attempt to obtain additional sources of capital from asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination thereof. However, the Company cannot provide any assurances that it will be successful in obtaining capital from such transactions on acceptable terms, or at all, 

Under applicable accounting principles these circumstances are deemed to create substantial doubt regarding the Company's ability to continue as a "going concern". The consolidated financial statements have been prepared on a "going concern" basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business for the twelve-month period following the date of issuance of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amount, or the amount and classification of liabilities that may result should the Company be unable to continue as a "going concern".

In April 2021, we received notice that certain of our hedging agreements were being terminated as a result of events of default under the First Lien Credit Facility, and we voluntarily terminated most  of our other hedging arrangements. As a result of the settlement of the terminated hedges, we have outstanding obligations of  $9.9 million.  The settlement values of the terminated hedges were determined at various dates between April 15 and April 30, 2021. These obligations will be added to the balance of the First Lien Credit Facility and accrue interest  at the default interest rate, currently 6.7%, until repaid. Remaining hedging agreements may also be terminated as a result of such events of default. The settlement of terminated hedging agreements may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. See Note 14 “Subsequent Events” for current information regarding non-compliance with certain covenants.

Our oil and gas assets are located in two operating regions, the Permian/Delaware Basin, and the Rocky Mountain as of December 31, 2020.  The following table sets forth certain information related to our properties as of and for the year ended December 31, 2020:

								Estimated Net Proved Reserves at December 31, 2020 (3)					Net Production for the Year Ended December 31, 2020
	Gross Producing Wells		Average Working Interest			Total Net Acres		(Mboe)		% Oil			(Mboe)		% Oil
Permian/Delaware Basin (1)		103		79.38	%		25,051		7,383		58	%		779		77	%
Rocky Mountain (2)		468		15.65	%		16,850		9,395		56	%		1,022		52	%
Total United States		571		27.50	%		41,901		16,778		62	%		1,801		63	%

(1 ) Our properties in the Permian/Delaware Basin region are primarily located in Ward and Winkler Counties, Texas and produce oil and gas primarily from the Bone Spring and Wolfcamp formations. 

(2)  Our properties in the Rocky Mountain region are primarily located in the Williston Basin of North Dakota and Montana.  In this region, our wells produce oil and gas from various reservoirs, primarily the Bakken, Three Forks and Red River formations. 

(3)  Net proved reserves excludes proved undeveloped reserves due to the Company's inability to fund the drilling and completion activities within the next five years.

Strategy

Our business strategy is to focus our capital and resources on our core operated basins, improve financial flexibility and profitably grow production and reserves.  Key elements of our business strategy include:

Focus our capital and resources on our core operated basins. Our core basins consist of the Permian/Delaware Basin (Bone Spring and Wolfcamp) and Williston Basin (Bakken and Three Forks). Given the disparity which has existed during the past several years and which continues currently between oil and gas prices, the economics of drilling oil wells is far superior to drilling gas wells.  Due to declines in oil prices, during the first half of 2020, we suspended our planned capital expenditures for 2020. This suspension of our  capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources including under our credit facilities, the results of our exploitation efforts, our financial results and our ability to obtain permits for drilling locations. Due to the capital spending constraints imposed by our credit facilities, we have also not adopted a 2021 drilling budget but do plan to complete the six previously drilled uncompleted wells in the Bakken. As part of our efforts to focus our property portfolio, we also seek to sell assets we have deemed non-core. These include assets with a low working interest that are non-operated and/or that fall outside of our two core basins. Any proceeds from these asset sales have been and will continue to be used to reduce our indebtedness and/or be redeployed into our core operating basins. During 2019 we monetized our remaining Eagle Ford assets in South Texas as well as our non-operated properties in the Bakken.

Financial flexibility. Our primary source of capital is cash flows from operations. As of December 31, 2020, we had $95.0  million outstanding on our first lien credit facility (the "First Lien Credit Facility") with no availability, and $112.7 million under our second lien credit facility (the "Second Lien Credit Facility"), and we generated approximately $16.0 million of cash flows from operations for the year ended December 31, 2020. Additionally, any excess cash, as defined in the First Lien Credit Facility, must be used to reduce the balance and simultaneously reduce the borrowing base to the new outstanding balance.

We have also sold producing properties from time to time in order to provide us with financial flexibility. During 2019 we sold our non-operated Bakken properties and our remaining South Texas Eagle Ford properties, proceeds from these sales were approximately $23.4 million.  In January 2019, we announced that we had engaged Petrie Partners to assist us in identifying and assessing our options for our Bakken properties. In October 2019 we announced that we had broadened the engagement of Petrie Partners to include a more thorough review of our business and strategic plans, competitive positioning and potential alternative transactions that might further enhance shareholder value. Petrie’s expanded mandate to assess our options is a broad one, which might include sales of assets, merger or acquisition transactions, additional financing alternatives or other strategic transactions. There have not been any significant developments to date.

We seek to reduce the volatility of our cash flows from operations by hedging a portion of our production. As of December 31, 2020, we had NYMEX-based fixed price commodity swap arrangements, on approximately 88% of the oil production from our estimated net proved developed producing reserves (as of December 31, 2020) through December 31, 2021, 96% for 2022, 72% for 2023 and 88% for 2024. Substantially all of our hedging arrangements were terminated subsequent to December 31, 2020.

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Profitably grow production and reserves. We have a substantial low-decline legacy production base as evidenced by our approximate 21-year average reserve life as of year-end 2020. Our capital is currently being deployed largely into unconventional oil assets with relatively predictable production profiles, yet steep initial decline rates. Therefore, the economics of these oil wells are highly dependent on both near term commodity prices and strong operational cost control. Cost savings achieved through efficiencies of using our own rig in the Williston Basin, and heightened focus on cost control in all of our operated positions both contribute to our historical success in adding low cost barrels to our production base.

2021 Budget and Drilling Activities

Due to the capital spending constraints imposed by our credit facilities, we have not adopted a drilling budget for 2021. As discussed under Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, our present level of indebtedness and the recent commodity price environment present challenges to our ability to comply with certain covenants in our credit facilities and under applicable auditing standards the independent accountants' opinion on our  financial statements for the year ended December 31, 2020 contains an explanatory paragraph regarding the Company's ability to continue as a "going concern". Due to the Company's inability to continue as a "going concern", all future development cost and reserves related to proved undeveloped reserves as of  December 31, 2020 have been written off for financial reporting purposes. If and when the Company has adequate capital resources to fund the projects the reserves will be reinstated.

Markets and Customers

The revenue generated by our operations is highly dependent upon the prices we receive for our oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas production are subject to wide fluctuations and depend on numerous factors beyond our control including seasonality, the condition of the world wide economy (particularly the manufacturing sector), foreign imports, political conditions in other petroleum producing countries, the actions of the OPEC, domestic regulation, legislation and policies, the outbreak of pandemic or contagious diseases, such as the recent COVID-19 coronavirus.  Decreases in the prices we receive for our oil and gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves, our revenue, profitability and cash flow from operations. Refer to “Risk Factors – Risks Related to Our Industry — Market conditions for oil and gas and particularly volatility of prices for oil and gas, could adversely affect our revenue, cash flows from operations, profitability and growth” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies” for more information relating to the effects that decreases in oil and gas prices have on us. To help mitigate the impact of commodity price volatility, we hedge a portion of our production through the use of fixed price swaps and basis differential swap contracts. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General – Commodity Prices and Hedging Arrangements” and Note 11 of the notes to our consolidated financial statements for more information regarding our derivative activities.

Substantially all of our oil and gas is sold at current market prices under short-term arrangements, as is customary in the industry. During the year ended December 31, 2020, four purchasers of production accounted for approximately 73% of our oil and gas sales. During the year ended December 31, 2019, two purchasers of production accounted for approximately 71% of our oil and gas sales. We believe that there are numerous other purchasers available to buy our oil and gas and that the loss of any of these purchasers would not materially affect our ability to sell our oil and gas. Furthermore, the largest purchasers of our oil and gas have changed from year to year.

Regulation of Oil and Gas Activities

The exploration, production and transportation of all types of hydrocarbons are subject to significant governmental regulations. Our properties are affected from time to time in varying degrees by political developments and federal, state and local laws and regulations. In particular, oil and gas production operations and economics are, or in the past have been, affected by industry specific price controls, taxes, conservation, safety, environmental and other laws relating to the petroleum industry, and by changes in such laws and by periodically changing administrative regulations.

Federal, state and local laws and regulations govern oil and gas activities. Operators of oil and gas properties are required to have a number of permits in order to operate such properties, including operator permits and permits to dispose of salt water. In addition, under federal law, operators of oil and gas properties are required to possess certain certificates and permits in order to operate such properties. We possess all material requisite permits required by Federal, state and other local authorities in which we operate properties.

Development and Production

The operations of our properties are subject to various types of regulation at the federal, state and local levels. These types of regulations include requiring the operator of oil and gas properties to possess permits for the drilling and development of wells, post bonds in connection with various types of activities, and file reports concerning operations. Most states, and some counties and municipalities in which we operate, regulate one or more of the following:

• the location of wells;

• the method of drilling and casing wells;

• the flaring of gas;

• the method of completing and fracture stimulating wells;

• the surface use and restoration of properties upon which wells are drilled;

• the plugging and abandoning of wells; and

• the notice to surface owners and other third parties.

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Some states regulate the size and shape of development and spacing units or proration units for oil and gas properties. Some states allow forced pooling or unitization of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum allowable rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas we can produce from our wells or limit the number of wells or the locations at which our wells can be drilled. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, gas and NGLs within its jurisdiction.

Operations on Federal or Indian oil and gas leases must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various tribal and federal agencies, including the Bureau of Land Management and the Office of Natural Resources Revenue, which we refer to as ONRR, (formerly Minerals Management Service). ONRR establishes the basis for royalty payments due under federal oil and gas leases through regulations issued under applicable statutory authority. State regulatory authorities establish similar standards for royalty payments due under state oil and gas leases. The basis for royalty payments established by ONRR and the state regulatory authorities is generally applicable to all federal and state oil and gas leases. Accordingly, we believe that the impact of royalty regulation on the operations of our properties should generally be the same as the impact on our competitors. We believe that the operations of our properties are in material compliance with all applicable regulations as they pertain to Federal or Indian oil and gas leases.

The failure to comply with these rules and regulations can result in substantial penalties, including lease suspension or termination in certain cases. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability. Our competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect us.

Regulation of Transportation and Sale of Gas in the United States

Historically, the transportation and sale for resale of gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, as amended, which we refer to as NGA, the Natural Gas Policy Act of 1978, as amended, which we refer to as NGPA, and regulations promulgated thereunder by the Federal Energy Regulatory Commission, which we refer to as FERC, and its predecessors. In the past, the federal government has regulated the prices at which gas could be sold. Deregulation of wellhead gas sales began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, as amended, which we refer to as the Decontrol Act. The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of gas effective January 1, 1993. While sales by producers of gas can currently be made at unregulated market prices, Congress could reenact price controls in the future.

Since 1985, FERC has endeavored to make gas transportation more accessible to gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate gas pipeline industry and to create a regulatory framework that will put gas sellers into more direct contractual relations with gas buyers by, among other things, unbundling the sale of gas from the sale of transportation and storage services. Beginning in 1992, FERC issued Order No. 636 and a series of related orders, which we refer to collectively as Order No. 636, to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell gas. FERC continues to regulate the rates that interstate pipelines may charge for such transportation and storage services. Although FERC’s orders do not directly regulate gas producers, they are intended to foster increased competition within all phases of the gas industry.

In 2000, FERC issued Order No. 637 and subsequent orders, which we refer to, collectively, as Order No. 637, which imposed a number of additional reforms designed to enhance competition in gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most major aspects of Order No. 637 have been upheld on judicial review, and most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect.

The Energy Policy Act of 2005, which we refer to as EP Act 2005, gave FERC increased oversight and penalty authority regarding market manipulation and enforcement. EP Act 2005 amended the NGA to prohibit market manipulation and also amended the NGA and the NGPA to increase civil and criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of FERC to up to $1,000,000 per day, per violation. In addition, FERC issued a final rule effective January 26, 2006, regarding market manipulation, which makes it unlawful for any entity, in connection with the purchase or sale of gas or transportation service subject to FERC jurisdiction, to defraud, make an untrue statement, or omit a material fact or engage in any practice, act, or course of business that operates or would operate as a fraud. This final rule works together with FERC’s enhanced penalty authority to provide increased oversight of the gas marketplace.

The gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach currently pursued by FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other gas producers, gatherers and marketers.

Generally, intrastate gas transportation is subject to regulation by state regulatory agencies, although FERC does regulate the rates, terms, and conditions of service provided by intrastate pipelines that transport gas subject to FERC’s NGA jurisdiction pursuant to Section 311 of the NGPA. The basis for state regulation of intrastate gas transportation and the degree of regulatory oversight and scrutiny given to intrastate gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate gas transportation in any states in which we operate and ship gas on an intrastate basis will not affect the operations of our properties in any way that is materially different from the effect of such regulation on our competitors.

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Gas Gathering in the United States

Section 1(b) of the NGA exempts gas gathering facilities from the jurisdiction of the FERC. FERC has developed tests for determining which facilities constitute jurisdictional transportation facilities under the NGA and which facilities constitute gathering facilities exempt from FERC’s NGA jurisdiction. From time to time, FERC reconsiders its test for defining non-jurisdictional gathering. FERC has also permitted jurisdictional pipelines to “spin down” exempt gathering facilities into affiliated entities that are not subject to FERC jurisdiction, although FERC continues to examine the circumstances in which such a “spin down” is appropriate and whether it should reassert jurisdiction over certain gathering companies and facilities that previously had been “spun down.” We cannot predict the effect that FERC’s activities in this regard may have on the operations of our properties, but we do not expect these activities to affect the operations in any way that is materially different from the effect thereof on our competitors.

State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take or service requirements, but does not generally entail rate regulation. In the United States, gas gathering has received greater regulatory scrutiny at both the state and federal levels in the wake of the interstate pipeline restructuring under FERC Order 636. For example, the Texas Railroad Commission enacted a Natural Gas Transportation Standards and Code of Conduct to provide regulatory support for the state’s more active review of rates, services and practices associated with the gathering and transportation of gas by an entity that provides such services to others for a fee, in order to prohibit such entities from unduly discriminating in favor of their affiliates.

Regulation of Transportation of Oil in the United States

Sales of oil, condensate and gas liquids are not currently regulated and are made at negotiated prices. The transportation of oil in common carrier pipelines is subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, FERC, in February 2003, increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulations, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect the operations of our properties in any way that is materially different from the effect of such regulation on our competitors.

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

All of our oil is sold on lease, at which time custody transfers, either by truck or pipeline. We are not able to determine how much of our sold oil is ultimately shipped to market centers using rail transportation facilities owned and operated by third parties. The U.S. Department of Transportation’s (“U.S. DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) establishes safety regulations relating to transportation of oil by rail transportation. In addition, third party rail operators are subject to the regulatory jurisdiction of the Surface Transportation Board of the U.S. DOT, the Federal Railroad Administration (“FRA”) of the DOT, the U.S. Occupational Safety and Health Administration, as well as other federal regulatory agencies. Additionally, various state and local agencies have jurisdiction over disposal of hazardous waste and seek to regulate movement of hazardous materials in ways not preempted by federal law.

In response to rail accidents occurring between 2002 and 2008, the U.S. Congress passed the Rail Safety and Improvement Act of 2008, which implemented regulations governing different areas related to railroad safety. Recently, in response to train derailments occurring in 2013, U.S. regulators have been implementing or considering new rules to address the safety risks of transporting oil by rail. On January 23, 2014, the National Transportation Safety Board (“NTSB”) issued a series of recommendations to the FRA and PHMSA to address safety risks, including (i) requiring expanded hazardous material route planning for railroads to avoid populated and other sensitive areas, (ii) developing an audit program to ensure rail carriers that carry petroleum products have adequate response capabilities to address worst-case discharges of the entire quantity of product carried on a train, and (iii) auditing shippers and rail carriers to ensure they are properly classifying hazardous materials in transportation and that they have adequate safety and security plans in place. Additionally, on February 25, 2014 the DOT issued an emergency order requiring all persons, prior to offering oil into transportation, to ensure such product is properly tested and classed and to assure all shipments by rail of oil be handled as a Packing Group I or II hazardous material.

We do not currently own or operate rail transportation facilities or rail cars; however, the adoption of any regulations that impact the testing or handling of shipments of oil by rail transportation could increase our costs of doing business and limit our ability to transport and sell our oil at favorable prices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows from operations. At this time, it is not possible to estimate the potential impact on our business if new federal or state rail transportation regulations are enacted.

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Environmental Matters

Oil and gas operations are subject to numerous federal, state and local laws and regulations controlling the generation, use, treatment, storage and disposal of materials and the discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations may: 

• require the acquisition of a permit or other authorization before construction or drilling commences;

• impose design, construction and permitting requirements on facilities in conjunction with oil and gas operations, including the construction of pollution control devices;

• require protective measures to prevent certain fluids from coming into contact with ground water;

• restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production, and gas processing activities;

• suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, and areas inhabited by threatened or endangered species and other protected areas;

• require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells;

• require disclosure of chemicals injected into wells in conjunction with hydraulic fracturing operations;

• restrict injection of liquids into subsurface strata that may contaminate groundwater or increase seismic activity;

• restrict the availability of water necessary for hydraulic fracturing operations;

• impose substantial penalties for violations of environmental rules or pollution resulting from our operations;

• curtail production in association with permit limits; and

• curtail or prohibit production for exceeding gas flaring limits.

Environmental permits that the operators of properties are required to possess may be subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations and permits, and violations are subject to injunction, civil fines, and even criminal penalties. Our management believes that we are in substantial compliance with current environmental laws and regulations, and that we will not be required to make material capital expenditures to comply with existing laws. Nevertheless, changes in existing environmental laws and regulations or interpretations thereof could have a significant impact on our operations as well as the oil and gas industry in general, and thus we are unable to predict the ultimate cost and effects of future changes in environmental laws and regulations.

We are not currently involved in any administrative, judicial or legal proceedings arising under federal, state, or local environmental protection laws and regulations, or under federal or state common law, which would have a material adverse effect on our respective financial positions or results of operations. Moreover, we maintain insurance against the costs of clean-up operations, but we are not fully insured against all such risks. A serious incident of pollution may result in the suspension or cessation of operations in the affected area.

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The following is a discussion of the current relevant environmental laws and regulations that relate to our operations.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, also known as Superfund, and which we refer to as "CERCLA", and comparable state statutes impose strict joint, and several liability, without regard to fault or legality of conduct, on certain classes of persons who are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include among others, the current and former owners or operators of a disposal site or sites where a release occurred and companies that arranged for the transportation or disposal of the hazardous substances released at the site. Under CERCLA, such persons or companies may be retroactively liable 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 authorizes the Environmental Protection Agency ("EPA"), and in some cases third parties, to take actions 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. In addition, it is not uncommon for neighboring land owners and other third parties to file claims for personal injury, property damage, and recovery of response costs allegedly caused by the hazardous substances released into the environment.

In the course of our ordinary operations, certain wastes may be generated that may fall within CERCLA’s definition of a “hazardous substance.” We may be liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed. Although CERCLA contains a “petroleum exclusion” from the definition of “hazardous substance,” state laws affecting our operations impose cleanup liability relating to petroleum and petroleum related products, including oil cleanups.

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

Oil Pollution Act of 1990.  Federal regulations also require certain owners and operators of facilities that store or otherwise handle oil to prepare and implement spill response plans relating to the potential discharge of oil into surface waters. The Federal Oil Pollution Act, which we refer to as OPA, and analogous state laws, contain numerous requirements relating to prevention of, reporting of, and response to oil spills into waters of the United States.  A failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on our financial position or results of operations.

Resource Conservation and Recovery Act.   The Resource Conservation and Recovery Act, which we refer to as "RCRA", is the principal federal statute governing the treatment, storage and disposal of hazardous and non-hazardous solid wastes.  RCRA imposes stringent requirements and liability for failure to meet such requirements, on persons who generate or transport regulated waste materials and also on persons who own or operate a waste treatment, storage or disposal facility. Analogous state laws also impose requirements associated with the management such wastes. At present, RCRA includes a statutory exemption that allows most oil and gas exploration and production wastes to be classified and regulated as non-hazardous wastes. A similar exemption is contained in many of the state counterparts to RCRA.  At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and gas exploration and production wastes from regulation as hazardous wastes. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose and would cause us to incur increased operating expenses. Also, in the ordinary course of our operations, we generate small amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes. We believe that our operations comply in all material respects with the requirements of RCRA and its state counterparts.

Naturally Occurring Radioactive Materials, which we refer to as "NORM", are materials not covered by the Atomic Energy Act, whose radioactivity is enhanced by technological operations such as mineral extraction or processing through exploration and production conducted by the oil and gas industry. NORM wastes are regulated under the RCRA framework, but primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and limitations upon the release of NORM contaminated land for unrestricted use. We believe that the operations of our properties are in material compliance with all applicable NORM standards established by the various states in which we operate wells.

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Clean Water Act.   The Clean Water Act, which we refer to as the "CWA", and analogous state laws, impose restrictions and controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA regulates storm water run-off from oil and gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of the CWA require appropriate containment berms and similar structures to help prevent the contamination of waters of the United States in the event of a petroleum hydrocarbon tank spill, rupture or leak. The reach and scope of the CWA, and the determination of what water bodies and land areas are regulated as waters of the U.S., is the subject of various rules adopted by  EPA and the U.S. Army Corps of Engineers which we refer to as the WOTUS Rules, and on-going federal court litigation arising out of the rules and recent amendments. The WOTUS Rules, litigation over the rules, and the associated regulatory uncertainty, could impact our operations by subjecting new land and waters to regulation, and increase our cost of operations. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for resource damages resulting from the release. We believe that the operations of our properties comply in all material respects with the requirements of the CWA and state statutes enacted to control water pollution.

Safe Drinking Water Act. Our operations also produce wastewaters that are disposed via underground injection wells. These activities are regulated by the Safe Drinking Water Act, which we refer to as the "SDWA", and analogous state and local laws. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and gas production., or the flow-back of hydraulic fracturing fluids. The main goal of the SDWA is the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Injection well operations are strictly controlled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. In most states, no underground injection may take place except as authorized by permit or rule. In addition, subsurface injection of water or other produced fluids from drilling or hydraulic fracturing processes have come under increased public and governmental scrutiny. Some jurisdictions, Texas for example, have adopted new and more stringent rules for injection wells aimed at reducing the potential for earthquakes associated with injection activities, including new restrictions on siting of such injection wells. We currently own and operate various underground injection wells and rely on third-party owned injection wells. Failure to comply with our permits could subject us to civil and/or criminal enforcement. More stringent regulations of injection wells could additionally increase our cost of operations. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.

Clean Air Act.    The Clean Air Act, which we refer to as the CAA, and state air pollution laws and regulations provide a framework for national, state and local efforts to protect air quality. The operation of our properties utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. In the past few years, EPA has adopted new more restrictive regulations governing air emissions from oil and gas operations, including regulations which restrict emissions of methane, volatile organic compounds and hazardous air pollutants.  

Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas may require us to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some oil and gas facilities may be included within the categories of hazardous air pollutant sources, which are subject to more stringent regulation under the CAA. Failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. We may be required to incur capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.

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Hydraulic Fracturing. Most of our current operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells.  This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of chemical additives—as well as sand, or other proppants, into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore.  Many of our newer wells would not be economical without the use of hydraulic fracturing to stimulate the formation to enhance production from the well.  Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs, but where these operations occur on federal or tribal lands they are subject to regulation by the U.S. Department of the Interior, Bureau of Land Management (“BLM”).  In addition to federal legislative and regulatory actions, some states and local governments have considered imposing, or have adopted various conditions and restrictions on hydraulic fracturing operations, including but not limited to requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in hydraulic fracturing, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations.  In some states, including Texas, water use may also be regulated and potentially curtailed by local groundwater management districts which could impact the availability of water for hydraulic fracturing.  If these types of restrictions are widely adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells, and these laws could make it easier for third parties to initiate litigation against us in the event of perceived problems with water wells in the vicinity of an oil or gas well or other alleged environmental problems.  Additional information concerning hydraulic fracturing is included under Item 1A "Risk Factors."

 Climate Change and Greenhouse Gas Regulation. Scientific studies have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases” or “GHGs” pursuant to efforts spearheaded by the United Nations. Domestically, the Fourth National Climate Assessment report, released in November 2018, noted that climate change is mostly driven by GHG emissions and that climate change is accelerating. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, gas, and refined petroleum products, are considered GHGs. We expect continuing debate, especially in the political arena, over how to address climate change and what policies and regulations are necessary to address the issue. It is possible that domestic and international regulations addressing climate change will have adverse effects on the market for oil, gas and other fossil fuel products as well as adverse effects on the business and operations of companies engaged in the exploration for, and production of, oil, gas and other fossil fuel products. Given widely divergent political views on climate change regulation, we are unable to predict the timing, scope and effect of any proposed or future investigations, laws, regulations or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such investigations, laws, regulations and treaties (if enacted) could materially and adversely affect our operations, financial condition and results of operations. In addition, several states and local governments have adopted, or are considering adopting, regulations or ordinances to reduce emissions of GHGs. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for our products. The various efforts to regulate the emissions of GHGs (including lawsuits pending in United States federal courts) may affect the cost of our operations, may affect the public’s perception of our industry, and may reduce demand for our products.

An example of the uncertainty in regulations comes from the BLM flaring rule. In November 2016, BLM issued a final rule to further restrict venting and flaring of gas from oil and gas operations on public lands.  Then, BLM issued a stay of these requirements in December 2017. In September 2018, BLM published a final rule to modify and rescind substantial portions of the flaring rule. The rescission was challenged by litigation filed in the U.S. District Court for the Northern District of California. If the litigation is successful and the rule restricting flaring of gas becomes effective, we would have to curtail production from the affected wells and would incur additional costs of compliance as well as increased monitoring and recordkeeping for some of our facilities.

Any of the climate change regulatory and legislative initiatives described above could have a material adverse effect on our business, financial condition, and results of operations. Additional information concerning climate change is included under Item 1A. “Risk Factors.”

National Environmental Policy Act.    Oil and gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, which we refer to as NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. If we were to conduct any exploration and production activities on federal lands in the future, those activities may need to obtain governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and gas projects and increase the cost of such operations.

Endangered Species Act.  The Endangered Species Act, which we refer to as the ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our properties may be located in areas that may be designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA.  Looking forward, we expect more listings of such species to occur, in light of renewed efforts by certain environmental activists to use the ESA as a mechanism to restrict land development and energy production. Such listings could include habitat in areas where we operate or plan to operate, or which could adversely affect our ability to secure needed sand, water or other materials for our operations or to transport oil or gas via pipeline to our customers. Further, some of the species could become subject to voluntary rangeland conservation plans that could affect our operations of sources of materials. Such listing of additional species, or the discovery of previously unidentified endangered or threatened species, or the adoption of conservation plans, could cause us to incur additional costs or become subject to operating restrictions, construction delays, or bans on operating in the affected areas.

Abandonment Costs.    All of our oil and gas wells will require proper plugging and abandonment at some time in the future. We have posted bonds with most regulatory agencies to ensure compliance with our plugging responsibility. Plugging and abandonment operations and associated reclamation of the surface site are important components of our environmental management system. We plan accordingly for the ultimate disposition of properties that are no longer producing.

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Title to Properties

As is customary in the oil and gas industry, we make only a cursory review of title to undeveloped oil and gas leases at the time we acquire them. However, before drilling commences, we make a thorough title search, and any material defects in title are remedied prior to the time actual drilling of a well begins. To the extent title opinions or other investigations reflect title defects, we, rather than the seller/lessor of the undeveloped property, are typically obligated to cure any title defect at our expense. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. We believe that we have good title to our properties, some of which are subject to immaterial encumbrances, easements and restrictions. The oil and gas properties we own are also typically subject to royalty and other similar non-cost bearing interests customary in the industry. We do not believe that any of these encumbrances or burdens will materially affect our ownership or use of our properties.

Competition

We operate in a highly competitive environment. The principal resources necessary for the exploration and production of oil and gas are leasehold prospects under which oil and gas reserves may be discovered, drilling rigs and related equipment and services to explore for such reserves and knowledgeable personnel to conduct all phases of oil and gas operations. We must compete for such resources with both major oil and gas companies and independent operators. Many of these competitors have financial and other resources substantially greater than ours. Although we believe our current operating and financial resources are adequate to preclude any significant disruption of our near-term operations, we cannot assure you that such materials and resources will be available to us in the future.

Employees

As of April 30, 2021, we had 62 full-time employees. We retain independent geological, land, marketing, engineering and health and safety consultants from time to time and expect to continue to do so in the future. We operate on the fundamental philosophy that people are our most valuable asset as every person who works for us has the potential to impact our success. Identifying quality talent is at the core of everything we do and our success is dependent upon our ability to attract, develop and retain highly qualified employees. Our core values include honesty/integrity, treating people fairly, high performance, efficient and effective processes, open communication and being respected in our local communities. These values establish the foundation on which the culture is built and represent the key expectations we have of our employees. We believe our culture and commitment to our employees creates an environment that allows us to attract and retain our qualified talent, while simultaneously providing significant value to the Company and its stockholders by helping our employees attain their highest level of creativity and efficiency.

Available Information

We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). You may read and copy any document we file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for information on the public reference room. The SEC maintains an internet web site that contains annual, quarterly and current reports, proxy statements and other information that issuers (including Abraxas) file electronically with the SEC. The SEC’s web site is www.sec.gov.

Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and amendments filed with the SEC are available free of charge on our web site at www.abraxaspetroleum.com in the Investor Relations section as soon as practicable after such reports are filed.  Information on our web site is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

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Item 1A. Risk Factors

Going Concern 

As discussed under Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, our present level of indebtedness and the recent commodity price environment present challenges to our ability to comply with certain covenants in our credit facilities and under applicable auditing standards the independent accountants' opinion on our  financial statements for the year ended December 31, 2020 contains an explanatory paragraph regarding the Company's ability to continue as a "going concern". At December 31, 2020, we had a total of $95.0  million outstanding under our First Lien Credit Facility, $112.7 million under our Second Lien Credit facility and total indebtedness of  $220.5 million including a $10.0 million exit fee. As of April 30, 2021, we had a total of $89.5  million outstanding under our First Lien Credit Facility, $127.2  million under our Second Lien Credit Facility, including a $10.0 million exit fee, and total indebtedness of $219.4 million. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements.

Specifically, with regard to our credit agreements, we did not satisfy the first lien debt to consolidated EBITDAX ratio covenant under our First Lien Credit Facility as of the December 31, 2020 measurement date and such failure represented an event of default under our First Lien Credit Facility. In addition,  we do not anticipate that we will  maintain compliance with the Second Lien Credit Facility total leverage ratio covenant or the minimum asset coverage ratio (as defined in Note 4), both of which will be  first tested as of September 30, 2021, over the next twelve months and, accordingly, the audit report prepared by our auditors with respect to the financial statements in this Form 10-K includes an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern.” The inability to maintain compliance with certain covenants of our Second Lien Credit Facility would represent an additional default under our First Lien Credit Facility as of the end of any such future fiscal quarters. The consolidated financial statements do not include any adjustments that might result from the outcome of the "going concern" uncertainty, with the exception of removing all proved undeveloped reserves and the corresponding capital requirements.

We are evaluating the available financial alternatives and are in discussion with our lenders seeking additional waivers or amendments to the covenants or other provisions of our credit facilities to address any current and future default relating to the covenants in question. The existing defaults at March 31, 2021 are subject to  forbearance agreements with our lenders that currently expire on May 6, 2021. No assurance can be provided that the forbearance agreements will be further extended. If, upon a future default, the Company is unable reach an agreement with its lenders or find acceptable alternative financing, the lenders under the Company's  First Lien Credit Facility may choose to accelerate repayment. If the Company's lenders accelerate the payment of amounts outstanding under its credit facilities, the Company does not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so. The Company could attempt to obtain additional sources of capital from asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination thereof. However, the Company cannot provide any assurances that it will be successful in obtaining capital from such transactions on acceptable terms, or at all. 

Under applicable accounting principles these circumstances are deemed to create substantial doubt regarding the Company's ability to continue as a "going concern". The consolidated financial statements have been prepared on a "going concern" basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business for the twelve-month period following the date of issuance of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amount, or the amount and classification of liabilities that may result should the Company be unable to continue as a "going concern".

In April 2021, we received notice that certain of our hedging agreements were being terminated as a result of events of default under the First Lien Credit Facility, and we voluntarily terminated most of our other hedging arrangements. As a result of the settlement of the terminated hedges, we have an outstanding obligations of $9.9 million. The settlement values of the terminated hedges were determined at various dates between April 15 and April 30, 2021. These obligations will be added to the balance of the First Lien Credit Facility and accrue interest  at the default interest rate, currently 6.7%, until repaid. The remaining  hedging agreements may also be terminated as a result of such events of default. The settlement of terminated hedging agreements may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. See Note 14 “Subsequent Events” for current information regarding non-compliance with certain covenants.

Risks Related to Our Business

We have substantial indebtedness which may adversely affect our cash flow and business operations.

At December 31, 2020, we had a total of $95.0 million of indebtedness under our First Lien Credit Facility, $112.7 million under our Second Lien Credit Facility, and total indebtedness of $220.5 million, including a $10.0 million exit fee. As of April 30, 2021, we had a total of  $89.5 million indebtedness under our First Lien Credit Facility, $117.2 under our Second Lien Credit Facility and total indebtedness, including $10.0 million exit fee, and total indebtedness of $219.4 million. There is no further availability under our First Len Credit Facility. Our indebtedness could have important consequences to us, including:

• affecting our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes which may be impaired or not available on favorable terms;

• requiring us to meet financial tests contained in our credit facilities and future debt arrangements that may affect our flexibility in planning for and reacting to changes in our business, including future business opportunities;

• requiring us to use a substantial portion of our cash flow from operations to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations and future business opportunities; and

• making us more vulnerable to competitive pressures if there is a downturn in our business or the economy in general, than our competitors with less debt.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying capital expenditures, acquisitions and/or selling assets, restructuring or refinancing our indebtedness or seeking additional debt or equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms or at all.

A breach of the terms and conditions of our credit facilities, including the inability to comply with the required financial covenants, could result in an event of default. If an event of default occurs (after any applicable notice and cure periods), the lenders under our First Lien Credit Facility would be entitled to accelerate the repayment of amounts outstanding (including accrued and unpaid interest and fees). In such an event, the lenders under our First Lien Credit Facility could also foreclose upon any collateral securing such obligations, which may be all or substantially all of our assets.  If that occurred, we may not be able to continue to operate as a "going concern". For the fiscal quarter ended September 30, 2019, the Company was in violation of its current ratio covenant under its First Lien Credit Facility. A waiver of this violation was obtained and the lenders agreed not to charge default interest.  Additionally, due to the unprecedented conditions surrounding the outbreak and spread of the COVID-19 coronavirus pandemic, the decline in oil prices during the first half of 2020, and related geopolitical developments, we failed to file our Annual Report on Form 10-K for the period ended December 31, 2019 no later than 90 days after the end of such fiscal year, which resulted in violations of certain covenants under our First Lien Credit Facility and Second Lien Credit Facility (each as in effect prior to their amendments). We also failed to maintain the required hedges under the Second Lien Credit Facility with respect to the fiscal quarter ended March 31, 2020, which resulted in a violation of certain covenants under the Second Lien Credit Facility (as in effect prior to the amendment of the Second Lien Credit Facility). Subject to the terms and conditions of the First Lien Credit Facility and the Second Lien Credit Facility, a waiver was obtained from each of the lenders and each of the lenders agreed not to charge default interest with respect to such defaults. We cannot assure you that we will be able to obtain similar waivers in the future. The failure to make a payment under the Second Lien Credit Facility could result in an event of default. If an event of default occurs (after any applicable notice and cure periods), the lenders (the “Junior Lenders”) under the Second Lien Credit Facility would be entitled to accelerate the repayment of amounts outstanding under the Second Lien Credit Facility (including accrued interest, fees and reimbursements). In such an event, the Junior Lenders, subject to the rights of the lenders under the First Lien Credit Facility, could also foreclose upon any collateral securing such obligations, which may be all or substantially all of our assets. If that occurred, we may not be able to operate as a "going concern". 

In April 2021, we received notice that certain of our hedging agreements were being terminated as a result of events of default under the First Lien Credit Facility and we voluntarily terminated most of our other hedging arrangements. As a result of the settlement of the terminated hedges, we have an outstanding obligations of $9.9 million. The settlement values of the terminated hedges were determined at various dates between April 15 and April 30, 2021. These obligations will be added to the balance of the First Lien Credit Facility and accrue interest  at the default interest rate, currently 6.7%, until repaid. Our remaining hedging agreements may also be terminated as a result of such events of default. The settlement of terminated hedging agreements may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. See Note 14 “Subsequent Events” for current information regarding non-compliance with certain covenants.

Depressed oil and/or gas prices would have a material and adverse effect on us.

Our financial results and the value of our properties are highly dependent on the general supply and demand for oil, gas and NGL, which impact the prices we ultimately realize on our sales of these commodities. Oil, gas and NGL prices are volatile and became more volatile during 2020. During the first half of 2020, there was a significant decline in oil, gas and NGL prices, which adversely affected our operating results and contributed to a reduction in our anticipated future capital expenditures. Prices improved in late 2020. In addition to the impact on our results of operations, future declines in oil and gas prices could cause us to write down the value of our estimated proved reserves. We recorded an impairment of $187.0 million for the year ended December 31, 2020. Oil and natural gas prices remain volatile, and as a result, we could and likely will record impairments in future periods, the amount of which will be dependent upon many factors such as future prices of oil, gas and NGL, increases or decreases in our reserve base, changes in estimated costs and expenses, and oil and gas property acquisitions.

 Prices in 2019 and 2020 have remained relatively low, sharply declining at the beginning of March 2020, and price volatility has continued into 2021.  A sustained weakness or further deterioration in commodity prices could materially and adversely impact our business by resulting in, or exacerbating, the following effects:

• reducing the amount of oil, gas and NGL that we can produce economically;

• limiting our financial flexibility, liquidity and access to sources of capital, such as equity and debt;

• reducing our revenues, cash flows from operations and profitability;

• causing us to decrease our capital expenditures or maintain reduced capital spending for an extended period, resulting in lower future production of oil, gas and NGL; and

• reducing the carrying value of our properties, resulting in additional noncash write-downs.

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Market prices and our realized prices have been volatile and are likely to continue to be volatile in the future due to numerous factors beyond our control. These factors include:

• the level of demand;

• domestic and global supplies of oil, NGL and gas;

• the price and quantity of imported and exported oil, NGL and gas;

• the actions of other oil exporting nations;

• weather conditions and changes in weather patterns;

• the availability, proximity and capacity of appropriate transportation facilities, gathering, processing and compression facilities, storage facilities and refining facilities;

• global or national health concerns, including the outbreak of pandemic or contagious disease, such as the coronavirus (COVID-19);

• worldwide economic and political conditions, including political instability or armed conflict in oil and gas producing regions, competition for markets and political initiatives disfavoring fossil fuels;

• the price and availability of, and demand for, competing energy sources, including alternative energy sources;

• the nature and extent of governmental regulation, including environmental regulation, regulation of derivatives transactions and hedging activities, tax laws and regulations and laws and regulations with respect to the import and export of oil, gas and related commodities;

• the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others, and;

• the effect of worldwide energy conservation measures.

Our cash flows from operations depend to a great extent on the prevailing prices for oil and gas, as well as our hedges to offset declines in price. Prolonged or substantial declines in oil and/or gas prices would materially and adversely affect our liquidity, the amount of cash flows we have available for our capital expenditures and other operating expenses, our ability to access the credit and capital markets and our results of operations.

The marketability of our production depends largely upon the availability, proximity and capacity of oil and gas gathering systems, pipelines, storage and processing facilities.

The marketability of our production depends in part upon processing, storage and transportation facilities, which are also known as midstream facilities, owned and operated by third parties.  Transportation space on such gathering systems and pipelines is limited and at times unavailable due to repairs or improvements being made to such facilities or due to such space being utilized by other companies with priority transportation agreements.  Our access to transportation options can also be affected by federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand.  These factors and the availability of markets are beyond our control.  If adequate transportation and storage options are not available to us, the financial impact on us could be substantial and adversely affect our ability to produce and market our oil and gas. For example, our principal third party provider in the Bakken Field for these services has experienced, and may in the future, experience significantly increased gathering system pressures which have resulted in capacity constraints. These constraints, in turn, restricted our production and required us to flare gas, decreasing the volumes sold from our wells. Similarly, rapid production growth in the Permian Basin has strained the available midstream infrastructure there with adverse effects on our operations.

In addition to causing production curtailments and reducing the price we receive for the oil, gas and NGL we produce, given environmental impacts, including GHG production, regulatory agencies including the North Dakota Industrial Commission have adopted policies to reduce the volume of flared gas, the number of wells flaring and the duration of flaring. While these regulations have not had a material adverse effect on us to date, these current regulations relating to flaring gas or the adoption of additional regulations could cause us to shut-in production or curtail the drilling of new wells either of which could have a material adverse effect on us.

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We rely on third parties to continue to construct additional midstream facilities and related infrastructure to accommodate our growth, and the ability and willingness of those parties to do so is subject to a variety of risks.

For example:

• Decreases in commodity prices in recent years have resulted in reduced investment in midstream facilities by some third parties;

• Various interest groups have protested the construction of new pipelines, and particularly pipelines near water bodies, in various places throughout the country, and protests have at times physically interrupted pipeline construction activities;

• Some companies in our industry have sought to reject volume commitment agreements with midstream providers in bankruptcy proceedings, and the risk that such efforts will succeed, or that upstream energy company counterparties will otherwise be unable or unwilling to satisfy their volume commitments, may have the effect of reducing investment in midstream infrastructure; and

We have pursued a variety of strategies to alleviate some of the risks associated with the midstream services and facilities upon which we rely, including seeking alternative sources for processing and transporting gas that we produce. There can be no assurance that the strategies we pursue will be successful or adequate to meet our needs.

Lower oil and/or gas prices may also reduce the amount of oil and/or gas that we can produce economically.

Sustained substantial declines in oil and/or gas prices may render uneconomic a significant portion of our exploration, development and exploitation projects, which may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a prolonged or substantial decline in oil and/or gas prices such as we have experienced since mid-2014 has in the past caused, and would likely in the future cause, a material and adverse effect on our future business, financial condition, results of operations, liquidity and ability to finance capital expenditures. Additionally, if we experience significant sustained decreases in oil and gas prices such that the expected future cash flows from our oil and gas properties falls below the net book value of our properties, we may be required to write down the value of our oil and gas properties. Any such asset impairments could materially and adversely affect our results of operations and, in turn, the trading price of our common stock and ultimately lead to the Nasdaq Global Select Market's ("Nasdaq") decision to delist us.

For more information regarding Nasdaq's ability to delist us, the Listing Rule , and the effect of a reverse stock split, you should read the information under "Risk Related to Our Common Stock - Nasdaq could make a decision to delist us."

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We may not be able to fund the capital expenditures that will be required for us to increase reserves and production.

We must make capital expenditures to develop our existing reserves and to discover new reserves.  Historically, we have financed our capital expenditures primarily with cash flows from operations, borrowings under credit facilities, sales of properties, monetizing derivative contracts and sales of debt and equity securities and we expect to continue to utilize these sources in the future to the extent available.  We cannot assure you that we will have sufficient capital resources in the future to finance all of our planned capital expenditures, additionally, our amended credit facilities, place restrictions on our capital expenditures.

Volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect our cash flows from operations.  Lower prices and/or lower production could also decrease revenues and cash flows from operations, thus reducing the amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our drilling opportunities.  If our cash flows from operations does not increase as a result of capital expenditures, a greater percentage of our cash flows from operations will be required for debt service and operating expenses and our capital expenditures would, by necessity, be decreased.

If cash flows from operations or our borrowing base decrease, our ability to undertake exploration and development activities could be adversely affected.  As a result, our ability to replace production may be limited.  

If we cannot replace the production from the properties sold with production from our remaining properties, our cash flows from operations will likely decrease, which in turn, could decrease the amount of cash available for additional capital spending.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Our First Lien Credit Facility and our Second Lien Credit Facility contain a number of significant covenants that, among other things, limit our ability to:

• incur or guarantee additional indebtedness and issue certain types of preferred stock or redeemable stock;

• transfer or sell assets;

• create liens on assets;

• pay dividends or make other distributions on capital stock or make other restricted payments, including repurchasing, redeeming or retiring capital stock or subordinated debt or making certain investments or acquisitions;

• engage in transactions with affiliates;

• make any change in the principal nature of our business;

• permit a change of control; or

• consolidate, merge or transfer all or substantially all of our assets.

In addition, our credit facilities require us to maintain compliance with specified financial covenants.  Our ability to comply with these covenants may be adversely affected by events beyond our control, and we cannot assure you that we can maintain compliance with these covenants.  These financial covenants could limit our ability pursuant to the credit agreements to obtain future advances, make needed capital expenditures or otherwise conduct necessary or desirable business activities. We are also required to prepay outstanding amounts under the First Lien Credit Facility (and under certain circumstances, the Second Lien Credit Facility) with the proceeds from the termination of any derivative contracts and with respect to cash and liquid investments in excess of certain thresholds.

A breach of any of these covenants could result in a default under our First Lien Credit Facility and our Second Lien Credit Facility. For example, at  fiscal quarter ended September 30, 2019, we were not in compliance with the current ratio under our First Lien Credit Facility, and we failed to file our Annual Report on Form 10-K for the period ended December 31, 2019 no later than 90 days after the end of such fiscal year, which resulted in violations of certain covenants under the First Lien Credit Facility. We also failed to maintain the required hedges under the Second Lien Credit Facility with respect to the fiscal quarter  ended March 31, 2020, which resulted in a violation of certain covenants under the Second Lien Credit Facility (as  in effect prior to our amendment of the Second Lien Credit Facility), for which a waiver was obtained. While we received waivers for these defaults, we cannot assure you that we will be able to obtain such waivers in the future. A default, if not cured or waived, could result in all of our indebtedness under the credit facilities becoming immediately due and payable. If that should occur, we may not be able to pay all such indebtedness or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms acceptable or favorable to us.

See Item 1. Business, Going Concern and Note 14 "Subsequent Events" for current information regarding non-compliance with certain covenants.

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Lower oil and gas prices increase the risk of ceiling limitation write-downs.

We use the full cost method to account for our oil and gas operations.  Accordingly, we capitalize the cost to acquire, explore for and develop our oil and gas properties.  Under full cost accounting rules, the net capitalized cost of our oil and gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from our proved reserves, discounted at 10%.  If the net capitalized costs of our oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings.  This is called a “ceiling limitation write-down.” This charge does not impact cash flows from operating activities, but it does reduce our stockholders’ equity and earnings.  The risk that we will be required to write-down the carrying value of our oil and gas properties increases when oil and gas prices are low, which could be further impacted by the SEC’s oil and gas reporting disclosures, which require us to use an average price over the prior 12-month period, rather than the year-end price, when calculating the PV-10.  In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves.  An expense recorded in one period may not be reversed in a subsequent period even though oil and gas prices may have increased the ceiling applicable in the subsequent period.

At both December 31, 2019 and 2020, the net capitalized costs of our oil and gas properties exceeded the present value of estimated future cash flows from our proved reserves, resulting in recognition of an impairment of $51.3 million for the year ended December 31, 2019 and  $187.0 million for the year ended December 31, 2020. If commodity prices decline or continue to be depressed we will be required to record further write downs during 2021.

An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flows from operations.

Our oil and gas are priced in the local markets where it is produced based on local or regional supply and demand factors.  The prices we receive for our oil and gas are typically lower than the relevant benchmark prices, such as NYMEX.  The difference between the benchmark price and the price we receive is called a differential.  Numerous factors may influence local pricing, such as refinery capacity, location to market, product quality, pipeline capacity and specifications, upsets in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations.  Additionally, insufficient pipeline capacity, lack of demand in any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas.  For example, production increases from competing Canadian and Rocky Mountain producers, combined with limited refining and pipeline capacity in the Rocky Mountain area, have gradually widened differentials in this area. In addition, we have a gas sales contract related to certain gas and NGL produced in the Rocky Mountain Region, which provides that if certain margins of gas and NGL prices are not met by the purchaser, we receive no sales proceeds.

During 2020, our differentials averaged $ (2.52) per Bbl of oil and $ (1.86) per Mcf of gas. Approximately  47% of our oil production during 2020 was from the Rocky Mountain region and approximately 53% from the Permian region.  As our production from the Rocky Mountain and Permian regions continues to increase, we expect that the effect our price differentials on our revenues will also increase.  Increases in the differential between the benchmark prices for oil and gas and the realized price we receive could significantly reduce our revenues and our cash flow from operations.

Our derivative contracts could result in financial losses or could reduce our cash flows.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil and gas, we sometimes enter into derivative contracts, which we sometimes refer to as hedging arrangements, for a significant portion of our oil and gas production that could result in both realized and unrealized derivative contract losses.  As of December 31, 2020, we had NYMEX-based fixed price commodity swap arrangements, on approximately 88% of the oil production from our estimated net proved developed producing reserves (as of December 31, 2020) through December 31, 2021, 96% for 2022, 72%  for  2123 and 88%. for 2024.The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity price derivative contracts.  For example, the prices utilized in our derivative contracts were NYMEX-based, which may differ significantly from the actual prices we receive for oil and gas which are based on the local markets where the oil and gas is produced.  The prices that we receive for our oil and gas production are typically lower than the relevant benchmark prices that are used for calculating commodity derivative positions.  The difference between the benchmark price and the price we receive is called a differential, a significant portion of which is based on the delivery location which is called the basis differential.  As a result, our cash flows from operations are affected if the basis differentials widen more than anticipated. We entered into basis swaps to mitigate some of the effects of differentials, however they do not alleviate all of the effects of such differentials. Our cash flows from operations are also affected based upon the levels of our production.  If production is higher than we estimate, we  have greater commodity price exposure than intended.  If production is lower than the nominal amount that is subject to our hedging arrangements, we may be forced to satisfy all or a portion of our hedging arrangements without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial reduction in cash flows from operations. In April 2021, we received notice that certain of our hedging agreements were being terminated as a result of events of default under the First Lien Credit Facility and we voluntarily terminated most of our other hedging arrangements. As a result of the settlement of the terminated hedges, we have outstanding obligations of $9.9 million. The settlement values of the terminated hedges were determined at various dates between April 15 and April 30, 2021. These obligations will be added to the balance of the First Lien Credit Facility and accrue interest  at the default interest rate, currently 6.7%, until repaid. Our remaining hedging agreements may also be terminated as a result of such events of default. The settlement of terminated hedging agreements may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. See Note 14 “Subsequent Events” for current information regarding non-compliance with certain covenants

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If the prices at which we hedge our oil and gas production are less than current market prices, our cash flows from operations could be adversely affected.

When our derivative contract prices are higher than market prices, we will incur realized and unrealized gains on our derivative contracts and conversely, when our contract prices are lower than market prices, we will incur realized and unrealized losses. For the year ended December 31, 2020, we recognized a gain on our oil and gas derivative contracts of $42.9 million, consisting of a gain of $17.5 million on our settled contracts and a gain of $25.4 million on open contracts. The gain on settled contracts resulted in an increase in cash flows from operations.  We have terminated most of our hedging arrangements subsequent to December 31, 2020.

We cannot assure you that any derivative contracts that we enter into, will adequately protect us from financial loss in the future due to circumstances such as:

• highly volatile oil and gas prices;

• our production being less than expected; or

• a counterparty to one of our hedging transactions defaulting on its contractual obligations.

The counterparties to our derivative contracts may be unable to perform their obligations to us which could adversely affect our cash flows.

At times when market prices are lower than our derivative contract prices, we are entitled to cash payments from the counterparties to our derivative contracts.  Any number of factors may adversely affect the ability of our counterparties to fulfill their contractual obligations to us.  If one of our counterparties is unable or unwilling to make the required payments to us, it could adversely affect our cash flows from operations.

The Company's expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.

The Company has identified drilling locations and prospects for future drilling opportunities, including development and exploratory drilling activities. These drilling locations and prospects represent a significant part of the Company's future drilling plans. For example, the Company's proved reserves as of December 31, 2020 included proved undeveloped reserves and proved developed reserves that are behind pipe of 884  MBbls of oil, 190 MBbls of NGL and 1,185  MMcf of gas. Due to the substantial doubt that the Company can continue as a "going concern" the proved undeveloped reserves were removed. If and when the Company has the  capital to complete the undeveloped reserves, they will be reinstated in the Company's total  proved reserves. The Company's ability to drill and develop these locations depends on a number of factors, including the availability of capital, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment, services, resources and personnel and drilling results. There can be no assurance that the Company will drill these locations or that the Company will be able to produce oil or gas reserves from these locations or any other potential drilling locations. Changes in the laws or regulations on which the Company relies in planning and executing its drilling programs could adversely impact the Company's ability to successfully complete those programs. For example, under current Texas laws and regulations the Company may receive permits to drill, and may drill and complete, certain horizontal wells that traverse one or more units and/or leases; a change in those laws or regulations could adversely impact the Company's ability to drill those wells. Because of these uncertainties, the Company cannot give any assurance as to the timing of these activities or that they will ultimately result in the realization of proved reserves or meet the Company's expectations for success. As such, the Company's actual drilling activities may materially differ from the Company's current expectations, which could have a significant adverse effect on the Company's proved reserves, financial condition and results of operations.

We may be unable to acquire or develop additional reserves, in which case our results of operations and financial condition could be adversely affected.

Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that are profitable to produce.  The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced.  Unless we acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, we cannot assure you that our exploration and development activities will result in increases in our proved reserves. Based on the reserve information set forth in our reserve report as of December 31, 2020, our average annual estimated decline rate for our net proved developed producing reserves is  39%; 18% ; 14% ; 12% ; 12% in  2021, 2022, 2023, 2024 and 2025, respectively, 9% in the following five years, and approximately 9% thereafter.  These rates of decline are estimates and actual production declines could be materially higher. We have not always been able to fully replace the production volumes lost from natural field declines and prior property sales.  As our proved reserves and consequently our production decline, our cash flow from operations, and the amount that we are able to borrow under our credit facilities could also decline.  

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We may not find any commercially productive oil and gas reservoirs.

Drilling involves numerous risks, including the risk that the new wells we drill will be unproductive or that we will not recover all or any portion of our capital investment.  Drilling for oil and gas may be unprofitable.  Wells that are productive but do not produce sufficient net revenues after drilling, operating and other costs are unprofitable.   By their nature, estimates of undeveloped reserves are less certain.  Recovery of such reserves will require significant capital expenditures and successful drilling and completion operations.  Due to the substantial doubt of the Company remaining as a "going concern", all of the proved undeveloped reserves initially contained in the December 31, 2020 reserve report have been removed.   If the volume of oil and gas we produce decreases, our cash flows from operations may decrease.

The results of our drilling in unconventional formations, principally in emerging plays with limited drilling and production history using long laterals and modern completion techniques, are subject to more uncertainties than our drilling program in the more established plays and may not meet our expectations for reserves or production.

We drill wells in unconventional formations in several emerging plays.  Part of our drilling strategy to maximize recoveries from these formations involves the drilling of long horizontal laterals and the use of modern completion techniques of multi-stage fracture stimulations that have proven to be successful in other basins. Risks that we face include landing our well bore in the desired drilling zone, staying in the desired drilling zone, running casing the entire length of the well bore and being able to run tools and recover equipment the entire length of the well bore during completion. Our experience with horizontal drilling and multi-stage fracture stimulations of these formations to date, as well as the industry’s drilling and production history in these formations, is relatively limited. The ultimate success of these drilling and completion strategies and techniques will be better evaluated over time as more wells are drilled and longer term production profiles are established. In addition, based on reported decline rates in these emerging plays as well as the industry’s experience in these formations, we estimate that the average monthly rates of production may decline as much as 95% during the first twelve months of production. Actual decline rates may differ significantly. Accordingly, the results of our drilling in these unconventional formations are more uncertain than drilling results in other more established plays with longer reserve and production histories.

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

The oil and 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, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

We may not adhere to our proposed drilling schedule.

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

• prevailing and anticipated prices for oil and gas;

• the availability and costs of drilling and service equipment and crews;

• economic and industry conditions at the time of drilling;

• the availability of sufficient capital resources;

• the results of our exploitation efforts;

• the acquisition, review and interpretation of seismic data;

• our ability to obtain permits for and to access drilling locations;

• continuous drilling obligations; and

• lease expirations.

Although we have identified numerous drilling locations, we may not be able to drill those locations within our expected time frame or at all.  In addition, our drilling schedule may vary from our expectations because of future uncertainties. For example, we have in the past, and may be required in the future, to delay drilling or completing wells in order to protect them from fracture stimulation of other wells in the same area.

We cannot control the activities on the properties we do not operate and are unable to ensure their proper operation and profitability.

We currently do not operate all of the properties in which we have an interest. Non-operated properties represented approximately 2.6% of our estimated net proved reserves on a Boe basis at December 31, 2020.  As a result, we have limited ability to exercise influence over and control the risks associated with operation of these properties. The failure of an operator to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including:

• the operator could refuse to initiate exploitation or development projects and if we proceed with any of those projects, we may not receive any funding from the operator with respect to that project;

• the operator may initiate exploitation or development projects on a different schedule than we would prefer;

• the operator may propose greater capital expenditures than we wish, including expenditures to drill more wells or build more facilities on a project than we have funds for, which may mean that we cannot participate in those projects and thus, not participate in the associated revenue stream; and

• the operator may not have sufficient expertise or resources.

Any of these events could significantly and adversely affect our anticipated exploitation and development activities.

Seasonal weather conditions and other factors could adversely affect our ability to conduct drilling activities.

Our operations could be adversely affected by weather conditions and wildlife restrictions on federal leases. In the Williston Basin, drilling and other oil and gas activities cannot be conducted as efficiently during the winter and spring months. Winter and severe weather conditions limit and may temporarily halt the ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our oil and gas operations and materially increase our operating and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

The lack of availability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploitation and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there has been a shortage of drilling rigs, equipment, supplies, oil field services or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. During times and in areas of increased activity, the demand for oilfield services will also likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of drilling rigs, equipment, supplies, oil field services or qualified personnel were particularly severe in any of our areas of operation, we could be materially and adversely affected. Delays could also have an adverse effect on our results of operations, including the timing of the initiation of production from new wells.

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Our drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors that are beyond our control.

Our drilling operations are subject to a number of risks, including:

• unexpected drilling conditions;

• facility or equipment failure or accidents;

• adverse weather conditions;

• title problems;

• delays due to protection from fracture stimulations of nearby wells,

• unusual or unexpected geological formations;

• fires, blowouts and explosions; and

• uncontrollable pressures or flows of oil or gas or well fluids.

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

We do not insure against all potential operating risks. We might incur substantial losses from, and be subject to substantial liability claims for, uninsured or underinsured risks related to our oil and gas operations.

We do not insure against all risks. Our oil and gas exploitation and production activities are subject to hazards and risks associated with drilling for, producing and transporting oil and gas, and any of these risks can cause substantial losses resulting from:

• environmental hazards, such as uncontrollable flows of oil, gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, underground migration and surface spills or mishandling of chemical additives;

• abnormally pressured formations;

• mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

• leaks of gas, oil, condensate, NGL and other hydrocarbons or losses of these hydrocarbons as a result of accidents during drilling and completion operations, or in the gathering and transportation of hydrocarbons, malfunctions of pipelines, measurement equipment or processing or other facilities in the Company’s operations or at delivery points to third parties;

• fires and explosions;

• personal injuries and death;

• regulatory investigations and penalties; and

• natural disasters.

We might elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities arising from uninsured and underinsured events or in amounts in excess of existing insurance coverage could have a material adverse effect on our business, financial condition or results of operations.

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Hydraulic fracturing, the process used for extracting oil and gas from shale and other formations, could be the subject of further regulation that could impact the timing and cost of development.

Hydraulic fracturing is the primary completion method used to extract reserves located in many of the unconventional oil and gas plays. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure, usually down tubing or casing that is cemented in the wellbore, into hydrocarbon-bearing formations at depth to stimulate oil and gas production. We use this completion technique on substantially all of our wells. Depending on the legislation that may ultimately be enacted or the regulations that may be adopted at the federal and state levels, exploration, exploitation and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements. Some states in which we operate, including Texas, have implemented disclosure requirements related to chemicals used in hydraulic fracturing, and while the BLM has rescinded its rules governing hydraulic fracturing on federal and tribal lands (which action itself is subject to pending litigation), we anticipate further regulation of hydraulic fracturing and related activities by states and local governments. Individually or collectively, such existing and new legislation or regulation could lead to operational delays or increased operating costs and could result in additional burdens that could increase the costs and delay the development of unconventional oil and gas resources from formations which are not commercial without the use of hydraulic fracturing. This could have an adverse effect on our business, financial condition and results of operations.

Hydraulic fracturing is typically regulated by state oil and gas commissions; however, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel fuels under the Underground Injection Control Program established under the Safe Drinking Water Act, or SDWA, and published permitting guidance and an interpretive memorandum addressing the performance of such activities.   In addition, the U.S. Congress, from time to time, has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In the event that a new federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we currently or in the future plan to operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development or production activities.

Certain states in which we operate, including Texas, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosures, and/or well-construction requirements on hydraulic-fracturing operations.    In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. In some states, including Texas, water use may also be regulated and potentially curtailed by local groundwater management districts which could impact water available for hydraulic fracturing. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities.  Nonetheless, in the event state or local restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves.

See “Item 1. Business – Environmental Matters – Hydraulic Fracturing” above for additional discussion related to environmental risks associated with our hydraulic fracturing activities.

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

Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. Over the past few years, extreme drought conditions persisted in West and South Texas. Although conditions have improved, we cannot guarantee what conditions may occur in the future. Severe drought conditions can result in local water districts taking steps to restrict the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If we are unable to obtain water to use in our operations from local resources, we may be unable to economically produce oil and gas, which could have an adverse effect on our financial condition, results of operations and cash flows from operations.

Studies noting a connection between increased seismic activity and the injection of wastewater from oil and gas operations could result in new laws or regulations which would increase our cost of operations.

Some studies have noted an increase in localized frequency of seismic activity associated with underground injection wastewater from oil and gas operations. If the results of these studies are confirmed, new legislative and regulatory initiatives could require additional monitoring, restrict the injection of produced water in certain disposal wells or modify or curtail hydraulic fracturing operations. These actions could lead to operational delays, increased compliance costs or otherwise adversely impact our operations.

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We face various risks associated with the trend toward increased anti-development activity.

As new technologies have been applied to our industry, we have seen significant growth in oil and gas supply in recent years, particularly in the U.S. With this expansion of oil and gas development activity, opposition toward oil and gas drilling and development activity has been growing both in the U.S. and globally. Companies in the oil and gas industry, such as us, can be the target of opposition to development from certain stakeholder groups. These anti-development efforts could be focused on:

• limiting oil and gas development;

• reducing access to federal and state owned lands;

• delaying or canceling certain projects such as offshore drilling, shale development, and pipeline construction;

• limiting or banning the use of hydraulic fracturing;

• denying air-quality permits for drilling; and

• advocating for increased regulations on shale drilling and hydraulic fracturing.

Future anti-development efforts could result in the following:

• blocked development;

• denial or delay of drilling permits;

• shortening of lease terms or reduction in lease size;

• restrictions on installation or operation of gathering or processing facilities;

• restrictions on the use of certain operating practices, such as hydraulic fracturing;

• reduced access to water supplies or restrictions on water disposal;

• reduce access to sand, or other proppants, required for hydraulic fracturing;

• limited access or damage to or destruction of our property;

• legal challenges or lawsuits;

• increased regulation of our business;

• damaging publicity and reputational harm;

• increased costs of doing business;

• reduction in demand for our products; and

• other adverse effects on our ability to develop our properties and expand production.

Costs associated with responding to these initiatives or complying with any new legal or regulatory requirements resulting from these activities could be substantial and not adequately provided for, could have a material adverse effect on our business, financial condition and results of operations. In addition, the use of social media channels can be used to cause rapid, widespread reputational harm.

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The adoption of derivatives legislation and regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.  

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act establishes federal oversight and regulation of over-the-counter, or OTC, derivatives and requires the Commodity Futures Trading Commission, or CFTC, and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In one of its rulemaking proceedings still pending under the Dodd-Frank Act, on November 5, 2013 (as modified and re-proposed on December 30, 2016), the CFTC approved a proposed rule imposing position limits for certain futures and option contracts in various commodities (including gas) and for swaps that are their economic equivalents. Certain specified types of hedging transactions are proposed to be exempt from these position limits, provided that such hedging transactions satisfy the CFTC’s requirements for “bona fide hedging” transactions or positions. Similarly, on December 16, 2016, the CFTC issued a proposed rule regarding the capital that a swap dealer, or major swap participant, is required to post with respect to its swap business, but has not yet issued a final rule. On January 6, 2016, the CFTC issued a final rule on margin requirements for uncleared swap transactions, which includes an exemption for commercial end-users, entering into uncleared swaps in order to hedge commercial risks affecting their business, from any requirement to post margin to secure such swap transactions. In addition, on July 19, 2012, the CFTC issued a final rule authorizing an exception for commercial end-users using swaps to hedge their commercial risks from the otherwise applicable mandatory obligation under the Dodd-Frank Act to clear all swap transactions through a registered derivatives clearing organization and to trade all such swaps on a registered exchange. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. All of the above regulations and requirements could increase the costs to us of entering into, and lessen the availability of, derivative contracts to hedge or mitigate our exposure to volatility in oil, gas and NGL prices and other commercial risks affecting our business.

It is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements. Moreover, our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks may affect whether we are required to comply with margin and certain clearing and trade-execution requirements in connection with our derivative activities. If we do not qualify for the commercial end-user exception, we may be required to post margin or clear certain transactions, which could reduce our liquidity and cash available for capital expenditures and our ability to hedge may be impacted. When a final rule on capital requirements is issued, the Dodd-Frank Act may require our current swap counterparties to post additional capital as a result of entering into uncleared derivatives with us, which could increase the costs to us of entering into, and lessen the availability of us to, derivative contracts. The Dodd-Frank Act may also require our current counterparties to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers. These changes could reduce the liquidity of the derivatives markets thereby reducing the ability of commercial end-users to have access to derivative contracts to hedge or mitigate their exposure to volatility in oil, gas, and NGL prices. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes), materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated derivative contracts, and reduce the availability of derivatives to protect us against commercial risks we encounter.

In addition, federal banking regulators have adopted new capital requirements for certain regulated financial institutions in connection with the Basel III Accord. The Federal Reserve Board also issued proposed regulations on September 30, 2016, proposing to impose higher risk-weighted capital requirements on financial institutions active in physical commodities, such as oil and gas. If and when these proposed regulations are fully implemented, financial institutions subject to these higher capital requirements may require that we provide cash or other collateral with respect to our obligations under the financial derivatives and other contracts we may enter into with such financial institutions in order to reduce the amount of capital such financial institutions may have to maintain. Alternatively, financial institutions subject to these capital requirements may price transactions so that we will have to pay a premium to enter into derivatives and other physical commodity transactions in an amount that will compensate the financial institutions for the additional capital costs relating to such derivatives and physical commodity transactions. Rules implementing the Basel III Accord and higher risk-weighted capital requirements could materially reduce our liquidity and increase the cost of derivative contracts and other physical commodity contracts (including through requirements to post collateral, which could adversely affect our available capital for other commercial operations purposes). In addition, certain foreign jurisdictions may adopt or implement laws and regulations relating to margin and central clearing requirements, which in each case may affect our counterparties and the derivatives markets generally.

If we reduce our use of derivative contracts as a result of any of the foregoing regulations or requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, gas, and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, gas, and NGL. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations, or cash flows from operations.

If we were to experience an ownership change, we could be limited in our ability to use net operating losses arising prior to the ownership change to offset future taxable income. In addition, our ability to use net operating loss carry forwards to reduce future tax payments may be limited if our taxable income does not reach sufficient levels.

As of December 31, 2020, we had pre 2018 net operating loss carryforwards or NOLs, for federal income tax purposes of $245.2 million and post 2018 NOLs of $140.0 million. If we were to experience an "ownership change," as determined under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"), our ability to offset taxable income arising after the ownership change with NOLs arising prior to the ownership change would be limited, possibly substantially. An ownership change would establish an annual limitation on the amount of our pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more "5% shareholders" (as defined in the Code) at any time during a rolling three-year period.

As a result of the Tax Cuts and Jobs Act of 2017, and The Coronavirus Aid, Relief, and Economic Security Act of 2020, NOLs  arising before January 1, 2018, and NOLs arising after January 1, 2018, are subject to different rules. Our pre-2018 NOLs will expire in varying amounts from 2023 through 2037, if not utilized; and can offset 100% of future taxable income for regular tax purposes. Our NOLs arising in 2018, 2019 and 2020 can generally be carried back five years, carried forward indefinitely and can offset 100% of future taxable income for tax years before January 1, 2021 and up to 80% of future taxable income for tax years after December 31, 2020. Any NOLs arising on or after January 1, 2021, cannot be carried back, can generally be carried forward indefinitely and can offset up to 80% of future taxable income. Our ability to use our NOLs during this period will be dependent on our ability to generate taxable income, and the NOLs could expire before we generate sufficient taxable income.

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Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities.  We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners.  Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations.  In addition, computer technology controls nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market.  A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.

While we have not experienced significant cyber-attacks, we may suffer such-attacks in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

We rely on independent experts and technical or operational service providers over whom we may have limited control.

We use independent contractors to provide us with certain technical assistance and services.  We rely upon the owners and operators of rigs and drilling equipment, and upon providers of field services, to drill and develop our prospects to production.  We also rely upon the services of other third parties to explore and/or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner.  Our limited control over the activities and business practices of these service providers, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially adversely affect our business, results of operations and financial condition.

We depend on our President, CEO and Chairman of the Board and the loss of his services could have an adverse effect on our operations.

We depend to a large extent on Robert L.G. Watson, our President and Chief Executive Officer, for our management, business and financial contacts.  Mr. Watson may terminate his employment agreement with us at any time on 30 days' notice, but, if he terminates without good reason, he would not be entitled to the severance benefits provided under the terms of that agreement.  Mr. Watson is not precluded from working for, with or on behalf of a competitor upon termination of his employment with us.  If Mr. Watson were no longer able or willing to act as President, Chief Executive Officer and Chairman of the Board, the loss of his services could have an adverse effect on our operations.

Risks Related to Our Industry

Market conditions for oil and gas, and particularly volatility of prices for oil and gas, could adversely affect our revenue, cash flows from operations, profitability and growth.

Our revenue, cash flows from operations, profitability and future rate of growth depend substantially upon prevailing prices for oil and gas.  Prices also affect the amount of cash flows available for capital expenditures and our ability to borrow money or raise additional capital.  Lower prices may also make it uneconomical for us to increase or even continue current production levels of oil and gas.  At the beginning of 2019, OPEC members and some nonmembers, including Russia, renewed pledges to reduce planned production in an effort to draw down a global oversupply and to rebalance supply and demand. As a result of a decrease in global demand for oil and natural gas due to the recent coronavirus outbreak, at the beginning of March 2020, negotiations to extend this pledge were unsuccessful. As a result, Saudi Arabia announced a significant reduction in its export prices and Russia announced that all agreed oil production cuts between members of OPEC and Russia would expire on April 1, 2020. Following these announcements, global oil and natural gas prices declined sharply and may continue to decline. Subsequently further negotiations in April 2020 resulted in an agreement to reduce production volumes in an effort to stabilize global oil prices. While prices have recovered from the lows in March 2020, they remain at depressed levels.  We expect ongoing oil price volatility as supply increases over the short term as a result of Saudi Arabia and Russia’s actions.

Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and gas, market uncertainty and a variety of other factors beyond our control, including:

• changes in foreign and domestic supply and demand for oil and gas;

• political stability and economic conditions in oil producing countries, particularly in the Middle East, including Saudi Arabia and Russia;

• weather conditions;

• global or national health concerns, including the outbreak of pandemic or contagious disease;

• price and level of foreign imports;

• terrorist activity;

• availability of pipeline and other secondary capacity;

• general economic conditions;

• domestic and foreign governmental regulation; and

• the price and availability of alternative fuel sources.

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Events beyond our control, including a global or domestic health crisis, may result in unexpected adverse operating and financial results.   In response to the COVID-19 pandemic governments around the world, including U.S. federal, state, and local governments, have imposed restrictions intended to limit the extent and spread of the virus, including travel restrictions, quarantines and business closures. These and other actions could, among other things, impact the ability of our employees and contractors to perform their duties, cause increased technology and security risk due to extended and company-wide telecommuting and lead to disruptions in our permitting activities and critical business relationships. Additionally, the COVID-19 outbreak and governmental restrictions have significantly impacted economic activity and markets and have dramatically reduced current and anticipated demand for oil and natural gas, adversely impacting the prices we receive for our production. The severity and duration of the current COVID-19 outbreak and the potential for future outbreaks are uncertain and difficult to predict. COVID-19 or another similar outbreak may negatively impact our business in numerous ways, including, but not limited to, the following:    

• reducing our revenues if the outbreak results in a substantial or prolonged decrease in demand for oil and natural gas due to an economic downturn or recession;

• disrupting our operations if our employees or contractors are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to measures designed to contain the outbreak; 

• disrupting the operations of our midstream service providers, on whom we rely for the gathering, processing and transportation of our production, due to measures designed to contain the outbreak, and/or the difficult economic environment may lead to capital spending constraints, bankruptcy, the closing of facilities or inability to maintain infrastructure, which may adversely affect our ability to market our production, increase our costs, lower the prices we receive, or result in the shut-in of our producing wells or a delay or discontinuation of our development plans; and

• the disruption and instability in the financial markets and the uncertainty in the general business environment may affect our ability to access capital, monetize assets and successfully execute our plans.

  The COVID-19 pandemic may also have the effect of heightening many of the other risks set forth in this Item 1A, “Risk Factors”. Any of these factors could have a material adverse effect on our business, operations, financial results and liquidity. Recently, oil and natural gas have declined to historically low levels and we have reduced our planned capital expenditures, delayed our drilling and completion plans and have begun shutting-in most of our producing wells, among other responses. We are unable to predict the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments, including the length of time that the pandemic continues, its ongoing effect on the demand for oil and natural gas and the response of the overall economy and the financial markets after governmental restrictions are eased.
 

Estimates of proved reserves and future net revenue are inherently imprecise.

The process of estimating oil and gas reserves in accordance with SEC requirements is complex and involves decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data.  Accordingly, these estimates are imprecise.  Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated.  Any significant variance could materially affect the estimated quantities and present value of our reserves.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.

The estimates of our reserves as of December 31, 2020 are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time.  In particular, estimates of oil and gas reserves, future net revenue from proved reserves and the present value of our oil and gas properties are based on the assumption that future oil and gas prices remain the same as the twelve month first-day-of-the-month average oil and gas prices for the year ended December 31, 2020.  The average realized sales prices used for purposes of such estimates were $39.54 per Bbl of oil and $2.03 per Mcf of gas. The December 31, 2020 estimates also assume that we will make future capital expenditures of approximately$6.3 million in the aggregate primarily from 2020 through 2024, which are necessary to develop and realize the value of proved reserves on our properties.  We cannot assure you that we will have sufficient capital in the future to make these capital expenditures. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of our reserves set forth or incorporated by reference in this report.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves.  Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

As required by SEC regulations, we based the estimated discounted future net cash flows from our proved reserves as of December 31, 2020 on the twelve month first-day-of-the-month average oil and gas prices for the year ended December 31, 2020 and costs in effect on December 31, 2020, the date of the estimate.  However, actual future net cash flows from our properties will be affected by factors such as:

• supply of and demand for our oil and gas;

• actual prices we receive for our oil and gas;

• our actual operating costs;

• the amount and timing of our capital expenditures;

• the amount and timing of our actual production; and

• changes in governmental regulations or taxation.

In addition, the 10% discount factor we use when calculating discounted future net cash flows, which is required by the SEC, 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.  Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

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Our operations are subject to the numerous risks of oil and gas drilling and production activities.

Our oil and gas drilling and production activities are subject to numerous risks, many of which are beyond our control.  These risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards.  Environmental hazards include oil and saltwater spills, gas leaks, ruptures, discharges of toxic gases, underground migration and surface spills or mishandling of any toxic fracture fluids, including chemical additives.  In addition, title problems, weather conditions and mechanical difficulties or shortages or delays in delivery of drilling rigs and other equipment could negatively affect our operations.  If any of these or other similar industry operating risks occur, we could have substantial losses.  Substantial losses also may result from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, environmental damage, regulatory investigation and penalties and suspension of operations.  In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above.  We cannot assure you that our insurance will be adequate to cover losses or liabilities.  Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase.

We operate in a highly competitive industry which may adversely affect our operations.

We operate in a highly competitive environment.  The principal resources necessary for the exploration and production of oil and gas are leasehold prospects under which oil and gas reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to conduct all phases of operations.  We must compete for such resources with both major oil and gas companies and independent operators.  Many of these competitors have financial and other resources substantially greater than ours.  Although we believe our current operating and financial resources are adequate to preclude any significant disruption of our operations, we cannot assure you that such resources will be available to us in the future.

Our oil and gas operations are subject to various U.S. federal, state and local regulations that materially affect our operations.

In the oil and gas industry, matters regulated include permits for drilling and completion operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells and unitization and pooling of properties, the disposal of wastes and taxation.  At various times, regulatory agencies have imposed price controls and limitations on production.  In order to conserve supplies of oil and gas, these agencies have at times restricted the rates of flow from oil and gas wells below actual production capacity.  U.S. federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and gas by-products and other substances and materials produced or used in connection with oil and gas operations.  To date, our expenditures related to complying with these laws and for remediation of existing environmental contamination have not been significant.  We believe that we are in substantial compliance with all applicable laws and regulations.  However, the requirements of such laws and regulations are frequently changed.  We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.

Recently enacted federal legislation will affect our tax position concerning tax deductions currently available with respect to oil and gas drilling may adversely affect our net earnings.

In December 2017, Congress enacted the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act, or TCJA. The law made significant changes to U.S. federal income tax laws, including reducing the corporate income tax rate from 35 percent to 21 percent, repealing the corporate alternative minimum tax, or AMT, partially limiting the deductibility of interest expense and NOLs, eliminating the deduction for certain U.S. production activities and allowing the immediate deduction of certain new investments in lieu of depreciation expense over time. Many aspects of the TCJA are unclear and may not be clarified for some time.

Congress has recently considered, is considering, and may continue to consider, legislation that, if adopted in its proposed or similar form, would deprive some companies involved in oil and gas exploration and production activities in certain U.S. federal income tax incentives and deductions currently available to such companies.  These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective and whether such changes may apply retroactively.  Although we are unable to predict whether any of these or other proposals will ultimately be enacted, the passage of any legislation as a result of these proposals or any other similar changes to U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available to us, and any such change could negatively affect our financial condition and results of operations.

27

Climate change and regulations related to GHGs could have an adverse effect on our operations and on the demand for oil and gas.

Scientific studies have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. Domestically, the Fourth National Climate Assessment report, released in November 2018, noted that climate change is mostly driven by GHG emissions and that climate change is accelerating. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, gas, and refined petroleum products, are considered GHGs. We expect continuing debate, especially in the political arena, over how to address climate change and what policies and regulations are necessary to address the issue. In response to various scientific studies, governments have begun adopting domestic and international climate change regulations that require reporting and reduction of emissions of GHGs. It is possible that international efforts spear-headed by the United Nations and subsequent domestic and international regulations will have adverse effects on the market for oil, gas and other fossil fuel products as well as adverse effects on the business and operations of companies engaged in the exploration for, and production of, oil, gas and other fossil fuel products. In the United States, at the state level and local level, several states and localities, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of GHGs. At the federal level, various climate change legislative measures have been considered by the U.S. Congress, but it is not possible at this time to predict when, or if, Congress will act on climate change legislation, although any major initiatives in this area are unlikely to become law in the near future due to opposition in Congress. We are unable to predict the timing, scope and effect of any currently proposed or future investigations, laws, regulations or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such investigations, laws, regulations and treaties (if enacted) could materially and adversely affect our operations, financial condition and results of operations.

Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and gas that we produce and, as a result, our financial condition and results of operations could be adversely affected.

In addition, local weather effects associated with climate change, including more severe rainfall events, more intense storms, flooding, or droughts could adversely affect our facilities or the scheduling of deliveries or the cost of supplies needed to run our business.

EPA’s ground-level ozone standards may result in more stringent regulation of air emissions from, and adverse economic impacts on, our operations.

Effective December 2015, the EPA adopted a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (NAAQS) for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards designed to provide protection of public health and welfare, respectively.  EPA has now issued new area designations with respect to ground-level ozone, and in November 2018 EPA issued final requirements for implementation that apply to state and local agencies. Areas of the country that have been reclassified so that they are no longer in attainment with the 2015 standard will be more costly and difficult for operators to construct new or modified sources of air pollution, including those associated with our operations. Moreover, such reclassified areas more stringent regulations may require among other things, installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs.

Proposed legislation and regulation under consideration regarding rail transportation could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business.

We presently sell all of our oil production at the lease, either by truck or pipeline, where custody transfers to the purchaser, accordingly it is unknown to us how much of the oil production is ultimately shipped by rail. In response to recent train derailments occurring in the United States, U.S. regulators are implementing or considering new rules to address the safety risks of transporting oil by rail. On January 23, 2014, the NTSB issued a series of recommendations to address safety risks, including (i) requiring expanded hazardous material route planning for railroads to avoid populated and other sensitive areas, (ii) developing an audit program to ensure rail carriers that carry petroleum products have adequate response capabilities to address worst-case discharges of the entire quantity of product carried on a train, and (iii) auditing shippers and rail carriers to ensure they are properly classifying hazardous materials in transportation and that they have adequate safety and security plans in place. Additionally, on February 25, 2014 the DOT issued an emergency order requiring all persons, prior to offering oil into transportation, to ensure such product is properly tested and classed and to assure all shipments by rail of oil be handled as a Packing Group I or II hazardous material. The introduction of these or other regulations that result in new requirements addressing the type, design, specifications or construction of rail cars used to transport oil could result in severe transportation capacity constraints during the period in which new rail cars are retrofitted or constructed to meet new specifications.

We do not currently own or operate rail transportation facilities or rail cars; however, the adoption of any regulations that impact the testing or rail transportation of oil could increase our costs of doing business and limit our ability to transport and sell our oil at favorable prices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows from operations.

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Risks Related to Our Common Stock

Future issuance of additional shares of common stock could cause dilution of ownership interests and adversely affect our stock price.

We are currently authorized to issue 20,000,000 shares of common stock with such rights as determined by our board of directors.  In the future, we may increase our authorized shares of common stock or issue previously authorized and unissued securities, resulting in the dilution of the ownership interests of current stockholders.  The potential issuance of any such additional shares of common stock may create downward pressure on the trading price of our common stock.  We may also issue additional shares of common stock or other securities that are convertible into or exercisable for common stock for capital raising or other business purposes.  Future sales of substantial amounts of common stock, or the perception that sales could occur, could have a material adverse effect on the price of our common stock.

We will not pay dividends on our common stock for the foreseeable future.

We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future.  In addition, our credit facilities prohibit us from paying dividends and making other cash distributions.

Shares eligible for future sale may depress our stock price.

At December 31, 2020, we had 8,421,910 shares of common stock outstanding of which 208,020 shares were held by affiliates and, in addition, 194,695 shares of common stock were subject to outstanding options granted under stock option plans (of which 192,096 shares were vested at December 31, 2020).

All of the shares of common stock held by affiliates are restricted or are control securities under Rule 144 promulgated under the Securities Act.  The shares of common stock issuable upon exercise of stock options have been registered under the Securities Act.  Sales of shares of common stock under Rule 144 or another exemption under the Securities Act or pursuant to a registration statement could have a material adverse effect on the price of our common stock and could impair our ability to raise additional capital through the sale of equity securities.

The price of our common stock has been volatile and could continue to fluctuate substantially.

Our common stock is traded on The Nasdaq Stock Market (the "Nasdaq").  The market price of our common stock has been volatile and could fluctuate substantially based on a variety of factors, including the following:

• fluctuations in commodity prices;

• variations in results of operations;

• legislative or regulatory changes;

• general trends in the oil and gas industry;

• sales of common stock or other actions by our stockholders;

• additions or departures of key management personnel;

• commencement of or involvement in litigation;

• speculation in the press or investment community regarding our business;

• an inability to maintain the listing of our common stock on a national securities exchange;

• market conditions; and

• analysts’ estimates and other events in the oil and gas industry.

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

Subject to the rules of The NASDAQ Stock Market, our articles of incorporation authorize our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from holders of our common stock.  Any preferred stock that is issued may rank ahead of our common stock in terms of dividends, priority and liquidation premiums and may have greater voting rights than our common stock.  

Anti-takeover provisions could make a third party acquisition of us difficult.

Our articles of incorporation and bylaws provide for a classified board of directors, with each member serving a three-year term, and eliminate the ability of stockholders to call special meetings or take action by written consent.  Each of the provisions in our articles of incorporation and bylaws could make it more difficult for a third party to acquire us without the approval of our board.  In addition, the Nevada corporate statute also contains certain provisions that could make an acquisition by a third party more difficult.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Exploratory and Developmental Acreage

Our principal oil and gas properties consist of producing and non-producing oil and gas leases, including reserves of oil and gas in place. The following table sets forth our developed and undeveloped acreage and fee mineral acreage as of December 31, 2020.

	Developed Acreage				Undeveloped Acreage				Fee Mineral Acreage (1)
	Gross Acres		Net Acres		Gross Acres		Net Acres		Gross Acres		Net Acres		Total Net Acres (2)
Permian/Delaware Basin		18,242		13,868		13,196		8,792		9,556		2,391		25,051
Rocky Mountain		20,778		11,509		9,185		5,235		2,078		106		16,850
Total		39,020		25,377		22,381		14,027		11,634		2,497		41,901

(1) Fee mineral acreage represents fee simple absolute ownership of the mineral estate or fraction thereof.

(2) Includes 640 net acres in the Permian Basin region that are included in both developed and fee mineral acres.

The following table sets forth Abraxas’ net undeveloped acreage subject to expiration by year:

	2021		2022		2023		2024		2025
Permian/Delaware Basin		593		-		-		-		-
Rocky Mountain		-		-		-		-		-
Total		593		-		-		-		-

Productive Wells

The following table sets forth our gross and net productive wells, expressed separately for oil and gas, as of December 31, 2020: 

	Productive Wells
	Oil				Gas
	Gross		Net		Gross		Net
Permian/Delaware Basin		57.0		48.2		46.0		33.6
Rocky Mountain		149.0		68.1		319.0		6.9
		206.0		116.3		365.0		40.5

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Reserves Information

The estimation and disclosure requirements we employ conform to the definition of proved reserves with the Modernization of Oil and Gas Reporting rules, which were issued by the SEC in 2008. This accounting standard requires that the average first-day-of-the-month price during the 12-month period preceding the end of the year be used when estimating reserve quantities and permits the use of reliable technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes.

The Company’s proved oil and gas reserves have been estimated by an independent petroleum engineering firm, DeGolyer & MacNaughton, as of December 31, 2019 and 2020, assisted by the engineering and operations departments of the Company. For the year ended December 31, 2020, DeGolyer & MacNaughton, of Dallas, Texas estimated reserves for our properties comprising approximately 93% of the PV-10 of our proved oil and gas reserves. Proved reserves for the remaining 7% of our properties  were estimated by Abraxas personnel because we determined that it was not practical for DeGolyer & MacNaughton to prepare reserves estimates for these properties as they are located in a widely dispersed geographic area and have relatively low value. DeGolyer & MacNaughton's reserve report as of December 31, 2020 included a total of 125 properties and our internal report included 121 properties.

The technical personnel responsible for preparing the reserve estimates at DeGolyer & MacNaughton meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer & MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists. They do not own an interest in any of our properties and are not employed on a contingent fee basis. All reports by DeGolyer & MacNaughton were developed utilizing their own geological and engineering data, supplemented by data provided by Abraxas.  The report of DeGolyer & MacNaughton, dated February 12, 2021, which contains further discussions of the reserve estimates and evaluations prepared by DeGolyer & MacNaughton as well as the qualifications of DeGolyer & MacNaughton’s technical personnel responsible for overseeing such estimates and evaluations is attached as Exhibit 99.1 to this report.

Estimates of reserves at December 31, 2020 were assisted by the engineering department of Abraxas which is directly responsible for Abraxas’ reserve evaluation process.  The Vice President of Engineering manages this department and is the primary technical person responsible for this process.  The Vice President of Engineering holds a Bachelor of Science degree in Petroleum Engineering and is a Registered Professional Engineer in the State of Texas; he has 42 years of experience in reserve evaluations. The operations department of Abraxas also assisted in the process. Reserve information as well as models used to estimate such reserves are stored on secured databases.  Non-technical inputs used in reserve estimation models, including oil and gas prices, production costs, future capital expenditures and Abraxas’ net ownership percentages, were obtained from other departments within Abraxas.

Oil and gas reserves and the estimates of the present value of future net revenues therefrom were determined based on prices and costs as prescribed by SEC and Financial Accounting Standards Board, or FASB, guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future net revenues to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods.  Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations or de-escalations except by contractual arrangements. For the year ended December 31, 2020, commodity prices over the prior 12-month period and year end costs were used in estimating future net cash flows.

The following table sets forth certain information regarding estimates of our oil and gas reserves as of December 31, 2020. All of our reserves are located in the United States. 

Summary of Oil, NGL and Gas Reserves
As of December 31, 2020
Reserve Category	Oil (MBbls)		NGL (MBbls)		Gas (MMcf)		Oil equivalents (MBoe)
Proved
Developed		9,537		3,187		24,318		16,778
Undeveloped		-		-		-		-
Total Proved		9,537		3,187		24,318		16,778

As of December 31, 2020, we did not recognize any proved undeveloped reserves. During 2020, our proved undeveloped reserves are excluded from our total proved reserves primarily due to capital constraints, as a result of the uncertainty of  the Company to continuing as a "going concern" as described in Item 1. Going Concern.

Our estimates of proved developed reserves, proved undeveloped reserves, and total proved reserves at December 31, 2019 and 2020, and changes in proved reserves during the last two years are presented in the Supplemental Oil and Gas Disclosures under Item 8 of this report.  Also presented in the Supplemental Information are our estimates of future net cash flows and discounted future net cash flows from proved reserves.

We have not filed information with a federal authority or agency with respect to our estimated total proved reserves at December 31, 2020. We report gross proved reserves of operated properties in the United States to the U.S. Department of Energy on an annual basis; these reported reserves are derived from the same data used to estimate and report proved reserves in this report.

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The process of estimating oil and gas reserves is complex and involves decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data.  Accordingly, these estimates are imprecise.  Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated.  Any significant variance could materially affect the estimated quantities and present value of our reserves set forth or incorporated by reference in this report.  We may also adjust estimates of reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. In particular, estimates of oil and gas reserves, future net revenue from reserves and the PV-10 thereof for the oil and gas properties described in this report are based on the assumption that future oil and gas prices remain the same as oil and gas prices utilized in the December 31, 2020 report. The average realized sales prices used for purposes of such estimates were $39.54 per Bbl of oil and $2.03 per Mcf of gas. It is also assumed that we will make future capital expenditures of approximately $6.3 million in the aggregate primarily in the years 2020 through 2024, which are necessary to develop and realize the value of proved reserves on our properties. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of reserves set forth herein.

You should not assume that the present value of future net revenues referred to in this report is the current market value of our estimated oil and gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are calculated using the average first-day-of-the-month price over the prior 12-month period.  Costs used in the estimated discounted future net cash flows are costs as of the end of the period. Because we use the full cost method to account for our oil and gas operations, we are susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. This is known as a “ceiling limitation write-down.” This charge does not impact cash flows from operating activities but does reduce our stockholders’ equity and reported earnings. We have experienced ceiling limitation write-downs in the past and we cannot assure you that we will not experience additional ceiling limitation write-downs in the future. As of December 31, 2020, the Company’s net capitalized costs of oil and gas properties exceeded the present value of our estimated proved reserves by $187.0 million, resulting in the recording of a proved property impairment of $187.0 million. As of December 31, 2019, the Company’s net capitalized costs of oil and gas properties  exceeded the present value of our estimated proved reserves by $51.3 million, resulting in the recording of a proved property impairment of $51.3 million. If commodity prices decrease, we could be required to further write down the carrying value of our reserves in the future.

For more information regarding the full cost method of accounting, you should read the information under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies.”

Actual future prices and costs may be materially higher or lower than the prices and costs used in the reserve report. Any changes in consumption by gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. Our effective interest rate on borrowings at various times and the risks associated with us or the oil and gas industry in general will affect the accuracy of the 10% discount factor.

Proved Undeveloped Reserves

Changes in PUDs. Significant changes to PUDs that occurred during 2020 are summarized in the table below.  As a result of the uncertainty that we can continue as a "going concern" we are not recognizing any proved undeveloped reserves as of    December 31, 2020.

The following is a summary of the changes to the Company's proved undeveloped reserves that occurred during 2020: 

	MBoe
PUDs at December 31, 2019		39,125
Revisions of prior estimates		(1,413	)
Extensions, discoveries, and other additions		-
Conversion to developed		-
Conversion to probable		(25,054	)
Other (1)		(12,658	)
PUDs at December 31, 2020		-

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(1) At December 31, 2020  all proved undeveloped reserves were removed from our total proved reserves. This was primarily due to  the uncertainty of the Company remaining a "going concern" and  the availability of capital for developing those reserves. 

The following is additional information regarding the changes to the Company’s proved undeveloped reserves that occurred during 2020.

Revisions of prior estimates: 

A decrease of 1,413 MBoe of net reserves was attributed to decreased economic life calculations at the lower commodity pricing experienced during 2020.

Extensions, discoveries and other additions: 

The Company did not add any new proved undeveloped locations during 2020 due to either extensions or discoveries. Also, the Company did not convert any probable undeveloped to proved undeveloped reserves during 2020.

Conversion to developed:

The Company did not convert any proved undeveloped to proved developed reserves during 2020.

Conversion to probable:

The Company converted 29 proved undeveloped Wolfcamp A1 locations, and 25 3rd Bone Spring locations in Ward County, Texas, to probable undeveloped reserves during 2020 accounting for 17,601 MBoe of net reserves.  The Company converted five proved undeveloped Middle Bakken locations and nine Three Forks locations in McKenzie County, North Dakota, to probable undeveloped reserves during 2020 accounting for 5,153 MBoe of net reserves.  The Company converted two proved undeveloped Delaware Montoya locations in Ward County, Texas, to probable undeveloped reserves during 2020 accounting for 2,300 MBoe of net reserves.  All these locations are no longer included in the Company’s five-year development schedule.

Sold:

The Company did not sell any proved undeveloped locations during 2020.

Reconciliation of Standardized Measure to PV-10

PV-10 is the estimated present value of the future net revenues from our proved oil and gas reserves before income taxes discounted using a 10% discount rate. PV-10 is considered a non-GAAP financial measure under SEC regulations 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. We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and gas properties and that PV-10 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, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes.

The following table provides a reconciliation of the standardized measure of discounted future net cash flows to PV-10 at December 31, 2019 and 2020:

	December 31,
	2019		2020
	(In thousands)
Standardized measure of discounted future net cash flows	$	307,612	$	106,684
Present value of future income taxes discounted at 10%		-		-
PV-10	$	307,612	$	106,684

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Oil and Gas Production, Sales Prices and Production Costs

The following table presents our net oil, gas and NGL production, the average sales price per Bbl of oil and NGL and per Mcf of gas produced and the average cost of production per Boe of production sold, for the two years ended December 31, by our major operating regions:

	Years Ended December 31,
	2019		2020
Oil Production (Bbl)
Permian		985,600		596,680
Rocky Mountain		1,348,192		536,032
South Texas		53,935		-
Total		2,387,727		1,132,712
Gas Production (Mcf)
Permian		1,380,003		689,684
Rocky Mountain		2,400,193		1,444,753
South Texas		296,273		-
Total		4,076,469		2,134,437
NGL Production (Bbl)
Permian		149,409		67,586
Rocky Mountain		398,809		245,469
South Texas		215
Total		548,433		313,055
Total Production (Boe) (1)		3,615,572		1,801,507
Average sales price per Bbl of oil (2)
Permian	$	53.56	$	38.36
Rocky Mountain	$	50.85	$	35.58
South Texas	$	58.58	$	-
Composite	$	52.14	$	37.05
Average sales price per Mcf of gas
Permian	$	0.36	$	0.49
Rocky Mountain	$	0.62	$	0.17
South Texas	$	2.04	$	-
Composite	$	0.63	$	0.27
Average sales price per Bbl of NGL
Permian	$	4.03	$	2.42
Rocky Mountain	$	3.27	$	1.08
South Texas	$	15.41	$	-
Composite	$	3.48	$	1.37
Average sales price per Boe (2)	$	35.68	$	23.86
Average cost of production per Boe produced (3)
Permian	$	11.33	$	12.14
Rocky Mountain	$	4.86	$	7.03
South Texas	$	17.27	$	-
Composite	$	7.66	$	9.24

(1) Oil and gas were combined by converting gas to Boe on the basis of 6 Mcf of gas to 1 Bbl of oil.

(2) Before the impact of hedging activities.

(3) Production costs include direct lease operating costs but exclude ad valorem taxes and production taxes.

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Within the above major operating regions, the Rocky Mountain and the Permian/Delaware regions represented more than 15% of our proved reserves as of December 31, 2020. The following is a summary, by product sold, for each primary field in these regions, which represented 15% or more of our total proved reserves as of December 31, 2020, for the two years ended December 31:

	Years Ended December 31,
	2019		2020
Rocky Mountain Region
Oil production (Bbls)
Bakken/Three Forks		1,298,000		509,518
Gas production (Mcf)
Bakken/Three Forks		2,360,608		1,428,355
NGL production (Bbls)
Bakken/Three Forks		397,836		244,835
Average sales price per Bbl of oil (1)
Bakken/Three Forks	$	50.89	$	35.78
Average sales price of per Mcf of gas
Bakken/Three Forks	$	0.61	$	0.17
Average sales price per Bbl of NGL
Bakken/Three Forks	$	3.26	$	1.08
Average cost of production per Boe produced (2)	$	3.82	$	5.96
Permian Region
Oil production (Bbls)		892,030		538,086
Wolfcamp
Gas Production (Mcf)		822,165		375,507
Wolfcamp
NGL production (Bbls)		126,181		55,706
Wolfcamp
Average sales price per Bbl of oil (1)	$	53.51	$	38.64
Wolfcamp
Average sales price of per Mcf of gas	$	0.24	$	0.14
Wolfcamp
Average sales price per Bbl of NGL	$	3.17	$	1.70
Wolfcamp
Average cost of production per Boe produced (2)	$	11.00	$	12.97

(1) Before the impact of hedging activities.

(2) Production costs include direct lease operating costs but exclude ad valorem taxes and production taxes.

Drilling Activities

The following table sets forth our gross and net interests in exploratory and development wells drilled and or completed during the two years ended December 31:

	2019				2020
	Gross		Net		Gross		Net
Exploratory
Productive
Permian/Delaware		-		-		-		-
Rocky Mountain		-		-		-		-
South Texas		-		-		-		-
Total		-		-		-		-
Development
Productive
Permian/Delaware		9.0		7.3		-		-
Rocky Mountain		6.0		2.4		-		-
South Texas		-		-		-		-
Total		15.0		9.7		-		-

In addition to the above drilling activity, as of December 31, 2020 we had 6.00 gross (5.4 net) operated wells in the Bakken that were drilled and uncompleted that are not represented in the above table.

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Present Activities 

Due to the drastic decline in oil prices occurring in early March 2020, we suspended any drilling and completion work indefinitely.  As a result, we have taken steps to reduce our general and administrative cost reductions, including, but not limited to, reduction of salaries for our executive officers and reductions in our work force. 

Office Facilities

Our executive and administrative offices are located at 18803 Meisner Drive, San Antonio, Texas 78258, and consist of approximately 21,000 square feet. We own the building which is subject to a real estate lien note. 

Other Properties

We own 1.5 acres of land and an office building in Ward County, Texas and an office building and lot in Niobrara County, Wyoming and 582 acres of land, with shop and office, in McKenzie County, North Dakota. We own 21 vehicles which are used in the field by employees. We also own a workover rig, which is used for servicing our wells. Raven Drilling owns a 2000 HP drilling rig, primarily used for drilling wells in the Williston Basin. In North Dakota, we own three houses and a man-camp to house rig crews.

Item 3. Legal Proceedings

From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At December 31, 2020, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on our financial condition.

Item 4. Mine Safety Disclosures

Not applicable.

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Part II

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

Market Information

Our common stock is traded on The NASDAQ Stock Market under the symbol "AXAS." The following table sets forth certain information as to the high and low sales price quoted for our common stock.

		High		Low
Period
2019
	First Quarter	$	30.00	$	20.20
	Second Quarter		31.00		19.00
	Third Quarter		22.60		8.60
	Fourth Quarter		10.40		4.40
2020	First Quarter	$	8.40	$	1.80
	Second Quarter		11.00		2.20
	Third Quarter		5.20		2.80
	Fourth Quarter		5.60		1.41
2021	First Quarter	$	4.99	$	2.23
	Second Quarter (Through April 30, 2021)		3.57		2.02

Holders

As of April 30, 2021, we had 8,421,910 shares of common stock outstanding and approximately 55 stockholders of record.

Dividends

We have not paid any cash dividends on our common stock and it is not presently determinable when, if ever, we will pay cash dividends in the future. In addition, our credit facilities prohibit the payment of cash dividends on our common stock.

Item 6. Selected Financial Data

The following selected financial data is derived from our Consolidated Financial Statements as of and for the years ended December 31, 2016 through 2020. The data should be read in conjunction with our Consolidated Financial Statements and Notes thereto and other financial information included herein. See “Financial Statements and Supplementary Data” in Item 8. All share and per share amounts reflect the retroactive treatment of the Reverse Stock Split, see Note 3 to our Consolidated Financial Statements.

	Year Ended December 31,
	2016					2017		2018		2019					2020
	(In thousands, except per share data)
Total revenue - continuing operations	$	56,555				$	86,264	$	149,167	$	129,146				$	43,043
Net (loss) income	$	(96,378	)			$	16,006	$	57,821	$	(65,004	)			$	(184,522	)
Net (loss) income from continuing operations	$	(96,378	)	(1	)	$	16,006	$	57,821	$	(65,004	)	(2	)	$	(184,522	)	(3	)
Net income (loss) from discontinued operations - net of tax	$	-				$	-	$	-	$	-				$	-
Net (loss) income per common share - diluted - continuing operations	$	(15.80	)			$	2.00	$	6.80	$	(7.80	)			$	(22.01	)
Weighted average shares outstanding - Diluted		6,107					8,142		8,384		8,315					8,382
Total assets	$	161,648				$	273,806	$	424,741	$	354,631				$	157,761
Long-term debt, excluding current maturities	$	96,616				$	87,354	$	181,942	$	192,718				$	2,515
Total stockholders' equity	$	18,505				$	106,308	$	166,510	$	103,819				$	(72,967	)

___________________________ 

(1) Includes proved property impairment of $67.6 million.

(2)	Includes proved property impairment of $51.3 million.
(3)	Includes proved property impairment of $187.0 million

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

The following is a discussion of our consolidated financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our Consolidated Financial Statements and the Notes thereto. See “Financial Statements and Supplementary Data” in Item 8.

General

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation, development and production of oil and gas in the United States. Historically, we have grown through the acquisition and subsequent development and exploitation of producing properties, principally through the redevelopment of old fields utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys and horizontal drilling. As a result of these activities, we believe that we have a number of development opportunities on our properties. In addition, we intend to expand upon our development activities with complementary acreage acquisitions in our core areas of operation. Success in our development and exploration activities is critical in the maintenance and growth of our current production levels and associated reserves.

Our financial results depend upon many factors which significantly affect our results of operations including the following:

• commodity prices and the effectiveness of our hedging arrangements;

• the level of total sales volumes of oil and gas;

• the availability of and our ability to raise additional capital resources and provide liquidity to meet cash flow needs;

• the level of and interest rates on borrowings; and

• the level and success of exploration and development activity.

Commodity Prices and Hedging Arrangements. The results of our operations are highly dependent upon the prices received for our oil and gas production. The prices we receive for our production are dependent upon spot market prices, differentials and the effectiveness of our derivative contracts, which we sometimes refer to as hedging arrangements. Substantially all of our sales of oil and gas are made in the spot market, or pursuant to contracts based on spot market prices, and not pursuant to long-term, fixed-price contracts. Accordingly, the prices received for our oil and gas production are dependent upon numerous factors beyond our control. Significant declines in prices for oil and gas could have a material adverse effect on our financial condition, results of operations, cash flows and quantities of reserves recoverable on an economic basis. 

Oil and gas prices have been volatile, and this volatility is expected to continue.  As a result of the many uncertainties associated with the world political environment, worldwide supplies of oil, NGL and gas, the availability of other worldwide energy supplies and the relative competitive relationships of various energy sources in the view of consumers, we are unable to predict what changes may occur in oil, NGL, and gas prices in the future.  The market price of oil, NGL and gas in 2021 will impact the amount of cash generated from operating activities, which will in turn impact our financial position. As of April 30, 2021, the NYMEX oil and gas price was $63.58 per Bbl of oil and $2.93 per Mcf of gas, respectively.

During 2020, the NYMEX future price for oil averaged $39.57 per barrel as compared to $57.05 per barrel in 2019 and the NYMEX future spot price for gas averaged $2.13 per Mcf compared to $2.53 per Mcf in 2019. Prices closed on December 31, 2020 at $48.52 per Bbl of oil and $2.13 per Mcf of gas.  If commodity prices decline from these levels, our revenue and cash flows from operations will also likely decline.  In addition, lower commodity prices could also reduce the amount of oil and gas that we can produce economically.  If oil and gas prices decline, our revenues, profitability and cash flows from operations will also likely decrease which could cause us to alter our business plans, including reducing our drilling activities. Such declines will require us to write down the carrying value of our oil and gas assets which will also cause a reduction in net income. 

The realized prices that we receive for our production differ from NYMEX futures and spot market prices, principally due to: 

• basis differentials which are dependent on actual delivery location;

• adjustments for BTU content;

• quality of the hydrocarbons; and

• gathering, processing and transportation costs.

The following table sets forth our average differentials for the years ended December 31,  2019 and 2020:

	Oil						Gas
	2019			2020			2019			2020
Average realized price	$	52.14		$	37.05		$	0.63		$	0.27
Average NYMEX price	$	57.05		$	39.57		$	2.53		$	2.13
Differential	$	(4.91	)	$	(2.52	)	$	(1.90	)	$	(1.86	)

_______________________

(1) Average realized prices are before the impact of hedging activities.

The Company’s derivative contracts as of December 31, 2020 and December 31, 2019 consisted of NYMEX-based fixed price swaps and basis differential swaps. Under fixed price swaps, we receive a fixed price for our production and pay a variable market price to the contract counter-party.

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As of December 31, 2020, we had NYMEX-based fixed price commodity swap arrangements, on approximately 88% of the oil production from our estimated net proved developed producing reserves (as of December 31, 2020) through December 31, 2021, 96%for 2022, 72% for 2023 and 88% for 2024. By removing a portion of price volatility on our future oil and gas production, we believe we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flows from operations for those periods.  However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flows on the portion of the production that has been hedged.  We have in the past and will in the future sustain losses on both open and settled derivative contracts if market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain realized and unrealized gains on our commodity derivative contracts. In 2020, we recorded a gain of $42.9 million, consisting of a gain of $17.5 million on closed contracts and a gain of $25.4 million related to open contracts. In 2019, we recognized a loss of $26.8 million, consisting of a loss of $6.0 million on closed contracts and a loss of $20.8 million related to open contracts. We have not designated any of these derivative contracts as a hedge as permitted by applicable accounting rules if certain conditions are met. Substantially all of our hedging contracts were terminated subsequent to March 31, 2021. See Note 14 "Subseqemt Events".

The following table sets forth our derivative contracts at December 31, 2020:

	Oil - WTI
Contract Periods	Daily Volume (Bbl)		Swap Price (per Bbl)
Fixed Swaps
January - December 2021		2,889	$	57.62
January - December 2022		2,412	$	50.60
January - December 2023		1,498	$	50.60
January - December 2024		1,585	$	50.60

At December 31, 2020, the aggregate fair market value of our commodity derivative contracts was an asset of approximately $19.4  million.

In April 2021, we received notice that certain of our hedging agreements were being terminated as a result of events of default under the First Lien Credit Facility, and we voluntarily terminated most of our other hedging arrangements. As a result of the settlement of the terminated hedges, we have outstanding obligations of $9.9 million. The settlement values of the terminated hedges were determined at various dates between April 15 and April 30, 2021. These obligations will be added to the balance of the First Lien Credit Facility and accrue interest  at the default interest rate, currently 6.7%, until repaid. Our remaining hedging agreements may also be terminated as a result of such events of default. The settlement of terminated hedging agreements may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. See Note 14 “Subsequent Events” for current information regarding non-compliance with certain covenants.

Production Volumes. Our proved reserves will decline as oil and gas is produced, unless we find, acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities.   Based on the reserve information set forth in our reserve report as of December 31, 2020, our average annual estimated decline rate for our net proved developed producing reserves is 39%,  18%, 14% , 13%  and 12% in 2021, 2022, 2023, 2024 and 2025, respectively, 9% in the following five years, and approximately 9% thereafter.   These rates of decline are estimates and actual production declines could be materially higher.  While we have had some success in finding, acquiring and developing additional reserves, we have not always been able to fully replace the production volumes lost from natural field declines and property sales. Our ability to acquire or find additional reserves in the future will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects. The decline in oil prices that occurred in March 2020, resulted in the suspension of our 2020 drilling program as well as shutting in production for some period of time. Both of these events  impacted our production volumes and will impact them going forward.

In addition to our ability to successfully drill wells, we must also market our production which depends substantially on the availability, proximity and capacity of gathering systems, pipelines and processing facilities, which are also known as midstream facilities, owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations could be adversely affected. Both of our principal areas of operation (the Bakken and Permian Basin) have experienced substantial development in recent years, and this has made it more difficult for providers of midstream infrastructure and services to keep pace with the corresponding increases in field-wide production. The ultimate timing and availability of adequate infrastructure is not within our control and we could experience capacity constraints for extended periods of time that would negatively impact our ability to meet our production targets. Weather, regulatory developments and other factors also affect the adequacy of midstream infrastructure.

We had cash capital expenditures during 2020 of approximately $12.6 million. This amount includes a decrease in the amount of capital expenditures in accounts payable of $7.2 million, resulting in accrual based capital expenditures related to 2020 of $5.4  million. Due to declines in oil prices, we suspended our planned capital expenditures for 2020. This suspension of our  capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources the results of our exploitation efforts, our financial results and our ability to obtain permits for drilling locations.

The following table presents historical net production volumes for the years ended December 31, 2019 and 2020:

	2019			2020
Total Production (Mboe)		3,616			1,801
Average daily production (Boepd)		9,906			4,922
% Oil		66	%		63	%

Availability of Capital.  As described more fully under “Liquidity and Capital Resources” below, our sources of capital are cash flows from operating activities, cash on hand, proceeds from the sale of properties, monetizing of derivative instruments, and if an appropriate opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financing on terms acceptable to us, if at all. Our credit facilities were amended in June 2020 and the  borrowing base under our First Lien Credit Facility was reduced to the then outstanding balance of $102.0 million, resulting in no additional availability, additionally, any excess cash, as defined in the First Lien Credit Facility, will be applied to the outstanding balance on a monthly basis, and the borrowing base will be reduced to the new outstanding balance.

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Borrowings and Interest.  At December 31, 2020, we had a total of $95.0  million outstanding under our First Lien Credit Facility, $112.7 million under our Second Lien Credit Facility, and total indebtedness of  $220.5 million, including a $10.0 million exit fee. As of April 30, 2021, we had a total of $89.5  million outstanding under our First Lien Credit Facility,  $127.2  million under our Second Lien Credit Facility, including a $10.0 million exit fee, and total indebtedness of $219.4 million. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements.  As a result, we would need to increase our cash flow from operations in order to fund the development of our drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices.

Exploration and Development Activity. We believe that our asset base, high degree of operational control and inventory of drilling projects position us for future growth. At December 31, 2020, we operated properties comprising approximately 97% of the Boe's of our estimated net proved reserves, giving us substantial control over the timing and incurrence of operating and capital expenditures. We have identified numerous additional drilling locations on our existing leaseholds, the successful development of which we believe could significantly increase our production and proved reserves. Over the five years ended December 31, 2020, we drilled or participated in 92 gross (42.8 net) wells all of which were commercially productive. The amendments to our First Lien Credit Facility and Second Lien Credit facility place severe restrictions on our future capital expenditures. We have suspended any planned drilling activity for  2021 indefinitely.

Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, finance, acquire and develop additional reserves that are profitable to produce. The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced unless we acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploration and development activities will result in increases in our proved reserves. If our proved reserves decline in the future, our production may also decline and, consequently, our cash flows from operations will decline. We may be unable to acquire or develop additional reserves, in which case our results of operations and financial condition could be adversely affected.

Results of Operations

Selected Operating Data. 

Not required for Smaller Reporting Company.

Comparison of Year Ended December 31, 2020 to Year Ended December 31, 2019

Revenue. During the year ended December 31, 2020, revenue decreased to $43.0 million from $129.1 million in 2019. The decrease in revenue was primarily due to lower sales volumes and lower prices for all products in 2020 . Lower sales volumes were the result of our decision to shut-in a significant amount of our production in mid-March as a result of the drastic price drop in early March due predominantly to the COVID 19 pandemic as well as geopolitical issues impacting supply and demand  Lower commodity prices negatively impacted revenue by  $18.5 million, while lower sales volumes had a negative impact on revenue of  $67.5 million. During 2020 we experienced a decrease in the average realized oil price of approximately 29% from 2019 levels. Average realized gas prices decreased by approximately 57% and average realized NGL prices decreased by approximately 75% from 2019 levels. 

Oil sales volumes decreased to 1,133 MBbls for the year ended December 31, 2020 from 2,388  MBbls for the same period of 2019. The decrease in oil sales volumes was primarily due to wells being shut in for most of the second quarter of 2020 due to severely depressed prices. We started bringing the shut in wells back on production in June, and had a majority of such wells back on production by early September. No new wells were brought on line in 2020. Gas sales volumes decreased to 2,134 MMcf for the year ended December 31, 2020 compared to 4,076 MMcf for the year ended December 31, 2019.  NGL sales decreased to 313 MBbls for the year ended December 31, 2020 compared to 548 MBbls for the same period of 2019. Overall BOE sales in 2020 were approximately 50%  of 2019 sales.

Lease Operating Expenses (“LOE”). LOE for the year ended December 31, 2020 decreased to $16.5 million from $27.6 million in 2019.  The decrease in LOE was primarily due to the disposition of our south Texas properties during the fourth quarter of 2019 and lower non-recurring LOE in 2020 as compared to 2019. Additionally, during the first nine months of 2020, we purchased certain production equipment that we had previously been renting and brought electrical power into most of our West Texas locations eliminating the need for generator rentals. We also reduced our work force in North Dakota in May 2020 and eliminated substantially all field overtime.   LOE per Boe for the year ended December 31, 2020 was $9.14  compared to $7.64 for the same period of 2019. The increase in LOE per Boe was attributable to lower sales volumes in 2020 as compared to 2019.

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Production and Ad Valorem Taxes.  Production and ad valorem taxes for the year ended December 31, 2020 decreased to $4.6 million from $10.6 million in 2019. The decrease was primarily due to lower realized prices and sales volumes in 2020 as compared to 2019. Production and ad valorem taxes as a percentage of oil and gas revenue were 11% in 2020  compared to 8% for the same period of  2019. The increase in the percentage of revenue is primarily due to ad valorem taxes that are not impacted by production tax rates.

General and Administrative (“G&A”) Expense.  G&A expense, excluding stock-based compensation, decreased to $7.5 million for the year ended December 31, 2020 from $9.4 million in 2019.  G&A expense per Boe was $4.15 for the year ended December 31, 2020 compared to $2.60 for the same period of 2019. The reduction in total G&A expense was primarily due to a reduction in personnel in the corporate office, as well as reductions in salaries. Officer salaries were reduced by 20%  effective March 1, 2020, and our CEO took an additional 20% reduction in salary effective April 1, 2020.  The increase per Boe was primarily due to  lower sales volumes. Due to management's decision to shut in substantially all production for most of the second quarter and a portion of  the third quarter, management believes the absolute decrease in cost is more relevant than the cost per BOE.

Stock-Based Compensation.  Restricted stock, stock options and performance based restricted stock  granted to employees and directors are valued at the date of grant and expense is recognized over the securities vesting period. Stock-based compensation decreased to $1.3 million for the year ended December 31, 2020 compared to $1.9 million for the same period of 2019. The decrease was primarily due to the cancellation, forfeiture, and expiration of stock options.  The Company did not award any stock options in 2019 or 2020..

Depreciation, Depletion, and Amortization (“DD&A”) Expenses. DD&A expense excluding accretion of future site restoration, decreased to $24.4 million for the year ended December 31, 2020 from $52.3 million in 2019. The decrease was primarily due to lower future development cost included in the December 31, 2020 internal reserve report, as well as lower production volumes during the year  ended December 31, 2020 as compared to the same period of 2019.  DD&A expense per Boe for the year ended December 31, 2020 was $13.63 compared to $14.46 in the same period of  2019. The decrease in DD&A expense per Boe was primarily due to a lower full cost pool as the result of the impairment incurred as of December 31, 2019 and in 2020 as well as lower production volumes.

Interest Expense. Interest expense increased to $21.3 million in 2020 from $12.3 million for 2019. The increase was primarily due to higher debt levels in 2020 as compared to 2019, as well as higher overall  interest rates in 2020 as compared to 2019. In 2020 the interest rate on our First Lien Credit facility averaged 3.6% as compared to 5.7% in 2019. On November 13, 2019, we entered into the Term Loan Credit Agreement, which we refer to as the Second Lien Credit Facility. The average interest rate on the Second Lien Credit Facility was 13.75% for the year ended December 31, 2020. Approximately $12.7 million of interest on the Second Lien Credit Facility was paid in kind.

Income Taxes.  Due to losses in the periods and loss carry forwards, we did not recognize any income tax expense for the years ended December 31, 2020 and 2019.

(Gain) loss on Derivative Contracts. Derivative gains or losses are determined by actual derivative settlements during the period and by periodic mark to market valuation of derivative contracts in place. We have elected not to apply hedge accounting to our derivative contracts as prescribed by Accounting Standards Codification 815, Derivatives and Hedging "ASC 815"; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consisted of fixed price swaps and basis differential swaps in 2020 and 2019. The net estimated value of our commodity derivative contracts was an asset of approximately $19.4 million as of December 31, 2020. When our derivative contract prices are higher than prevailing market prices, we recognize gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses. For the year ended December 31, 2020, we incurred a gain of $42.9 million, consisting of a gain of $17.5 million on closed contracts and a gain of $25.4 million on the mark to market valuation on open contracts. For the year ended December 31, 2019, we recognized a loss on our derivative contracts of approximately $26.8 million, consisting of a loss of $6.0 million on closed contracts and a loss of $20.8 million on the mark to market valuation of open contracts.

Ceiling Limitation Write-Down. We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties.  Under the full cost accounting rules, the net capitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes.  If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flows from operating activities. However, such write-downs do impact the amount of our stockholders' equity and reported earnings. During 2020, the net capitalized cost of our oil and gas properties exceeded the future net revenues from our estimated proved reserves resulting in the recording of an impairment of $187.0 million. For the year ended  December 31, 2019, the net capitalized cost of our oil and gas properties exceeded the future net revenues from our estimated proved reserves resulting in the recording of an impairment of $51.3 million. The year-end amounts were calculated in accordance with SEC rules utilizing the twelve month first-day-of-the-month average oil and gas prices utilized for the year ended 2020 which were $39.54 per Bbl of oil and $2.03 per Mcf of gas as adjusted to reflect the expected realized prices for our oil and gas reserves. The twelve month first-day-of-the-month average oil and gas prices utilized for the year ended 2019 were $50.03 per Bbl of oil and $0.56 per Mcf of gas as adjusted to reflect the expected realized prices for our oil and gas reserves.

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Working Capital (Deficit). At December 31, 2020,  our current liabilities of $219.3 million exceeded our current assets of  $24.1 million resulting in a working capital deficit of $195.2 million. This compares to a working capital deficit of $28.6 million at December 31, 2019. Current assets at December 31, 2020 primarily consisted of  accounts receivable of $10.0 million, current amount of our derivative asset of $9.6 million and other current assets of $1.6 million.  Current liabilities at December 31, 2020 primarily consisted of trade payables of $6.1 million, revenues due third parties of $8.8 million, current maturities of long-term debt of $202.8 million, the current amount of our derivative liability of $0.5 million and accrued expenses of $0.3 million. 

Capital Expenditures. Capital expenditures in  2019 and 2020 were $93.0 million and $5.4 million, respectively.  The table below sets forth the components of these capital expenditures:

	Years Ended December 31,
	2019		2020
	(in thousands)
Expenditure category:
Exploration/Development	$	92,884	$	5,238
Acquisitions		-		-
Facilities and other		155		162
	$	93,039	$	5,400

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During 2020 capital expenditures were primarily expenditures on our existing properties, designed to reduce lease operating expense, such as purchasing certain equipment as opposed to renting. We also performed extensive workovers on several wells in 2020.  In 2019, capital expenditures were for the exploration and development of our existing properties.  The level of capital expenditures will vary during future periods depending on economic and industry conditions and commodity prices. Should the prices of oil and gas decline and if our costs of operations increase or if our production volumes decrease, our cash flows from operations will decrease which may result in a reduction of capital expenditure. Due to capital expenditure limits imposed by our credit facilities, we have not adopted a capital drilling budget for 2021, but do intend to complete the six previously drilled wells in the Bakken. If we cannot incur significant capital expenditure, we will not be able to offset oil and gas production decreases caused by natural field declines. 

Sources and Uses of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below: 

	Years Ended December 31,
	2019			2020
	(in thousands)
Net cash provided by operating activities	$	73,647		$	15,985
Net cash used in investing activities		(84,967	)		(12,557	)
Net cash (used in) provided by financing activities		10,453			(653	)
	$	(867	)	$	2,775

Operating activities for the year ended December 31, 2020 provided  $16.0 million in cash compared to $73.6 million in 2019. The reduction was primarily due to lower net income due to lower commodity prices and lower production volumes. Investing activities used  $12.6 million in 2020 primarily for the development of our existing properties. Cash expenditures for the year ended December 31, 2020 included a decrease in the accounts payable balance related to capital expenditures of $7.2 million, resulting in accrual based capital expenditures incurred during the period of $5.4 million. 

Operating activities for the year ended December 31, 2019 provided  $73.6 million in cash. The reduction from 2018 was primarily due to lower net income due to lower commodity prices. Investing activities used  $85.0 million in 2019 primarily for the development of our existing properties and leasehold acquisitions. Cash expenditures for the year ended December 31, 2019 included a decrease in the accounts payable balance related to capital expenditures of $16.5 million, and an increase in our asset retirement obligation liability of $0.8 million, resulting in accrual based capital expenditures, net of dispositions of $23.4 million, incurred during the period of $93.0  million. Financing activities provided $10.5  million primarily from net borrowings under our First Lien Credit Facility and Second Lien Credit Facility.

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Future Capital Resources. Our principal sources of capital going forward, are cash flows from operations, proceeds from the sale of properties, monetizing of derivative instruments and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete financing on terms acceptable to us, if at all.

Cash from operating activities is dependent upon commodity prices and production volumes.  A decrease in commodity prices from current levels would likely reduce our cash flows from operations.  This could cause us to alter our business plans, including reducing our exploration and development plans.  Unless we otherwise expand and develop reserves, our production volumes may decline as reserves are produced.  In the future we may continue to sell producing properties, which could further reduce our production volumes. To offset the loss in production volumes resulting from natural field declines and sales of producing properties, we must conduct successful exploration and development activities, acquire additional producing properties or identify and develop additional behind-pipe zones or secondary recovery reserves. We believe our numerous drilling opportunities will allow us to increase our production volumes; however, our drilling activities are subject to numerous risks, including the risk that no commercially productive oil and gas reservoirs will be found.  If our proved reserves decline in the future, our production will also decline and, consequently, our cash flows from operations will decline. 

Contractual Obligations. We are committed to making cash payments in the future on the following types of agreements:

• Long-term debt

Below is a schedule of the future payments that we are obligated to make based on agreements in place as of December 31, 2020:

	Payments due in the twelve month periods ended:
Contractual Obligations (In thousands)	Total		December 31, 2021		December 31, 2022-2023		December 31, 2024-2025		Thereafter
Long-term debt (1)	$	220,505	$	217,990	$	2,515	$	-	$	-
Interest on long-term debt (2)		6,672		6,497		175		-		-
Paid in kind interest on long-term debt (3)		21,130		21,130		-		-		-
Lease obligations		282		63		88		32		99
Total	$	248,589	$	245,680	$	2,778	$	32	$	99

___________________________

(1) These amounts represent the balances outstanding under our credit facilities and the real estate lien note. These payments assume that we will not borrow additional funds.

(2)	Interest expense assumes the balances of long-term debt at December 31, and current effective interest rates at that time.
(3)	Represents interest expense paid in kind on our Second Lien Credit Facility. Accrued interest is added to the outstanding balance and is payable at maturity.

We maintain a reserve for costs associated with the retirement of tangible long-lived assets. At December 31, 2020, our reserve for these obligations totaled $7.4 million for which no contractual commitments exist. For additional information relating to this obligation, see Note 1 of the Notes to Consolidated Financial Statements.

Off-Balance Sheet Arrangements. At December 31, 2020, we had no existing off-balance sheet arrangements, as defined under SEC regulations, that have, or are reasonably likely to have a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

Contingencies. From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At December 31, 2020, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us.

Long-Term Indebtedness.

Long-term debt consisted of the following:

	Years Ended December 31,
	2019			2020
	(In thousands)
First Lien Credit Facility	$	95,778		$	95,000
Second Lien Credit Facility		100,000			112,695
Exit fee - Second Lien Credit Facility		-			10,000
Real estate lien note		3,091			2,810
		198,869			220,505
Less current maturities		(280	)		(202,751	)
		198,589			17,754
Deferred financing fees and debt issuance cost - net		(5,871	)		(15,239	)
Total long-term debt, net of deferred financing fees and debt issuance costs	$	192,718		$	2,515

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The following sections regarding the First Lien Credit Facility and Second Lien Credit Facility are qualified in their entirety by the disclosure contained in Item 1. Business, Going Concern, which is expressly incorporated in the sections below. Due to certain covenant violations as of December 31, 2020, and the potential for future violations, all of the debt related to our credit facilities has been classified as current liabilities.

First Lien Credit Facility

The Company has a senior secured First Lien Credit Facility with Société Générale, as administrative agent and issuing lender, and certain other lenders.  As of December 31, 2020,  $95.0 million was outstanding under the First Lien Credit Facility. 

Outstanding amounts under the First Lien Credit Facility accrue interest at a rate per annum equal to (a)(i) for borrowings that we elect to accrue interest at the reference rate  at the greater of (x) the reference rate announced from time to time by Société Générale, (y) the federal funds rate plus 0.5%, and (z)  daily one-month LIBOR plus, in each case, 1.5%-2.5%, depending on the utilization of the borrowing base, and (ii) for borrowings that  we elect to accrue interest at the Eurodollar rate, LIBOR plus 2.5%-3.5% depending on the utilization of the borrowing base, and (b) at any time an event of default exists, 3.0% plus the amounts set forth above. At December 31, 2020, the interest rate on the First Lien Credit Facility was approximately 3.6%.

     Subject to earlier termination rights and events of default, the stated maturity date of the First Lien Credit Facility is May 16, 2022. Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. The Company is permitted to terminate the First Lien Credit Facility and is able, from time to time, to permanently reduce the lenders’ aggregate commitment under the First Lien Credit Facility in compliance with certain notice and dollar increment requirements.

Each of the Company's subsidiaries has guaranteed our obligations under the First Lien Credit Facility on a senior secured basis. Obligations under the First Lien Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of the Company and its subsidiary guarantors’ material property and assets. As of December 31, 2020, the collateral is required to include properties comprising at least 90% of the PV-9 of the Company's proven reserves and 95% of the PV-9 of the Company's PDP reserves.

Under the amended First Lien Credit Facility, the Company is subject to customary covenants, including financial covenants and reporting covenants. The amendment to the First Lien Credit Facility dated June 25, 2020 (the "1L Amendment") modified certain provisions of the First Lien Credit Facility, including (i) the addition of monthly mandatory prepayments from excess cash (defined as available cash minus certain cash set-asides and a $3.0 million working capital reserve) with corresponding reductions to the borrowing base; (ii) the elimination of scheduled redeterminations (which were previously made every six months) and interim redeterminations (which were previously made at the request of the lenders no more than once in the six month period between scheduled redeterminations) of the borrowing base; (iii) the replacement of total debt leverage ratio and minimum asset ratio covenants with a first lien debt leverage ratio covenant (comparing the outstanding debt of the First Lien Credit Facility to the consolidated EBITDAX of the Company and requiring that the ratio not exceed 2.75 to 1.00 as of the last day of each fiscal quarter) and a minimum first lien asset coverage ratio covenant (comparing the sum of, without duplication, (A) the PV-15 of producing and developed proven reserves of the Company, (B) the PV-9 of the Company’s hydrocarbon hedge agreements and (C) the PV-15 of proved reserves of the Company classified as “drilled uncompleted” (up to 20% of the sum of (A), (B) and (C)) to the outstanding debt of the First Lien Credit Facility and requiring that the ratio exceed 1.15 to 1.00 as of the last day of each fiscal quarter ending on or before December 31, 2020, and 1.25 to 1.00 for fiscal quarters ending thereafter); (iv) the elimination of current ratio and interest coverage ratio covenants; (v) additional restrictions on (A) capital expenditures (limiting capital expenditures to $3.0 million in any four fiscal quarter period (commencing with the four fiscal quarter period ended June 30, 2020 and calculated on an annualized basis for the 1, 2 and 3 quarter periods ending on June 30, 2020, September 30, 2020 and December 31, 2020, respectively, subject to certain exceptions, including capital expenditures financed with the proceeds of newly permitted, structurally subordinated debt and capital expenditures made when (1) the first lien asset coverage ratio is at least 1.60 to 1.00, (2) the Company is in compliance with the first lien leverage ratio, (3) the amounts outstanding under the First Lien Credit Facility are less $50.0 million, (4) no default exists under the First Lien Credit Facility and (5) and all representations and warranties in the First Lien Credit Facility and the related credit documents are true and correct in all material respects), (B) outstanding accounts payable (limiting all outstanding and undisputed accounts payable to $7.5 million, undisputed accounts payable outstanding for more than 60 days to $2.0 million and undisputed accounts payable outstanding for more than 90 days to $1.0 million and (C) general and administrative expenses (limiting cash general and administrative expenses the Company may make or become legally obligated to make in any four fiscal quarter period to $9.0 million for the four fiscal quarter period ended June 30, 2020, $8.25 million for the four fiscal quarter period ended September 30, 2020, $6.9 million for the four fiscal quarter period ending December 31, 2020, and $6.5 million for the fiscal quarter from March 31, 2021 through December 31, 2021 and $5.0 million thereafter; in all cases, general and administrative expense excludes up to $1.0 million in certain legal and professional fees; and (vi) permission for up to an additional $25.0 million in structurally subordinated debt to finance capital expenditures. Under the 1L Amendment, the borrowing base was adjusted to $102.0 million. The borrowing base will be reduced by any mandatory prepayments from excess cash flow (in an amount equal to such prepayment) and upon the disposition of the Company’s oil and gas properties.

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Table of Contents

The First Lien Credit Facility contains a number of covenants that, among other things, restrict our ability to: 

• incur or guarantee additional indebtedness;

• transfer or sell assets;

• pay dividends or make other distributions on capital stock or make other restricted payments;

• engage in transactions with affiliates other than on an "arm's length" basis;

• make any change in the principal nature of our business; and

• permit a change in control

The First Lien Credit Facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. 

Events of default have occurred, or are reasonably likely to occur, under the First Lien Credit Facility as a result of (i) our failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, (ii) our inability to comply with the first lien debt to consolidated EBITDAX ratio for the fiscal quarter ended December 31, 2020, (iii) our failure to cause certain deposit accounts to be subject to control agreements in favor of the administrative agent for the First Lien Credit Facility and (iv) certain cross-defaults that have occurred, or may occur, as a result of the events of default under the First Lien Credit Agreement and corresponding cross-defaults under the Second Lien Credit Facility and cross-defaults or similar termination events under our hedging contracts.

Second Lien Credit Facility

On November 13, 2019, we entered into the Term Loan Credit Agreement, with Angelo Gordon Energy Servicer, LLC, as administrative agent, and certain other lenders party thereto, which we refer to as the Second Lien Credit Facility. The Second Lien Credit facility was amended on June 25, 2020. The Second Lien Credit Facility has a maximum commitment of $100.0 million. On November 13, 2019, $95.0 million of the net proceeds obtained from the Second Lien Credit Facility were used to permanently reduce the borrowings outstanding on the First Lien Credit Facility.  As of December 31,  2020, the outstanding balance on the Second Lien Credit Facility was $122.7 million, which includes a $10.0 million exit fee. 

The stated maturity date of the Second Lien Credit Facility is November 13, 2022. Prior to the latest amendments of the Second Lien Credit Facility, accrued interest was payable quarterly on reference rate loans and at the end of each three-month interest period on Eurodollar loans. We are permitted to prepay the loans in whole or in part, in compliance with certain notice and dollar increment requirements.

Each of our subsidiaries has guaranteed our obligations under the Second Lien Credit Facility. Obligations under the Second Lien Credit Facility are secured by a first priority perfected security interest, subject to certain permitted liens, including those securing the indebtedness under the First Lien Credit Facility to the extent permitted by the Intercreditor Agreement, of even date with the Second Lien Credit Facility, among us, our subsidiaries, Angelo Gordon Energy Servicer, LLC and Société Générale, in all of our subsidiary guarantors’ material property and assets. As of December 31, 2020, the collateral is required to include properties comprising at least 90% of the PV-9 of the Company's proven reserves and 95% of the PV-9 of the Company's PDP reserves. 

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Table of Contents

Under the amended Second Lien Credit Facility, the Company is subject to customary covenants, including financial covenants and reporting covenants. The amendment to the Second Lien Credit Facility dated June 25, 2020 (the "2L Amendment") modified certain provisions of the Second Lien Credit Facility, including (i) a requirement that, while the obligations under the First Lien Credit Facility are outstanding, scheduled payments of accrued interest under the Second Lien Credit Facility will be paid in the form of capitalized interest; (ii) an increase in the interest rate by 200bps for interest payable in cash and 500bps for interest payable in kind; (iii) modification of the minimum asset ratio covenant to be the sum of, without duplication, (A) the PV-15 of producing and developed proven reserves of the Company, (B) the PV-9 of the Company’s hydrocarbon hedge agreements and (C) the PV-15 of proved reserves of the Company classified as “drilled uncompleted” (up to 20% of the sum of (A), (B) and (C)) to the total outstanding debt of the Company and requiring that the ratio not exceed 1.45 to 1.00 as of the last day of each fiscal quarter ending between September 30, 2021 to December 31, 2021, and 1.55 to 1.00 for fiscal quarters ending thereafter); (iv) modification of the total leverage ratio covenant to set the first test date to occur on September 30, 2021; (v) modification of the current ratio to eliminate the exclusion of certain valuation accounts associated with hedge contracts from current assets and from current liabilities, (vi) additional restrictions on (A) capital expenditures (limiting capital expenditures to those expenditures set forth in a plan of development approved by Angelo Gordon Energy Servicer, LLC, subject to certain exceptions, including capital expenditures financed with the proceeds of newly permitted, structurally subordinated debt), (B) outstanding accounts payable (limiting all outstanding and undisputed accounts payable to $7.5 million, undisputed accounts payable outstanding for more than 60 days to $2.0 million and undisputed accounts payable outstanding for more than 90 days to $1.0 million and (C) general and administrative expenses (limiting cash general and administrative expenses the Company may make or become legally obligated to make in any four fiscal quarter period to $9.0 million for the four fiscal quarter period ended June 30, 2020, $8.25 million for the four fiscal quarter period ended September 30, 2020, $6.5 million for fiscal quarter period from March 31, 2021 through December 31, 2021 and $5.0 million thereafter. 

 As of December 31, 2020 we were in compliance with  the financial covenants under the Second Lien Credit Facility, as amended.

The Second Lien Credit Facility contains a number of covenants that, among other things, restrict our ability to:

● incur or guarantee additional indebtedness;

● transfer or sell assets;

● create liens on assets;

● pay dividends or make other distributions on capital stock or make other restricted payments; 

● engage in transactions with affiliates other than on an “arm’s length” basis;

● make any change in the principal nature of our business; and

● permit a change of control

The Second Lien Credit Facility also contains customary events of default, including nonpayment of principal or interest, violation of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities.

Events of default have occurred, or are reasonably likely to occur, under the Second Lien Credit Facility as a result of (i) our failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, (ii) our failure to cause certain deposit accounts to be subject to control agreements in favor of the administrative agent for the Second Lien Credit Facility, (iii) the failure of the Company to meet certain hedging requirements, and (v) certain cross-defaults that have occurred, or may occur, as a result of the occurrence of events of default under the First Lien Credit Facility and the Second Lien Credit Facility and corresponding cross-defaults or similar termination events under our hedging contracts.

On April 16, 2021, we received a Notice of Default and Reservation of Rights (the “Notice of Default”) from Angelo Gordon stating that we have defaulted under the Second Lien Credit Facility, and that, as a result, the lenders have accelerated our obligations due thereunder and have reserved their rights to pursue additional remedies in the future.

The Notice of Default describes certain events of default that occurred under the Second Lien Credit Facility as a result of (i) our failure to file timely our Form 10-K for the fiscal year ended December 31, 2020, (ii) our failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, and (iii) other defaults under our revolving credit facility.

The Notice of Default declares that our obligations under the Second Lien Credit Facility are immediately due and payable, in each case without presentment, demand, protest or other requirements of any kind, and have begun to bear interest at the rate applicable to such amount under the Second Lien Credit Facility, plus an additional 3%. Additionally, the administrative agent and the lenders have reserved their right to exercise further rights, powers and remedies under the Second Lien Credit Facility, at any time or from time to time, with respect to any of the events of default described above. Angelo Gordon has agreed to forbear from exercising remedies available to it until May 6, 2021.

In connection with the amendment to the Second Lien Credit Facility on June 25, 2020, the Company entered into an Exit Fee and Warrant Agreement subject to NASDAQ approval for the issuance of the issuance of certain warrants. This agreement was finalized on August 11, 2020 at which time the Company issued a warrant to the lender to purchase a total of 33,445,792 shares of common stock at an exercise price of $0.01 per share. On October 19, 2020, the Company effected a reverse stock split of the Company’s authorized, issued and outstanding shares of common stock at a ratio of 1-for-20, thus the warrant was adjusted to provide that the lender may purchase a total of 1,672,290 shares of common stock at an exercise price of $0.20 per share. The warrant is exercisable immediately in whole or in part, on or before five years from the issuance date. The fair value of the warrant and exit fee were recorded as debt issuance costs, presented in the consolidated balance sheets as a deduction from the carrying amount of the note payable, and are being amortized over the loan term. The Exit Fee shall be due and payable in cash on the earliest to occur of maturity of the obligation under the Second Lien Credit Agreement or the earlier acceleration or payment in full of the same. The 2L Amendment, including the impact of the Exit Fee and Warrant Agreement finalized on August 11, 2020, resulted in the 2L Amendment meeting the criteria of debt extinguishment under the guidance of ASC 470: Debt. Accordingly, all debt issuance cost, including the original discount, of the original Second Lien Credit Facility, were charged to debt extinguishment loss in the accompanying Condensed Consolidated Statement of Operation in the amount of $4.1 million.

Real Estate Lien Note

We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. The outstanding principal accrues interest at a fixed rate of 4.9%. The note is payable in monthly installments of principal and interest in the amount of $35,672.  The maturity date of the note is July 20, 2023. As of  December 31, 2019, and 2020, $3.1 million and $2.8 million, respectively, were outstanding on the note.

Net Operating Loss Carryforwards

At December 31, 2020, we had, subject to the limitation discussed below, $245.20 million of pre 2020 NOLs for U.S. tax purposes and a $140.0 million NOL for 2020.  Our pre-2018 NOLs will expire in varying amounts from 2023 through 2037, if not utilized; and can offset 100% of future taxable income for regular tax purposes. Any NOLs arising in 2018, 2019 and 2020 can generally be carried back five years, carried forward indefinitely and can offset 100% of future taxable income for tax years before January 1, 2021 and up to 80% of future taxable income for tax years after December 31, 2020. Any NOLs arising on or after January 1, 2021, cannot be carried back and  can generally be carried forward indefinitely and can offset up to 80% of future taxable income for regular tax purposes, (the alternative minimum tax no longer applies to corporations after January 1, 2018).

Uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under ASC 740-10 “Income Taxes”. Therefore, we have established a valuation allowance of $117.27 million for deferred tax assets at December 31, 2020.

Related Party Transactions

We have adopted a policy that transactions between us and our officers, directors, principal stockholders, or affiliates of any of them, will be on terms no less favorable to us than can be obtained on an arm’s length basis in transactions with third parties and must be approved by our audit committee. There were no related party transactions in  2019 or 2020.

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 Critical Accounting Policies

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“GAAP”) requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain.

Full Cost Method of Accounting for Oil and Gas Activities. SEC Regulation S-X Rule 4-10 and ASC 932 defines the financial accounting and reporting standards for companies engaged in oil and gas activities. Two methods are prescribed: the successful efforts method and the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities but do not include any costs related to production, general corporate overhead or similar activities. Sales of oil and gas properties are treated as a reduction of the full cost pool with no gain or loss being recognized, except under certain circumstances. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and gas properties are generally calculated on a well by well or lease or field basis versus the “full cost” pool basis. Additionally, gain or loss may be recognized on sales of oil and gas properties under the successful efforts method. As a result, our financial statements will differ from those of companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher depreciation, depletion and amortization rate on our oil and gas properties.

At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method. However, the full cost method makes us susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. We have experienced this situation several times over the years, including a $51.3 million and  $187.0 million impairment recorded as of December 31, 2019 and December 31, 2020, respectively.  Our oil and gas reserves have a relatively long life. However, temporary drops in commodity prices can have a material impact on our business including impact from impairment testing procedures associated with the full cost method of accounting as discussed below.

Under full cost accounting rules, the net capitalized cost of oil and gas properties, less related deferred taxes, may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves on a pool by pool basis, discounted at 10%, plus the lower of cost or fair market value of unproved properties and the cost of properties not being amortized, less income taxes. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation write-down.”  This charge does not impact cash flows from operating activities, but does reduce our stockholders’ equity and reported earnings. The risk that we will be required to write down the carrying value of oil and gas properties increases when oil and gas prices are depressed. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. Given the recent decline in oil prices, it is likely that we will incur future impairments. 

Estimates of Proved Oil and Gas Reserves. Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

• the quality and quantity of available data;

• the interpretation of that data;

• the accuracy of various mandated economic assumptions; and

• the judgment of the persons preparing the estimate.

Our proved oil and gas reserves have been estimated by our independent petroleum engineering firm, DeGolyer & MacNaughton, as of December 31, 2019 and 2020,  Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on costs on the date of the estimate and for the years ended December 31, 2019 and 2020 oil and gas prices were based on the average 12-month first-day-of-the-month pricing.  Actual future prices and costs may be materially higher or lower than the prices and costs used in the estimate.

The estimates of proved reserves materially impact DD&A expense and the ceiling test calculation. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase and we may be required to record future impairments of the full cost pool, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields.

Asset Retirement Obligations. The estimated costs of restoration and removal of facilities are accrued. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and we amortize these costs as a component of our depletion expense.

Accounting for Derivatives. Gains or losses are determined by actual derivative settlements during the period and on the periodic mark to market valuation of derivative contracts in place. The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations.  We have elected not to apply hedge accounting to our derivative contracts. As a result, fluctuations in the market value of the derivative contract are recognized in earnings during the current period. In 2019 and 2020 derivative contracts consisted of fixed price swaps and basis differential swaps. Due to the volatility of oil and gas prices, our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments. As of December 31, 2019, and 2020, the net market value of our commodity derivatives was a net liability of $7.4 million and a net asset of  $19.4 million, respectively. The recent drop in oil prices has resulted in a significant increase in the value of our derivative contracts.

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Recently Issued Accounting Standards 

Effective January 1, 2020, the Company adopted Accounting Standards Update ("ASU") 2016-13 and its related amendments.  This ASU primarily applies to the Company’s accounts receivable, of which the majority are due within 30 days. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analysis. The Company develops its estimated allowance for credit losses primarily using an aging method and analysis of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.

In November 2019, the FASB issued ASU 2019-12 – Income Taxes (“Topic 740”): Simplifying the Accounting for Income Taxes. The amendments in ASU 2019-12 are part of an initiative to reduce complexity in accounting standards and simplify the accounting for income taxes by removing certain exceptions from Topic 740 and making minor improvements to the codification. ASU 2019-12 and its related amendments will be effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.

New accounting pronouncements issued but not yet adopted. 

In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 840): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (“ASU 2020-04”), which provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates (e.g., London Interbank Offered Rate (“LIBOR”)) that are expected to be discontinued. ASU 2020-04 allows, among other things, certain contract modifications, such as those within the scope of Topic 470 on debt, to be accounted as a continuation of the existing contract. This ASU was effective upon the issuance and its optional relief can be applied through December 31, 2022. The Company will consider this optional guidance prospectively, if applicable.

In May 2020, the SEC adopted final rules that amend the financial statement requirements for significant business acquisitions and dispositions. Among other changes, the final rules modify the significance tests and improve the disclosure requirements for acquired or to be acquired businesses and related pro forma financial information, the periods those financial statements must cover, and the form and content of the pro forma financial information. The final rules do not modify requirements for the acquisition and disposition of significant amounts of assets that do not constitute a business. The final rules are effective January 1, 2021, but earlier compliance is permitted. The Company will consider these final rules and update its disclosures, as applicable.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

As an independent oil and gas producer, our revenue, cash flows from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of oil and gas. Declines in commodity prices will adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of oil and gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Historically, prices received for our oil and gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indices fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. Assuming the production levels we attained during the year ended December 31, 2020, a 10% decline in oil and gas prices would have reduced our operating revenue and cash flows by approximately $4.3 million for the year. If commodity prices remain at their current levels the impact on operating revenues and cash flows, could be much more significant. However, we do have derivative contracts in place that will mitigate the impact of low commodity prices.

Derivative Instrument Sensitivity

At December 31, 2020, the aggregate fair market value of our commodity derivative contracts was an asset of  approximately $19.4 million. The fair market value of our commodity derivative contracts is sensitive to changes in the market price for oil and gas. When our derivative contract prices are higher than prevailing market prices, we recognize gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses.

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Interest Rate Risk

We are subject to interest rate risk associated with borrowings under our First Lien Credit Facility and our Second Lien Credit facility.  As of December 31, 2020, we had $95.0 million of outstanding indebtedness under our First Lien Credit Facility and $112.7 of outstanding indebtedness under our Second Lien Credit Facility, each with a variable interest rate. At December 31, 2020, the interest rate on the First Lien Credit Facility was approximately 3.6% based on 1-month LIBOR borrowings and level of utilization. An increase in the interest rate of 1% would increase our interest expense by $1.0 million on an annual basis, based on the outstanding balance at December 31, 2020. At December 31, 2020 the interest rate on the Second Lien Credit Facility was 15.8% based on 3-month LIBOR borrowings. An increase of 1% would increase our interest expense by $1.1 million on an annual basis, based on the outstanding balance at December 31, 2020.

Item 8. Financial Statements and Supplementary Data

For the financial statements and supplementary data required by this Item 8, see the Index to Consolidated Financial Statements.

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

On July 20, 2020, the Company's Board of Directors engaged the accounting firm of ADKF, as the Company’s certifying accountants. The decision to approve the dismissal of BDO USA, LLP and engagement of ADKF was approved by the Board's Audit Committee and the Company's Board of Directors.  BDO USA, LLP was notified of their dismissal on July 21, 2020.

In connection with the audit of the Company’s financial statements for the fiscal year ended December 31, 2019, there were no disagreements with BDO USA, LLP on any matters of accounting principles, financial statement disclosure or audit scope and procedures which, if not resolved to the satisfaction of BDO USA, LLP, would have caused the firm to make reference to the matter in their report.

Item 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, the Chief Executive Officer and our Chief Financial Officer concluded that disclosure controls and procedures as of December 31, 2020 were effective, as of the end of the reporting period covered by this report, our disclosure controls over financial reporting are effective.

Changes in Internal Controls

There were no changes in our internal control over financial reporting during the fourth quarter of 2020 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and implemented by the Company’s Board of Directors, management and other personnel, 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 and includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2020.

The effectiveness of our internal control over financial reporting as of December 31, 2020 has not been audited

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Board of Directors

The following table sets forth the names, ages, and positions of the directors of Abraxas. The term of the Class I directors expires in 2021, but if re-elected will expire in 2024, the term of the Class II directors expires in 2023, and the term of the Class III directors expires in 2022.

Name and Municipality of Residence	Age		Office	Class
Robert L.G.Watson............................................................................................................................................ San Antonio, Texas		70	Chairman of the Board, President and Chief Executive Officer	II
Ralph F. Cox....................................................................................................................................................... Fort Worth, Texas		89	Director	I
Brian L. Melton.................................................................................................................................................. Oklahoma City, Oklahoma		51	Director	III
Angela A. Steffen Meyer..................................................................................................................................... Denton, Texas		60	Director	III
				II

Robert L.G. Watson has served as Chairman of the Board, President, Chief Executive Officer and a director of Abraxas since 1977. Prior to forming Abraxas, Mr. Watson held petroleum engineering positions with Tesoro Petroleum Corporation and DeGolyer and MacNaughton. Mr. Watson received a Bachelor of Science degree in Mechanical Engineering from Southern Methodist University in 1972 and a Master of Business Administration degree from the University of Texas at San Antonio in 1974. Mr. Watson has been involved in the oil and gas industry for his entire business career and is the founder of Abraxas. He has developed a wide network of personal and business relationships within the oil and gas industry. His strong engineering and financial background combined with his many years of operational experience throughout changing conditions in the market and industry provide him with the ability to successfully lead the Company.

Ralph F. Cox, a director of Abraxas since December 1999, has over 50 years of oil and gas industry experience, over 30 of which were with Atlantic Richfield Company (ARCO). Mr. Cox retired from ARCO in 1985 after serving as Vice Chairman. Mr. Cox then joined Union Pacific Resources, retiring in 1989 as President and Chief Operating Officer. Mr. Cox then joined Greenhill Petroleum Corporation as President until leaving in 1994 to pursue a consulting business. Mr. Cox currently serves as a trustee for Fidelity Mutual Funds. Mr. Cox previously served as a director of Abraxas General Partner, LLC, the general partner of Abraxas Energy Partners, L.P., as a director of CH2M Hill Companies, an engineering and construction firm, as a director of World GTL Inc., a gas-to-liquids production facility, and as an advisory director of Impact Petroleum, an oil and gas exploration and production company. Mr. Cox received Bachelor of Science degrees in Petroleum Engineering and Mechanical Engineering from Texas A&M University in 1954 and completed advanced studies at Emory University.

Mr. Cox has many years of prior experience with major oil and gas companies. Mr. Cox continues his involvement in the industry through his other directorship positions. His executive-level perspective and decision making abilities continue to prove beneficial to the Company.

Brian L. Melton has served as the Senior Vice President – Commercial & Business Development of NorthStar Midstream (a private portfolio company of OakTree Capital) since September 2019. Prior to joining NorthStar, Mr. Melton worked as Chief Commercial Officer for Blueknight Energy Partners (Nasdaq: “BKEP”, or “Blueknight”), a publicly traded master limited partnership (MLP) that specializes in providing crude oil and asphalt terminalling from December 2013 until September 2019. Prior to joining Blueknight, Mr. Melton served as Vice-President of Business Development / Corporate Strategy for Crestwood Equity Partners, L.P. (NYSE: CEQP), Crestwood Midstream Energy Partners, L.P. (NYSE: CMLP), and Inergy, L.P. (NYSE: NRGY) from September 2008 until December 2013. Crestwood and Inergy are publicly-traded MLP’s that specialize in providing midstream crude oil, natural gas and natural gas liquids services to producers and midstream providers in many of the major U.S. shale plays including the Bakken, Eagle Ford, Marcellus / Utica, Barnett, Fayetteville, Haynesville and Niobrara U.S. shale regions. Prior to joining Inergy in 2008, Mr. Melton was a Director in the Energy Corporate Investment Banking groups of Wachovia Securities and A.G. Edwards, prior to its merger with Wachovia Securities in October of 2007. Mr. Melton joined A.G. Edwards in July 2000 and was a senior member of the energy corporate finance team. From November 1995 until July 2000, Mr. Melton served as Director of Finance & Corporate Planning with TransMontaigne Inc., a downstream refined products supply, transportation and logistics company. Mr. Melton has served on the Board of Directors of San Antonio, TX based exploration and production company Abraxas Petroleum Corporation (Nasdaq: AXAS) since October of 2009. Mr. Melton received a Bachelor of Science degree in Management and a Master of Business Administration degree from Arkansas State University.

We believe that Mr. Melton’s operational and business experience (particularly in the U.S. shale plays in which the Company operates), as well as Mr. Melton’s prior oil and gas investment banking experience help him bring unique insight to our Board and that his financial experience is beneficial to our audit committee.

Angela A. Steffen Meyer, a director of Abraxas since May 2019, currently serves as a Corporate Vice President of Exponent, Inc. (NASDAQ: “EXPO”, or “Exponent”), a science and engineering consulting firm. From June 2018 to October 2019, Dr. Meyer was President and CEO of the Product Liability Advisory Council, a specialized legal association of more than 80 multinational corporations and 350 outside defense counsel. From 1990 through May 2018, Dr. Meyer worked at Exponent (formerly Failure Analysis Associates) in a variety of engineering and corporate roles and served as Vice President, Client Services (2002-2018) where she was the chief business development, marketing and client relations officer. She served on the firm’s operating and development committees. Dr. Meyer also serves on the External Advisory Board of Summit Consulting, LLC (August 2018-present) and the External Advisory Board of SMU Lyle School of Engineering (2006 – present). Dr. Meyer received a BS in Mechanical Engineering, a MS in Mechanical Engineering, and a PhD in Mechanical Engineering, from Southern Methodist University. She is a registered professional mechanical engineer in the State of California.

Committees of the Board of Directors

Abraxas has standing Audit, Compensation and Nominating and Corporate Governance Committees.

The Audit Committee is a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. During 2020, the Audit Committee consisted of Messrs. Melton (Chairman), Cox and Dr. Meyer. The Board of Directors has determined that Mr. Melton is an audit committee financial expert as defined by SEC rules. The Audit Committee Report, which appears on page 31, more fully describes the activities and responsibilities of the Audit Committee. Steven P. Harris, the Company’s Chief Financial Officer, Mr. Krog and representatives from ADKF, PC, the Company’s independent registered public accounting firm, along with all four members of the Company’s Audit Committee attended each meeting of the Audit Committee. In addition, the representatives from ADKF, PC and the Audit Committee met in executive session at each meeting.

The Compensation Committee consist of Messrs. Cox (Chairman), Melton and Dr. Meyer. The Compensation Committee’s role is to establish and oversee Abraxas’ compensation and benefit plans and policies, to administer its stock option plans, and to annually review and approve all compensation decisions relating to Abraxas’ executive officers. The Compensation Discussion & Analysis, as set forth in Item 11, more fully describes the activities and responsibilities of the Compensation Committee. The Compensation Committee submits its decisions regarding executive compensation to the independent members of the Board for approval. The agenda for meetings of the Compensation Committee is determined by its Chairman and the meetings are regularly attended by Mr. Watson. At each meeting, the Compensation Committee also meets in executive session. Mr. Cox reports the committee’s recommendations on executive compensation to the Board. The Company’s personnel support the Compensation Committee in its duties and, along with Mr. Watson, may be delegated authority to fulfill certain administrative duties regarding the Company’s compensation programs. The Compensation Committee has authority under its charter to retain, approve fees for and terminate advisors, consultants and agents as it deems necessary to assist in the fulfillment of its responsibilities. In May 2017, the Compensation Committee engaged Longnecker and Associates, which we refer to as “L&A” or the “Compensation Consultant”, as its independent compensation consultant. The Committee did not engage any outside compensation consultants in 2019 and 2020. For more information on the Compensation Committee’s processes and procedures, please see “Executive Compensation – Compensation Discussion & Analysis – Our Compensation Committee” and – “Elements of Executive Compensation.”

The Nominating Committee consist of Dr. Meyer (Chairman), and Messrs. Cox and Melton. The primary function of the Nominating and Corporate Governance Committee is to develop and maintain the corporate governance policies of Abraxas and to assist the Board in identifying, screening and recruiting qualified individuals to become Board members and determining the composition of the Board and its committees, including recommending nominees for the election at the annual meeting of stockholders or to fill vacancies on the Board.

Each of the Board’s committees has a written charter and copies of the charters are available for review on the Company’s website at www.abraxaspetroleum.com.

Audit Committee and Audit Committee Financial Expert

The Audit Committee of our board of directors consists of Brian L. Melton (Chairman), Ralph R. Cox and Angela Meyer. The board of directors has determined that each of the members of the Audit Committee is independent as determined in accordance with the listing standards of The NASDAQ Stock Market and Item 407(a) of Regulation S-K. In addition, the board of directors has determined that Brian L. Melton, as defined by SEC rules, is an audit committee financial expert.

Code of Ethics

In April 2004, the Board of Directors unanimously approved Abraxas’ Code of Ethics. This Code is a statement of Abraxas’ high standards for ethical behavior, legal compliance and financial disclosure, and is applicable to all directors, officers, and employees. Abraxas’ Code of Ethics is periodically reviewed by the Board of Directors and was last updated in 2018. A copy of the Code of Ethics can be found in its entirety on Abraxas’ website at www.abraxaspetroleum.com. Additionally, should there be any changes to, or waivers from, Abraxas’ Code of Ethics, those changes or waivers will be posted immediately on our website at the address noted above.

Executive Officers

The following table sets forth the names, ages and positions of the executive officers of Abraxas.

Name and Municipality of Residence	Age	Office
Robert L.G. Watson......................................................................... San Antonio, Texas	70	Chairman of the Board, President and Chief Executive Officer
Steven P. Harris................................................................................ San Antonio, Texas	47	Vice President – Chief Financial Officer
Peter A. Bommer.............................................................................. San Antonio, Texas	64	Vice President – Engineering
Tod A. Clarke.................................................................................... San Antonio, Texas	61	Vice President – Land
G. William Krog, Jr......................................................................... San Antonio, Texas	67	Vice President – Chief Accounting Officer
Kenneth W. Johnson........................................................................ San Antonio, Texas	63	Vice President – Operations

Robert L.G. Watson has served as Chairman of the Board, President, Chief Executive Officer and a director of Abraxas since 1977. See page 57 for more information.

Steven P. Harris has served as Vice President – Chief Financial Officer since November 2018. Mr. Harris joined Abraxas in June 2018 as Director, Finance and Capital Markets. Prior to joining Abraxas, from June 2017 to May 2018, Mr. Harris was with Sundance Energy where he assisted Sundance’s Business Development and Investor Relations efforts. From 2008 through 2017, Mr. Harris was a Managing Director and headed the U.S. Energy Investment Banking division of Canaccord Genuity in Houston, Texas. Prior to joining Canaccord Genuity, Mr. Harris served in the Business Development Group at El Paso Exploration and Production. Mr. Harris earned his Bachelor of Business Administration from the University of Texas at Austin and a Master of Business Administration from the Rice University Jesse H. Jones Graduate School of Management.

 Peter A. Bommer has served as Vice President – Engineering since 2012 and as Manager of Special Projects since 2007. Prior to joining Abraxas, Mr. Bommer owned and ran the day-to-day operations of Bommer Engineering, a privately held engineering firm, for over 25 years. Mr. Bommer received a Bachelor of Science in Petroleum Engineering degree from the University of Texas in 1978 and a Master of Theology degree from Dallas Theological Seminary in 1999. Mr. Bommer also holds the Professional Engineer designation.

Tod A. Clarke has served as Vice President – Land since August 2017. Mr. Clarke joined Abraxas in 2000 as Land Manager. Prior to joining Abraxas, Mr. Clarke worked at Exxon USA for 15 years. Mr. Clarke received a Bachelor of Science – Land Management degree from the University of Houston in 1984. Mr. Clarke also is a Certified Petroleum Landman.

Kenneth W. Johnson has served as Vice President – Operations since September 2018. Mr. Johnson joined Abraxas in 2000 and most recently served as Regional Operations Manager. Prior to joining Abraxas, Mr. Johnson served as a consultant to various operators in supervisory and operations management roles across the US including the Mid-Continent, Rockies, and Gulf Coast regions.

G. William Krog, Jr. has served as Chief Accounting Officer since 2011 and Vice President – Chief Accounting Officer since November 2017. Mr. Krog joined Abraxas in 1995 and most previously served as Information Systems / Financial Reporting Director prior to being appointed Chief Accounting Officer. Prior to joining Abraxas, Mr. Krog was an independent accountant in private practice. Mr. Krog received a Bachelor of Business Administration degree from the University of Texas at Austin in 1976 and is a Certified Public Accountant.

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Delinquent Section 16(a) Reports

Section 16(a) of the Exchange Act requires our directors and executive officers and persons who own more than 10% of a registered class of Abraxas equity securities to file with the SEC and The NASDAQ initial reports of ownership and reports of changes in ownership of Abraxas common stock. Officers, directors and greater than 10% stockholders are required by SEC regulations to furnish us with copies of all such forms they file. Based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all our directors and executive officers complied on a timely basis with all applicable filing requirements under Section 16(a) of the Exchange Act during 2020.

Item 11. Executive Compensation

Compensation Discussion & Analysis

We compensate our executive officers through a combination of base salary, annual incentive bonuses and long-term equity based awards. The compensation is designed to be competitive with those of a peer group, which in 2019 was a group of exploration and production companies originally provided by Longnecker & Associates, or L&A or the Compensation Consultant, in 2014 and subsequently updated by the Compensation Committee due to bankruptcies and other corporate events.

This section discusses the principles underlying our executive compensation policies and decisions, and the most important factors relevant to an analysis of these policies and decisions. It provides qualitative information regarding the manner and context in which compensation is awarded to and earned by our executive officers and places in perspective the data presented in the tables and narrative that follow.

Our Compensation Committee

Our Compensation Committee approves, implements and monitors all compensation and awards to executive officers including the Chief Executive Officer, the Chief Financial Officer and the other executive officers named in the Summary Compensation Table below, whom we refer to as the named executive officers or NEOs. The Committee’s membership is determined by the Board of Directors and is composed of three independent directors. The Committee, in its sole discretion, has the authority to delegate any of its responsibilities to subcommittees as it deems appropriate. During 2017, the Compensation Committee engaged L&A to assist in providing a comprehensive assessment of our executive compensation programs. The Compensation Committee retains the sole authority to select, retain, terminate, and approve fees and other retention terms of the relationship with L&A.

During 2017, the Compensation Consultant performed the following services for the Committee:

• Conducted an evaluation of the total compensation for each of the NEOs

• Presented information related to current trends and regulatory developments affecting executive compensation programs among the companies in our peer group;

• Assisted with the analysis and selection of peer group companies for compensation purposes and for comparative total shareholder return, or TSR, purposes;

• Assessed the Company’s Annual Bonus Plan (as defined on page 16) metrics versus the companies in our peer group; and

• Assessed the Company’s LTIP metrics versus the companies in our peer group.

The Committee has not utilized the services of the Compensation Consultant since 2017.

The Committee periodically approves and adopts, or makes recommendations to the Board regarding, Abraxas’ executive compensation decisions. In the first quarter of each year, Mr. Watson, the Chief Executive Officer, submits to the Compensation Committee his recommendations for salary adjustments and long-term equity incentive awards based upon his subjective evaluation of individual performance and his subjective judgment regarding each executive officer’s salary and equity incentives, for each executive officer except himself. For more information on our Compensation Committee, please refer to the discussion under “Proposal One – Election of Directors – Committees of the Board of Directors.”

The Committee reviews all components of compensation for our executive officers, including base salary, annual incentive bonuses, long-term equity based awards, the dollar value to the executive and cost to Abraxas of all benefits and all severance and Change in Control arrangements. Based on this review, the Compensation Committee has determined that the compensation paid to our executive officers reflects our compensation philosophy and objectives.

Compensation Philosophy and Objectives

Our underlying philosophy in the development and administration of Abraxas’ annual and long-term compensation plans is to align the interests of our executive officers with those of Abraxas’ stockholders. Key elements of this philosophy are:

• establishing compensation plans that deliver base salaries which are competitive with companies in our peer group, within Abraxas’ budgetary constraints and commensurate with Abraxas’ salary structure;

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• rewarding outstanding performance; and

• providing equity-based incentives to ensure motivation over the long-term to respond to Abraxas’ business challenges and opportunities as owners rather than just as employees.

The compensation currently paid to Abraxas’ executive officers consists of three core elements: base salary, annual bonuses under the Abraxas Petroleum Corporation Bonus Plan, as amended (the “Annual Bonus Plan”), and long-term equity based awards granted pursuant to the LTIP, plus other employee benefits generally available to all employees of Abraxas.

We believe these elements support our underlying philosophy of aligning the interests of our executive officers with those of Abraxas’ stockholders by providing the executive officers a competitive salary, an opportunity for annual bonuses, and equity-based incentives to ensure motivation over the long-term. We view the three core elements of compensation as related but distinct. Although we review total compensation, we do not believe that significant compensation derived from one component of compensation should increase or reduce compensation from another component. We determine the appropriate level for each component of compensation separately. We have not adopted any formal or informal policies or guidelines for allocating compensation among long-term incentives and annual base salary and bonuses, between cash and non-cash compensation, or among different forms of non-cash compensation. Abraxas’ Board has also adopted stock ownership guidelines. Please read “Stock Ownership Guidelines” for more information.

Abraxas does not have any other deferred compensation programs or supplemental executive retirement plans, no benefits are provided to Abraxas’ executive officers that are not otherwise available to all employees of Abraxas, and no benefits are valued in excess of $10,000 per employee per year.

CEO Pay Ratio

We believe executive pay must be internally consistent and equitable to motivate our employees to create shareholder value. We are committed to internal pay equity, and the Compensation Committee monitors the relationship between the pay our executive officers receive and the pay our non-managerial employees receive. The Compensation Committee reviewed a comparison of CEO pay (base salary and incentive pay) to the pay of all our employees in 2020. The compensation for our CEO in 2020 was approximately 4.6 times the median pay of our full-time employees.

Our CEO to median employee pay ratio is calculated in accordance with SEC regulations. We identified the median employee by examining the 2020 total cash compensation for all individuals, excluding our CEO, who were employed by us on December 16, 2020, the last day of our payroll year. We included all employees, whether employed on a full-time, part-time, or seasonal basis. We did not make any assumptions, adjustments, or estimates with respect to total cash compensation and we did not annualize the compensation for any full-time employees that were not employed by us for all of 2020. We believe the use of total cash compensation for all employees is a consistently applied compensation measure because we do not widely distribute annual equity awards to employees.

After identifying the median employee based on total cash compensation, we calculated annual total compensation for such employee using the same methodology we use for our named executive officers as set forth in the 2020 Summary Compensation Table later in this proxy statement.

As illustrated in the table below, our 2020 CEO to median employee pay ratio was 4.6:1.

	CEO to Median Employee Pay Ratio
	President and CEO			Median Employee
Base Salary..............................................................................................................................................................	$	382,094		$	79,478
Non-Equity Incentive Plan Compensation.........................................................................................................		—			—
All Other Compensation........................................................................................................................................		12,975	(1)		6,680	(2)
	$	395,069		$	86,158

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(1)   This amount represents a $9,975 contribution by Abraxas to Mr. Watson’s 401(k) plan and a $3,000 contribution to Mr. Watson’s health savings accounts for 2020.

(2)   This amount represents a safety pay bonus of $6,680 in 2020.

Elements of Executive Compensation

Executive compensation consists of the following elements:

Base Salary. In determining base salaries for the executive officers of Abraxas, we aim to set base salaries at a level we believe enables us to hire and retain individuals in a competitive environment and to reward individual performance and contribution to our overall business goals. In addition, we take into consideration the responsibilities of each executive officer and determine compensation appropriate for the positions held and expectations of services rendered during the year. During 2019 we utilized a list of peer companies originally provided by L&A in 2014 and subsequently updated by the Committee due to bankruptcies and other corporate events to analyze our salary structure. L&A originally identified, and the Committee updated, potential peer candidates based on 1) companies of similar size, 2) other similar companies in the oil and gas exploration industry, and 3) similar operations in comparable geographic areas. L&A then analyzed (and the Committee updated) each company based on:

• Market capitalization;

• Revenue;

• Assets;

• Enterprise value; and

• Operational similarities.

Using these criteria, in 2019 the following were the comparable companies: Approach Resources, Inc. (AREX), Contango Oil & Gas Company (MCF), Earthstone Energy, Inc. (ESTE), Halcon Resources Corporation (HK), Lilis Energy, Inc. (LLEX), Ring Energy, Inc. (REI) and Rosehill Resources Inc. (ROSE).

In 2019, Abraxas’ salary range was set by reference to the salaries paid by the comparable companies considering the responsibilities and expectations of each executive officer while remaining within Abraxas’ budgetary constraints. We utilized salary information from the comparable companies to compare Abraxas’ salary structure with those other companies that compete with Abraxas for executives but without targeting salaries to be higher, lower or approximately the same as those companies. We believe that the base salary levels for our executive officers are consistent with the practices of the comparable companies, and increases in base salary levels from time to time are designed to reflect competitive practices in the industry, individual performance and the officer’s contribution to our overall business goals. Individual performance and contribution to the overall business goals of Abraxas are subjective measures and evaluated by Mr. Watson and the Compensation Committee and, with respect to Mr. Watson only, the Compensation Committee.

Due to the unprecedented conditions surrounding the outbreak and spread of COVID-19, the decline in oil prices during the first half of 2020, and related geopolitical developments, the Company did not conduct an analysis of the salaries paid by the comparable companies in 2020. Rather, we evaluated our current business activities and financial conditions, and the impact of the foregoing events on our future operations, financial position and liquidity in the fiscal year ending December 31, 2020. In response to the economic uncertainty caused by the pandemic and the upheaval in the oil and gas markets, we took measures to reduce our general and administrative costs, which included reducing the salaries of our executive officers and reducing our work force. In setting Abraxas’ salary range in 2020, we still considered the responsibilities of each executive officer and determined what compensation was appropriate for the positions held and expectations of services rendered during the year, while staying within Abraxas’ tightened budgetary constraints.

The base salaries paid to our named executive officers in 2020 are set forth below in the Summary Compensation Table. For 2020, base salaries, paid as cash compensation, were $832,98 with Mr. Watson receiving $382,094. We believe that the base salaries paid achieved our objectives.

Annual Bonuses. Abraxas’ Annual Bonus Plan was initially adopted by our Board of Directors in 2003. In May 2017, in connection with the Company’s annual compensation cycle, the Compensation Committee asked L&A to conduct a thorough review of the Company’s grant practices under the Annual Bonus Plan. Under the terms of the Annual Bonus Plan as approved by Abraxas’s stockholders at the annual meeting in 2014, the performance measures include:

• increases in, or levels of, net asset value (after taking the risking of reserves into account);

• net asset value per share;

• pretax earnings;

• earnings before interest and taxes;

• earnings before interest, taxes, depreciation and amortization;

• net income and/or earnings per share;

• return on equity, return on assets or net assets, return on capital (including return on total capital or return on invested capital);

• share price or stockholder return performance (including, but not limited to, growth measures and total stockholder return, which may be measured in absolute terms and/or in comparison to a group of peer companies or an index);

• oil and gas reserve replacement, reserve growth and finding and development cost targets;

• oil and gas production targets;

• performance of investments in oil and gas properties;

• cash flow measures (including, but not limited to, cash flows from operating activities, discretionary cash flows, and cash flow return on investment, assets, equity, or capital); and

• levels of operating and/or non-operating expenses.

On August 8, 2017, the Board of Directors, at the recommendation of the Compensation Committee, adjusted the eligibility, metrics and payouts associated with the Annual Bonus Plan. The adjustments became effective on January 1, 2018. Employees earning above $180,000, including all NEOs, were eligible for participation in the Annual Bonus Plan. Employees earning below $180,000 were eligible for participation at the discretion of the Compensation Committee. The target payout ranged from 50-70% of the eligible employee’s base salary depending upon the employee’s role and responsibilities. The target payout was multiplied by a target multiplier based on Company performance versus a given set of performance measures established by the Compensation Committee. There were no new adjustments made in 2018, 2019 or 2020. The Company did not establish bonus metrics for 2020. There were no bonuses paid for 2019 or 2020.

Long-Term Equity Incentives

In May 2017, the Compensation Committee retained L&A to conduct a thorough review of the Company’s grant practices under the Abraxas Petroleum Corporation Amended and Restated 2005 Employee Long-Term Equity Incentive Plan (“LTIP”). In August 2017, the Board of Directors, at the recommendation of the Compensation Committee, adjusted the eligibility, targeted vesting schedule and award requirements for the LTIP. The adjustments took effect on January 1, 2018. There have been no changes to the LTIP since its inception.

Employees, including all of the NEOs, earning above $180,000 are eligible to participate in the LTIP. Employees earning below $180,000 are eligible for participation at the discretion of the Compensation Committee. It is anticipated that awards will largely be made up of restricted stock grants. The target award for participants is 50% of the employee’s yearly salary, which can be adjusted at the Compensation Committee’s discretion. One-half of the target award vests annually over three years. Vesting of the remaining half is based on the achievement of performance goals established by the Compensation Committee.

LTIP. The LTIP, which was approved by our stockholders at the 2006 annual meeting and subsequently amended by our stockholders, authorizes us to grant incentive stock options, non-qualified stock options and shares of restricted stock to our executive officers, as well as to all employees of Abraxas. We use equity incentives as a form of long-term compensation because it provides our executive officers an opportunity to acquire an equity interest in Abraxas and further aligns their interest with those of our stockholders. Options grants generally have a term of 10 years and vest in equal increments over four years. Restricted stock grants vest in accordance with each individual grant agreement. Vesting is accelerated in certain events described under “Employment Agreements and Potential Payments Upon Termination or Change in Control.”

The purposes of the LTIP are to employ and retain qualified and competent personnel and to promote the growth and success of Abraxas, which can be accomplished by aligning the long-term interests of the executive officers with those of the stockholders by providing the executive officers an opportunity to acquire an equity interest in Abraxas. All grants are made with an exercise price of no less than 100% of the fair market value on the date of such grant.

As of December 31, 2020, a total of 183,639 shares of Abraxas common stock were reserved under the LTIP, subject to adjustment following certain events, such as stock splits. The maximum annual award for any one employee is 250,000 shares of Abraxas common stock.   If options, as opposed to restricted stock, are awarded, the exercise price shall be no less than 100% of the fair market value on the date of the award, unless the employee is awarded incentive stock options and, at the time of the award, owns more than 10% of the voting power of all classes of stock of Abraxas. Under this circumstance, the exercise price shall be no less than 110% of the fair market value on the date of the award. Option terms and vesting schedules are at the discretion of the Compensation Committee.

Employment Contracts, Change in Control Arrangements and Certain Other Matters. We provide the opportunity for our executive officers to be protected under the severance and change in control provisions contained in their employment agreements. We believe that these provisions help us to attract and retain an appropriate caliber of talent for these positions. Our severance and change in control provisions for the executive officers are summarized in “Employment Agreements and Potential Payments Upon Termination or Change in Control” below. We believe that our severance and change in control provisions are consistent with the programs and levels of severance and post-employment compensation of other companies in our industry and believe that these arrangements are reasonable.

Other Employee Benefits. Abraxas’ executive officers are eligible to participate in all of our employee benefit plans, such as medical, dental, group life and long-term disability insurance, in each case on the same basis as other employees. Abraxas’ executive officers are also eligible to participate in our 401(k) plan on the same basis as other employees. In 2008, Abraxas adopted the safe harbor provision for its 401(k) plan which requires Abraxas to contribute a fixed match to each participating employee’s contributions to the plan. The fixed match is set at the rate of dollar for dollar for the first 1% of eligible pay contributed, then 50 cents on the dollar for each additional percentage point of eligible pay contributed, up to 5%. The fixed match is contributed in the form of Abraxas common stock. An employee’s eligible pay with respect to calculating the fixed match is limited by IRS regulations. In addition, the Board of Directors, at its sole discretion, may authorize Abraxas to make additional contributions to each participating employee’s plan. The employee contribution limit for 2020 was $19,500 for employees under the age of 50 and $26,000 for employees 50 years of age or older. The Board of Directors has also suggested a cap on the amount (or percentage) of Abraxas common stock that each employee should own in their individual 401(k) account to encourage diversification. The maximum suggested percentage has been set at 20% and each employee is encouraged to reduce his or her ownership of Abraxas common stock in his or her 401(k) account in the event such employee is over the suggested limit.

Assessment of Compensation Policies and Practices

The Company and the Compensation Committee have conducted an in-depth risk assessment of the Company’s compensation policies and practices in response to public and regulatory concerns about the link between incentive compensation and excessive risk taking by companies. The Company and the Committee concluded that our compensation program does not motivate imprudent risk taking. In this regard, the Committee believes that:

• The Company’s annual incentive compensation is based on performance metrics that promote a disciplined approach towards the long-term goals of the Company;

• The Company does not offer significant short-term incentives that might drive high-risk investments at the expense of the long-term value of the Company;

• The Company’s compensation programs are weighted towards offering long-term incentives that reward sustainable performance, especially when considering the Company’s stock ownership guidelines for executive officers;

• The Company’s compensation awards are capped at reasonable levels, as determined by a review of the Company’s financial position and prospects, as well as the compensation offered by companies in our industry; and

• The Board’s high level of involvement in approving material investments and capital expenditures helps avoid imprudent risk taking.

The Company’s compensation policies and practices were evaluated to ensure that they do not foster risk taking above the level of risk associated with the Company’s business and the Company concluded that it has a balanced pay and performance program and that the risks arising from its compensation policies and practices are not reasonably likely to have a material adverse effect on the Company.

Impact of Regulatory Requirements

Deductibility of Executive Compensation. In evaluating compensation program alternatives, the Compensation Committee considered the potential impact on the Company of Section 162(m) of the Internal Revenue Code of 1986, as amended. Prior to 2018, Section 162(m) limited to $1 million the amount that a publicly traded corporation, such as the Company, may deduct for compensation paid in any year to its chief executive officer and certain other named executive officers (“covered employees”). At the time the Compensation Committee made its compensation decisions, the tax law provided that compensation which qualified as “performance-based” was excluded from the $1 million per covered employee limit if, among other requirements, the compensation was payable only upon attainment of pre-established, objective performance goals under a plan approved by our stockholders. However, this exception was repealed in the tax reform legislation signed into law on December 22, 2017. As a result, it is uncertain whether compensation that the Compensation Committee intended to structure as performance-based compensation under Section 162(m) will be deductible in the future.

Non-Qualified Deferred Compensation. On October 22, 2004, the American Jobs Creation Act of 2004 was signed into law, changing the tax rules applicable to non-qualified deferred compensation arrangements. We believe we are in compliance with the statutory provisions which were effective January 1, 2005 and the regulations which became effective on January 1, 2009. If such compensation does not comply with the tax rules applicable to non-qualified deferred compensation arrangements, then the benefits would be taxable in the first year they are not subject to a substantial risk of forfeiture and are subject to certain additional adverse tax consequences.

Accounting for Stock-Based Compensation. On October 1, 2005 we began accounting for stock-based compensation in accordance with the requirements of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 718 for all of our stock-based compensation plans. See the notes to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2020 filed with the Securities and Exchange Commission for a discussion of all assumptions made in the calculation of this amount.

Policy on Recovery of Compensation. Our Chief Executive Officer and Chief Financial Officer are required to repay certain bonuses and stock-based compensation they receive if we are required to restate our financial statements as a result of misconduct as required by Section 304 of the Sarbanes-Oxley Act of 2002.

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SUMMARY COMPENSATION TABLE

The following table sets forth a summary of compensation paid to each of our named executive officers for the last two fiscal years.

Name and Principal Position	Year	Salary ($)(1)		Bonus ($)(2)		Stock Awards ($)(3)		Option Awards ($)(4)		Non-Equity Incentive Plan Compensation ($)(5)		All Other Compensation ($)(6)		Total ($)(7)
Robert L.G. Watson................................................ President, Chief Executive Officer and Chairman of the Board	2020		382,094		—		—		—		—		12,975		395,069
	2019		531,700		—		130,000		—		—		12,800		674,500
Steven P. Harris....................................................... Vice President—Chief Financial Officer	2020		214,853		—		—		—		—		3,000		217,853
	2019		255,625		—		62,500		—		—		3,000		321,125
Kenneth W. Johnson............................................... Vice President—Operations	2020		236,042		—		—		—		—		15,261		251,303
	2019		281,187		—		68,750		—		—		12,800		362,737

(1)   The amounts in this column include any 401(k) plan account contributions made by the named executive officer.

(2)   The amounts in this column reflect discretionary bonuses. There were no discretionary bonuses in 2019 or 2020.

(3)   The amounts in this column reflect the aggregate grant date fair value of stock awards granted during a given year to the named executive officer calculated in accordance with FASB ASC Topic 718. There were no stock awards in 2019 or 2020.

(4)   The amounts in this column reflect the aggregate grant date fair value of options granted during a given year to the named executive officer calculated in accordance with FASB ASC Topic 718. There were no grants in 2019 or 2020.

(5)   The amounts included in this column for 2019 and 2020 include cash bonuses earned and paid under the Annual Bonus Plan. There were no bonuses paid for 2019 or 2020.

(6)   The amounts in this column represent contributions by Abraxas to the named executive officer’s 401(k) plan and health savings accounts for  2019 and 2020 as well as a $4,000 vehicle allowance for Mr. Johnson in 2020.

(7)   The dollar value in this column for each named executive officer represents the sum of all compensation reflected in the previous columns.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END

The following table provides information concerning outstanding equity awards at December 31, 2020 for our named executive officers.

	Option Awards				Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) (Exercisable)	Number of Securities Underlying Unexercised Options (#) (Unexercisable)(1)	Option Exercise Price ($)	Option Expiration Date	Number of Shares of Stock That Have Not Vested (#)(2)	Market Value of Shares of Units of Stock That Have Not Vested ($)(3)	Equity Incentive  Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)(2)	Equity Incentive  Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)(3)
Robert L.G. Watson.....	3,000	—	94.40	03/15/2021
	1,000	—	74.80	03/08/2022
	2,100	—	47.80	05/14/2023
	2,300	—	63.00	03/11/2024
	15,000	—	63.20	03/03/2025
	20,750	—	19.40	03/15/2026
					875	1,925	2,626	5,777
					3,234	7,115	4,851	10,672
Steven P. Harris...........	2,500	2,500	53.40	06/20/2028
					1,250	2,750	—	—
					1,555	3,421	2,333	5,133
Kenneth W. Johnson....	7,500	—	94.40	03/15/2021
	475	—	74.80	03/08/2022
	1,075	—	47.80	05/14/2023
	1,150	—	63.00	03/11/2024
	1,250	—	71.00	08/09/2021
	3,850	—	19.40	03/15/2026
					2,212	4,866	1,366	3,005
					1,710	3,762	2,566	5,645

(1)   Options vest in twenty-five percent (25%) increments each year for four (4) years on the anniversary of the grant date.

(2)   For awards granted before January 1, 2018, stock awards vest in 25% increments each year for four years on the anniversary of the grant date. Starting January 1, 2018, the vesting schedule for all restricted stock awards changed to 33.3% each year for three years with the remainder vesting upon achievement of performance goals established by the Compensation Committee.

(3)   The market value was calculated based on the closing price of Abraxas’ common stock on December 31, 2020 of $2.20 per share multiplied by the number of shares of stock that had not vested as of December 31, 2020.

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Stock Ownership Guidelines

Abraxas’ Board has established stock ownership guidelines to strengthen the alignment of director and executive officer interests with those of our stockholders. As of December 31, 2020, we had nine non-employee directors and eight executive officers subject to the stock ownership guidelines. Under the guidelines below, each director and officer is precluded from selling any shares of Abraxas common stock until the director or officer satisfies the ownership guidelines set forth in the following table. Satisfaction of the ownership guidelines will fluctuate with the market value of Abraxas common stock.

Position	Stock Ownership Guidelines
Chief Executive Officer	5x annual base salary
All other Executive Officers	3x annual base salary
Non-employee Directors	3x all fees received during the prior 12-month period, including the value of common shares awarded in lieu of cash payments at the time of issuance

Abraxas’ Board has discretion to review special situations; however, non-compliance without board approval can result in the loss of future bonuses and discretionary stock-based compensation. As of December 31, 2020, the market value of Abraxas common stock was $2.20 per share. As an example, Mr. Watson, our chief executive officer, is required to own 1,217,273 shares of Abraxas common stock to meet the stock ownership guidelines at this price. As of December 31, 2020, none of the NEO’s or directors satisfied the minimum stock ownership guidelines.

Policies Against Hedging and Pledging Stock

Our NEOs and directors are prohibited from engaging in hedging transactions that are designed to hedge or offset a decrease in market value of such person’s Common Stock in the Company. We believe that such conduct could cause an NEO or director to no longer have the same objectives as the Company’s other stockholders because these types of transactions could reduce the full risks of stock ownership. In addition, our NEOs and directors may not pledge Company securities as collateral for any other loan.

The Company’s Code of Business Conduct and Ethics, which was updated in 2018 contains a policy on insider trading. The policy states that employees, officers and directors who have access to confidential information are not permitted to use or share that information for stock trading purposes or for any other purpose except the conduct of our business. All non-public information about the Company should be considered confidential information. To use non-public information for personal financial benefit or to “tip” others who might make an investment decision on the basis of this information is not only unethical but also illegal. If you have any questions, please consult the Company’s policy on insider trading.

Compensation of Directors

All compensation paid to directors is limited to non-employee directors. We use a combination of cash and stock-based incentive compensation to attract and retain qualified individuals to serve on the Board.

Compensation. During 2020, each director was paid $1,000 for each board meeting attended and $1,000 for each committee meeting attended. The chairman of the Audit Committee received an additional annual fee of $7,875, the chairman of the Compensation Committee received an additional annual fee of $3,975 and the chairman of the Nominating and Governance Committee received an additional annual fee of $1,050. Directors were not paid a retainer in 2020.

Stock Options. Historically, Abraxas has awarded each director stock options, depending on each director’s length of service, with exercise prices equal to the prevailing market prices at the time of issuance, ranging from $19.80 to $107.60 per share. Each year at the first regular board meeting following the annual meeting, Abraxas awarded each director 1,250 options, in accordance with the terms of the Amended and Restated Abraxas Petroleum Corporation 2005 Non-Employee Directors Long-Term Equity Incentive Plan (the “Directors Plan”). Option grants were discontinued beginning in 2019 and replaced with restricted stock grants.

The Directors Plan currently reserves 70,698 shares of Abraxas common stock, subject to adjustment following certain events, such as stock splits. The maximum annual award for any one director is 25,000 shares. The exercise price of all options awarded is no less than 100% of the fair market value on the date of the award while the option terms and vesting schedules are at the discretion of the Compensation Committee.

Unless otherwise provided in the applicable award agreement, vested awards granted under the Directors Plan shall expire, terminate, or otherwise be forfeited as follows:

• three months after the date the Company delivers a notice of termination of a participant’s active status, other than in circumstances covered by the following three circumstances:

• immediately upon termination for misconduct;

• 12 months after the date of death; and

• 36 months after the date on which the director ceased performing services as a result of retirement.

The following table sets forth a summary of compensation for the fiscal year ended December 31, 2020 that Abraxas paid to each director. Abraxas does not sponsor a pension benefits plan, a non-qualified deferred compensation plan or a non-equity incentive plan for its directors; therefore, these columns have been omitted from the following table. Except for reimbursement of travel expenses to attend board and committee meetings, no other or additional compensation for services were paid to any of the directors.

Restricted Stock. Beginning in 2019, Abraxas quit awarding stock options and instead granted shares of restricted stock. Restricted stock was awarded in shares with a market value at the time of the grant equal to $12,000. The restricted shares vest over a three year period, one third per year from the date of the grant. In 2019 each director was granted 462 shares at the closing price on the date of the grant of $26.00. There were not any restricted stock awards awarded to directors in 2020.

Director Compensation Table

Name	Fees Earned or Paid in Cash ($)(1)	Restricted Stock Awards ($)(2)	Total ($)(3)
Ralph F. Cox........................................................................................................................................................	8,975	—	8,975
Brian L. Melton...................................................................................................................................................	13,875	—	13.875
Angela A. Steffen Meyer...................................................................................................................................	6,050	—	6,050

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(1)   This column represents the amounts paid in cash to each director.

(2)   The amounts in this column reflect the aggregate grant date fair value of restricted stock granted in 2020 to each director calculated in accordance with FASB ASC Topic 718. See the notes to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2020 filed with the Securities and Exchange Commission for a discussion of all assumptions made in the calculation of this amount.

(3)   The dollar value in this column for each director represents the sum of all compensation reflected in the previous columns.

The following table provides information concerning outstanding equity awards at December 31, 2020 for our directors:

Outstanding Equity Awards at Fiscal Year End Table

	OPTION AWARDS			STOCK AWARDS
Name	Number of Securities Underlying Unexercised Options (Exercisable)	Number of Securities Underlying Unexercised Options (Unexercisable)(1)	Option Exercise Price ($)	Number of Shares of Stock That Have Not Vested (#)(2)	Market Value of Shares of Units of Stock That Have Not Vested ($)(3)
Ralph F. Cox....................................................................................	500		55.00	308	678
	500		90.20
	500		86.40
	500		90.00
	2,500		19.80
	500		21.20
	500		47.20
	525		82.60
	600		58.00
	600		47.80
	600		107.60
	1.250		73.20
	1.250		26.80
	1.250		37.40
	1.250		57.40
Brian L. Melton...............................................................................	500		47.20	308	678
	525		82.60
	600		58.00
	600		47.80
	600		107.60
	1,250		73.20
	1,250		26.80
	1,250		37.40
	1,250		57.40
Angela A. Steffen Meyer..............................................................	—	—	—	308	678

(1)   The options awarded to each non-employee director at the first regular board meeting following the annual meeting vest immediately. Other option awards vest in twenty-five percent (25%) increments each year for four (4) years on the anniversary of the grant date.

(2)   For awards granted after January 1, 2018, the vesting schedule for all restricted stock awards changed to 33.3% each year for three years.

(3)   The market value was calculated based on the closing price of Abraxas’ common stock on December 31, 2020 of $2.20 per share multiplied by the number of shares of stock that had not vested as of December 31, 2020.

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Compensation Committee Interlocks and Insider Participation

Messrs. Cox, Carter and Melton and Dr.. Meyer served on the Compensation Committee during 2020. No member of the Compensation Committee was at any time during 2020, or at any other time, an officer or employee of Abraxas, and no member had any relationship with Abraxas requiring disclosure as a related-party transaction in the section “Certain Relationships and Related Party Transactions” of Item 13 of this annual report. No executive officer of Abraxas has served on the Board of Directors or Compensation Committee of any other entity that has or has had one or more executive officers who served as a member of the Board of Directors or the Compensation Committee during 2020.

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

Securities Holdings of Principal Stockholders, Directors, and Officers

Based upon information received from the persons concerned, each person known to Abraxas to be the beneficial owner of more than five percent of the outstanding shares of common stock of Abraxas, each director and nominee for director, each of the executive officers and all directors and officers of Abraxas as a group, owned beneficially as of April 30, 2021, the number and percentage of outstanding shares of common stock of Abraxas indicated in the following table. Abraxas’ Board has adopted stock ownership guidelines. Except as otherwise noted below, the address for each of the beneficial owners is c/o Abraxas Petroleum Corporation, 18803 Meisner Drive, San Antonio, Texas 78258. Please read “Executive Compensation – Stock Ownership Guidelines.” None of the shares listed below have been pledged as security.

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Equity Compensation Plan Information

The following table gives aggregate information regarding grants under all of Abraxas’ equity compensation plans through April 26, 2020.

Name of Beneficial Owner	Number of Shares(1)	Percentage (%)
Robert L.G. Watson..................................................................................................................................	94,810(2)	1.1%
Steven P. Harris.........................................................................................................................................	4,823(3)	*
Peter A. Bommer.......................................................................................................................................	21,987(4)	*
Tod A. Clarke............................................................................................................................................	10,983(5)	*
Kenneth W. Johnson.................................................................................................................................	22,745(6)	*
G. William Krog, Jr..................................................................................................................................	12,979(7)	*
Harold D. Carter........................................................................................................................................	20,643(8)	*
Ralph F. Cox..............................................................................................................................................	34,161(9)	*
Dennis E. Logue........................................................................................................................................	17,727(10)	*
Brian L. Melton.........................................................................................................................................	10,001(11)	*
Angela A. Steffen Meyer.........................................................................................................................	462(12)
All Officers and Directors as a Group (18 persons)............................................................................	251,321	3.0%
Angelo, Gordon & Co, L.P......................................................................................................................	1,672,289(13)	16.6%

*      Less than 1%

(1)   Unless otherwise indicated, all shares are held directly with sole voting and investment power.

(2)   Includes 1,617 restricted shares subject to vesting and 13,966 shares in a retirement account.

(3)   Includes 2,027 restricted shares subject to vesting.

(4)   Includes 855 restricted shares subject to vesting and 4,097 shares in a retirement account.

(5)   Includes 777 restricted shares subject to vesting and 3,696 shares in a retirement account.

(6)   Includes 2,615 restricted shares subject to vesting and 3,765 shares in a retirement account.

(7)   Includes 718 restricted shares subject to vesting and 3,663 shares in a retirement account.

(8)   Includes 9,825 shares issuable upon exercise of vested options granted pursuant to the Directors Plan (as defined on page 27), 379 shares in a family trust and 2,130 shares in a retirement account. Mr. Carter resigned from the board effective March 24, 2020, but remained as an uncompensated Advisory Director.

(9) Includes 12,825 shares issuable upon exercise of vested options granted pursuant to the Directors Plan, and 308 restricted shares subject to vesting.

(10) Includes 12,825 shares issuable upon exercise of vested options granted pursuant to the Directors Plan.

(11) Includes 7,825 shares issuable upon exercise of vested options granted pursuant to the Directors Plan and 308 restricted shares subject to vesting.

(12) Includes 462 restricted shares subject to vesting.

(13) Information related to this stockholder is based on the stockholder’s Schedule 13D filed with the Securities and Exchange Commission on August 21, 2020. The Schedule 13 D was filed by: (i) Angelo, Gordon & Co., L.P., a Delaware limited partnership (“Angelo Gordon”), (ii) AG Partners, LLC, a Delaware limited liability company (“AG Partners”), (iii) JAMG LLC, a Delaware limited liability company (“JAMG”), (iv) Michael L. Gordon and (v) AG Energy Funding, LLC (“AG Energy Funding”, and collectively with Angelo Gordon, AG Partners, JAMG and Mr. Gordon, the “Reporting Persons”). The number of shares reflected in the table as being beneficially owned by Angelo Gordon represent 1,672,290 shares of Common Stock underlying a warrant held directly by AG Energy Funding. Angelo Gordon, in its capacity as manager to AG Energy Funding, has sole power to vote all shares of the Common Stock underlying warrants to purchase Common Stock held by AG Energy Funding and to dispose of all shares of Common Stock underlying warrants to purchase Common Stock held by AG Energy.

Equity Compensation Plan Information

The following table gives aggregate information regarding grants under all of Abraxas’ equity compensation plans through December 31,2020.

Plan Category	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights	Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans
Equity compensation plans approved by security holders....................................................................................	195,180	$       49.69	254,337
Equity compensation plans not approved by security holders....................................................................................	—	—	—

Employment Agreements and Potential Payments Upon Termination or Change in Control

Abraxas has entered into employment agreements with each of our named executive officers pursuant to which each will receive compensation as determined from time to time by the Board in its sole discretion. Abraxas has also established the Abraxas Petroleum Corporation Severance Plan, effective December 31, 2008, for all employees who are not subject to an employment agreement. This plan provides severance benefits in the event of a change in control and for certain other changes in conditions of employment. The affected employees would be entitled to receive one month of base salary for each year of service with Abraxas, up to a maximum of 12 months.

The employment agreements for Messrs. Watson, Harris, and Johnson are scheduled to terminate on December 31, 2021, and are automatically extended for an additional year if by December 1 neither Abraxas nor Messrs. Watson, Harris, Bommer, Johnson or Wendel, as the case may be, has given notice to the contrary. In the event of a Change in Control, the term or any renewal thereof continues in effect for 36 months.

The employment agreements contain the following defined terms:

“Cause” means termination upon

(i) the willful and continued failure by the named executive officer to substantially perform his duties with Abraxas (other than any such failure resulting from his incapacity due to physical or mental illness or any such actual or anticipated failure resulting from termination by him for Good Reason) after a written demand for substantial performance is delivered to the named executive officer by the Board, which demand specifically identifies the manner in which the Board believes that he has not substantially performed his duties, or

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(ii) the willful engaging by the named executive officer in conduct which is demonstrably and materially injurious to the Company, monetarily or otherwise. The named executive officer shall not be deemed to have been terminated for Cause unless and until the named executive officer has been delivered a copy of a resolution duly adopted by the affirmative vote (which cannot be delegated) of not less than a majority of the members of the Board who are not officers of the Company at a meeting of the Board called and held for such purposes (after reasonable notice to the named executive officer and an opportunity for the named executive officer, together with the named executive officer’s counsel, to be heard before the Board), finding that in the good faith opinion of the Board, the named executive officer was guilty of conduct set forth in clauses (i) or (ii) above and specifying the particulars thereof in detail.

“Change in Control” means the occurrence of

(i) any “person” or “group” (as such terms are used in Section 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”)) becoming the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), except that a person shall be deemed to be the “beneficial owner” of all shares that any such person has the right to acquire pursuant to any agreement or arrangement or upon exercise of conversion rights, warrants, options or otherwise, without regard to the sixty day period referred to in such Rule), directly or indirectly, of securities representing 20% or more of the combined voting power of the Company’s then outstanding securities,

(ii) any person or group making a tender offer or an exchange offer for 20% or more of the combined voting power of the Company’s then outstanding securities,

(iii) at any time during any period of two consecutive years (not including any period prior to the execution of the employment agreement), individuals who at the beginning of such period constituted the Board and any new directors, whose election by the Board or nomination for election by the Company’s stockholders was approved by a vote of at least two-thirds (2/3) of the Company directors then still in office who either were the Company directors at the beginning of the period or whose election or nomination for election was previously so approved (“Current Directors”), ceasing for any reason to constitute a majority thereof,

(iv) the Company consolidating, merging or exchanging securities with any other entity and the stockholders of the Company immediately before the effective time of such transaction not beneficially owning, immediately after the effective time of such transaction, shares entitling such stockholders to a majority of all votes (without consideration of the rights of any class of stock entitled to elect directors by a separate class vote) to which all stockholders of the corporation issuing cash or securities in the consolidation, merger or share exchange would be entitled for the purpose of electing directors or the Current Directors immediately after the effective time of the consolidation, merger or share exchange not constituting a majority of the Board of Directors of the corporation issuing cash or securities in the consolidation, merger or share exchange, or

(v) any person or group acquiring all or substantially all of the Company’s assets.

“Disability” means the incapacity of the named executive officer due to physical or mental illness which causes the named executive officer to have been absent from the full-time performance of his duties with the Company for six consecutive months, and within 30 days after the Company gives the named executive officer written notice of termination, the named executive officer has not returned to the full-time performance of his duties.

“Good Reason” means, without the named executive officer’s express written consent, any of the following:

(i) a material adverse alteration in the nature or status of his position, duties or responsibilities from those in effect immediately prior to a Change in Control, other than any such alteration primarily attributable to the fact that the Company may no longer be a public company or may be a subsidiary of another entity,

(ii) a reduction in his current annual base salary as in effect immediately prior to the Change in Control or as the same may be increased from time to time,

(iii) a change in the principal place of his employment, as in effect at the time of a Change in Control, to a location more than fifty (50) miles from such principal place of employment, excluding required travel on the Company’s business to an extent substantially consistent with Employee’s business travel obligations as of the date of the agreement,

(iv) the failure by the Company, without his consent, to pay to him any portion of his current compensation, or to pay to him any portion of any deferred compensation, within ten (10) days of the date any such compensation payment is due,

(v) the failure by the Company to continue in effect any compensation plan in which he participates, or any substitute plans adopted prior to the Change in Control, unless an equitable arrangement (embodied in an ongoing substitute or alternative plan) has been made with respect to such plan in connection with the Change in Control, or the failure by the Company to continue his participation therein on the same basis, both in terms of the amount of benefits provided and the level of his participation relative to other participants, as existed at the time of the Change in Control,

(vi) the failure by the Company to continue to provide him with benefits at least as favorable to those enjoyed by him under any of the Company’s pension, life insurance, medical, health and accident, disability, deferred compensation or savings plans in which he is currently participating, the taking of any action by the Company which would directly or indirectly materially reduce any of such benefits or deprive him of any material fringe benefit enjoyed by him, or the failure by the Company to provide him with the number of paid vacation days to which he is entitled on the basis of the Company’s practice with respect to him as in effect at the time of the Change in Control,

60

(vii) the failure of the Company to obtain a satisfactory agreement from any successor to assume and agree to perform his employment agreement, or

(viii) any purported termination of his employment which is not effected pursuant to the employment agreement’s termination provisions.

“Retirement” means termination in accordance with the Company’s retirement policy, generally applicable to its salaried employees or in accordance with any retirement arrangement established with the named executive officer’s consent with respect to himself.

If, following a Change in Control, an officer’s employment is terminated by the Company other than for Cause or Disability, by reason of the officer’s death or Retirement, or by such officer for Good Reason, then such terminated officer will be entitled to the following a lump sum payment equal to three times his annual base salary.

If any lump sum payment to an named executive officer would individually or together with any other amounts paid or payable constitute a would constitute a “parachute payment” (as defined in Section 280G(b)(2) of the Internal Revenue Code of 1986, as amended (the “Code”)) (the “Parachute Payments”) which will be subject to the excise tax imposed under Section 4999 of the Code (the “Excise Tax”), then the total amounts received by the named executive officer from the Company which constitute Parachute Payments shall be reduced to an amount equal, in the aggregate, to one dollar ($1.00) less than three (3) times the named executive officer’s base amount (as defined in Section 280G of the Code) so that no portion of the Parachute Payments received by the named executive officer shall be subject to the Excise Tax, if and only if (i) such reduction in the Parachute Payments produces a better net after-tax position (taking into account any applicable Excise Tax under Section 4999 of the Code and any applicable income tax) than the total payment provided for herein and (ii) there are no other amounts receivable by the named executive officer from the Company which, by their terms, may not be reduced such that no portion of such amounts received by the named executive officer shall be subject to the Excise Tax.

In addition, unvested options and restricted stock that have been awarded to our named executive officers will vest upon any change in control. As of December 31, 2019, our named executive officers held 279,250 unvested options, none of which were “in-the-money”. Additionally, our named executive officers held 495,709 shares of restricted stock on that date, which were unvested.

The following table provides information concerning termination and change in control payments to each of our named executive officers as if the event occurred on December 31, 2020.

Termination and Change in Control Payments Table

Name	Type of Benefit	Before Change in Control Termination w/o Cause or for Good Reason ($)	After Change in Control Termination w/o Cause or for  Good Reason ($)(1)	Voluntary Termination ($)	Death / Disability ($)	Change in Control ($)(2)
Robert L.G. Watson.......	Severance pay	—	1,606,800	—	—	1,606,800
	Option acceleration	—	—	—	—	—
	Restricted stock acceleration		9,040	—	9,040	9,040
	Total		1,615,840	—	9,040	1,615,840
Steven P. Harris..............	Severance pay	—	772,500	—	—	772,500
	Option acceleration	—	—	—	—	—
	Restricted stock acceleration		6,171	—	6,171	6,171
	Total		778,671	—	6,171	778,671
Kenneth W. Johnson......	Severance pay	—	849,750	—	—	849,750
	Option acceleration	—	—	—	—	—
	Restricted stock acceleration		8,628	—	8,628	8,628
	Total		858,378	—	8,628	858,378

(1)   These amounts reflect a lump sum payment equal to 3.0x the named executive officer’s annual base salary as of December 31, 2018. There were no vested or unvested  “in-the-money” options for the named executive officers at December 31, 2019. Our named executive officers held 495,709 shares of restricted stock valued at the fair market value as of December 31, 2019.

(2)   The amounts on the severance pay row reflect a 36-month extension of each named execution officer’s employment agreement based on the named executive officer’s base salary on December 31, 2019 and would be paid over the extension period. Our named executive officers held 495,709 shares of restricted stock valued at the fair market value as of December 31, 2019.

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

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

General

On February 21, 2007, the Board of Directors adopted a formal written related person transaction approval policy, which sets out Abraxas’ policies and procedures for the review, approval, or ratification of “related person transactions.” For these purposes, a “related person” is a director, nominee for director, executive officer, or holder of more than 5% of our common stock, or any immediate family member of any of the foregoing. This policy applies to any financial transaction, arrangement or relationship or any series of similar financial transactions, arrangements or relationships in which Abraxas is a participant and in which a related person has a direct or indirect interest, other than the following:

• payment of compensation by Abraxas to a related person for the related person’s service in the capacity or capacities that give rise to the person’s status as a “related person;”

• transactions available to all employees or all stockholders on the same terms;

• purchases of supplies from Abraxas in the ordinary course of business at the same price and on the same terms as offered to any other purchasers, regardless of whether the transactions are required to be reported in Abraxas’ filings with the SEC; and

• transactions which when aggregated with the amount of all other transactions between the related person and Abraxas involve less than $10,000 in a fiscal year.

Our Audit Committee is required to approve any related person transaction subject to this policy before commencement of the related person transaction, provided that if the related person transaction is identified after it commences, it shall be brought to the Audit Committee for ratification, amendment or rescission. The chairman of our Audit Committee has the authority to approve or take other actions in respect of any related person transaction that arises, or first becomes known, between meetings of the Audit Committee, provided that any action by the chairman must be reported to our Audit Committee at its next regularly scheduled meeting.

Our Audit Committee will analyze the following factors, in addition to any other factors the members of the Audit Committee deem appropriate, in determining whether to approve a related person transaction:

• whether the terms are fair to Abraxas;

• whether the transaction is material to Abraxas;

• the role the related person has played in arranging the related person transaction;

• the structure of the related person transaction; and

• the interest of all related persons in the related person transaction.

Related Party Transactions

There have been no related party transactions since January 1, 2020.    

Our Audit Committee may, in its sole discretion, approve or deny any related person transaction. Approval of a related person transaction may be conditioned upon Abraxas and the related person following certain procedures designated by the Audit Committee.

Director Independence

The Board of Directors has determined that each of the following members of the Board of Directors is independent as determined in accordance with the listing standards of The NASDAQ Stock Market and Rule 10A-3 of the Exchange Act:  Ralph F. Cox, Brian L. Melton, and Angela A. Meyer. All of the members of the Audit, Compensation and Nominating and Corporate Governance Committees are independent as determined in accordance with the listing standards of The NASDAQ Stock Market and Rule 10A-3 of the Exchange Act. The Board of Directors periodically conducts a self-evaluation on key Board and committee-related issues, which has proven to be a beneficial tool in the process of continuous improvement in the Board’s functioning and communication.

Item 14. Principal Accountant Fees and Services

PRINCIPAL AUDITOR FEES AND SERVICES

Audit Fees. The aggregate fees billed by  ADKF for professional services rendered for the audit of Abraxas’ annual financial statements for the year ended December 31, 2020, the reviews of the condensed consolidated financial statements included in Abraxas’ quarterly reports on Form 10-Q for the year ended December 31, 2020, and the preparation and delivery of consents, comfort letters and other similar documents, were $235,000.

Audit-Related Fees. The aggregate fees billed by ADKF for assurance and related services that were reasonably related to the performance of the audit or review of Abraxas’ financial statements which are not reported in “audit fees” above, for the year ended December 31, 2020 were $0.

Tax Fees. The aggregate fees billed by  ADKF for professional services rendered for tax compliance, tax advice or tax planning for the year ended December 31, 2020 were $0.

All Other Fees. The aggregate fees billed by ADKF for other services, exclusive of the fees disclosed above relating to financial statement audit and audit-related services and tax compliance, advice or planning, for the year ended December 31, 2020, were $0.

Consideration of Non-audit Services Provided by the Independent Registered Public Accounting Firm. The Audit Committee has considered whether the services provided for non-audit services are compatible with maintaining ADKF’s independence, and has concluded that the independence of such firm has been maintained.

AUDIT COMMITTEE PRE-APPROVAL POLICY

The Audit Committee’s policy is to pre-approve all audit, audit-related and non-audit services provided by the independent registered public accounting firm. These services may include audit services, audit-related services, tax services and other services. The Audit Committee approved all of the fees described above. The Audit Committee may also pre-approve particular services on a case-by-case basis. The independent registered public accounting firm is required to periodically report to the Audit Committee regarding the extent of services provided by the independent registered public accounting firm in accordance with such pre-approval. The Audit Committee may also delegate pre-approval authority to one or more of its members. Such member(s) must report any decisions to the Audit Committee at the next scheduled meeting.

61

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)1. Consolidated Financial Statements

	Page
Report of Independent Registered Public Accounting Firm on  Consolidated Financial Statements		63
Report of Independent Registered Public Accounting Firm on  Consolidated Financial Statements		F-3
Consolidated Balance Sheets at December 31, 2019 and 2020		F-3
Consolidated Statements of Operations for the years ended December 31, 2019 and 2020		F-5
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2019 and 2020		F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2019 and 2020		F-7
Notes to Consolidated Financial Statements		F-8

(a)2. Financial Statement Schedules

All schedules have been omitted because they are not required, not applicable, or the information required is included in the Consolidated Financial Statements or related notes thereto.

(a)3. Exhibits

The following Exhibits have previously been filed by the Registrant or are included following the Index to Exhibits.

Exhibit

Number Description

3.1 Articles of Incorporation of Abraxas dated August 30, 1990. (Filed as Exhibit 3.1 to our Registration Statement on Form S-4, No. 33-36565. (the “S-4 Registration Statement”)).

3.2 Articles of Amendment to the Articles of Incorporation of Abraxas dated October 22, 1990. (Filed as Exhibit 3.3 to the S-4 Registration Statement).

3.3 Articles of Amendment to the Articles of Incorporation of Abraxas dated December 18, 1990. (Filed as Exhibit 3.4 to the S-4 Registration Statement).

3.4 Articles of Amendment to the Articles of Incorporation of Abraxas dated June 8, 1995. (Filed as Exhibit 3.4 to our Registration Statement on Form S-3, No. 333-00398).

3.5 Articles of Amendment to the Articles of Incorporation of Abraxas dated as of August 12, 2000. (Filed as Exhibit 3.5 to our Annual Report on Form 10-K filed on April 2, 2001).

3.6 Certificate of Correction dated February 24, 2011 (Filed as Exhibit 3.6 to our Annual Report on Form 10-K filed on March 15, 2012).

3.7 Certificate of Withdrawal dated March 16, 2015. (Filed as Exhibit 3.6 to our Current Report on Form 8-K filed March 17, 2015).

3.8 Certificate of Amendment to Articles of Incorporation dated May 9, 2017. (Filed as Exhibit 3.1 to our Current Report on Form 8-K filed on May 10, 2017).

3.9 Amended and Restated Bylaws of Abraxas. (Filed as Exhibit 3.1 to our Current Report on Form 8-K filed on December 18, 2018).

4.1 Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to the S-4 Registration Statement).

4.2 Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2 to our Annual Report on Form 10-K filed on March 31, 1995).

4.3 Description of Securities (Filed as Exhibit 4.3 to our annual report on Form 10-K filed on June 26, 2020).

*10.1 Abraxas Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as Exhibit 10.4 to our Registration Statement on Form S-4, No. 333-18673 filed on December 23, 1996).

*10.2 Form of Indemnity Agreement between Abraxas and each of its directors and officers. (Filed as Exhibit 10.4 to our Annual Report on Form 10-K filed March 14, 2007).

*10.3 Form of Employment Agreement for Executive Officers (Filed as Exhibit 10.1 to our Current Report on Form 8-K filed on December 18, 2018).

*10.5 Amended and Restated Abraxas Petroleum Corporation Non-Employee Directors Long-Term Equity Incentive Plan. (Filed as Appendix B to our Proxy Statement filed on April 2, 2015).

62

*10.6 Form of Stock Option Agreement under the Abraxas Petroleum Corporation Amended and Restated 2005 Non-Employee Directors Long-Term Equity Incentive Plan. (Filed as Exhibit 10.2 to our Current Report on Form 8-K filed June 6, 2005).

*10.7 Abraxas Petroleum Corporation Senior Management Incentive Bonus Plan 2006. (Filed as Exhibit 10.17 to our Annual Report on Form 10-K filed March 23, 2006).

*10.8 Amended and Restated Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan. (Filed as Appendix A to our Proxy Statement filed on April 3, 2017).

*10.9 Form of Employee Stock Option Agreement under the Amended and Restated Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan. (Filed as Exhibit 10.2 to our Current Report on Form 8-K filed May 26, 2006).

*10.10 Form of Restricted Stock Agreement under the Amended and Restated Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan (Filed as Exhibit 10.1 to our Annual Report on Form 10-K filed on March 13, 2015).

*10.11 Form of Restricted Stock Award Agreement under Abraxas Petroleum Corporation Amended and Restated 2005 Employee Long-Term Equity Incentive Plan. (Filed as Exhibit 10.1 to our Current Report on Form 8-K filed on April 6, 2018).

10.13 Promissory Note dated November 13, 2008 by Abraxas Properties Incorporated and Abraxas Petroleum Corporation, payable to the order of Plains Capital Bank, as Lender. (Filed as Exhibit 10.1 to our Current Report on Form 10-Q filed on August 8, 2014.)

10.14 Second Modification, Renewal and Extension of Promissory Note and Deed of Trust Liens by and between Plains Capital Bank, Abraxas Properties Corporation and Abraxas Petroleum Corporation effective March 13, 2013. (Previously filed as Exhibit 10.2 to our Current Report on Form 10-Q filed on August 8, 2014).

10.15 Third Modification, Renewal and Extension of Promissory Note and Deed of Trust Liens by and between Plains Capital Bank, Abraxas Properties Incorporated and Abraxas Petroleum Corporation effective as of July 13, 2013. (Previously filed as Exhibit 10.3 to our Current Report on Form 10-Q filed on August 8, 2014).

10.16 Amendment No. 2 to Third Amended and Restated Credit Agreement dated as of April 20, 2016 among Abraxas Petroleum, as Borrower, the lenders party thereto and Société Générale, as Administrative Agent and as Issuing Lender (Previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on April 20, 2016).

10.17 Amendment No. 3 to Third Amended and Restated Credit Agreement dated as of May 16, 2017 among Abraxas Petroleum, as Borrower, the lenders party thereto and Société Générale, as Administrative Agent and as Issuing Lender. (Previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on May 17, 2017).

10.18 Master Assignment and Acceptance Agreement, Waiver, and Amendment No. 9 to Third Amended and Restated Credit Agreement dated as of November 13, 2019 among Abraxas Petroleum, as Borrower, the lenders party thereto and Société Générale, as Administrative Agent and as Issuing Lender. (Previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on November 19, 2019).

10.19 $100,000,000 Term Loan Credit Agreement dated as of November 13, 2019, among Abraxas Petroleum Corporation, as Borrower, the lenders party thereto and Angelo Gordon Energy Servicer, LLC, as Administrative Agent and as Sole Lead Arranger and Sole Bookrunner (previously filed as Exhibit 10.2 to our Current Report on Form 8-K filed on November 11, 2019).

10.20 Intercreditor Agreement dated November 13, 2019, among Abraxas Petroleum Corporation, as Borrower, the other grantors party thereto Société Générale, as Senior Representative for the Senior Secured Parties and Angelo Gordon Energy Servicer, LLC, as Junior Representative for the Junior Secured Parties (previously filed as Exhibit 10.3 to our Current Report on Form 8-K filed November 19, 2019).

10.21 Waiver and Amendment No. 10 to Third Amended and Restated Agreement dated as of June 25, 2020, among Abraxas Petroleum Corporation, as Borrower, the lenders party thereto and Société Générale, as Administrative Agent and as Issuing Lender (Previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on June 26, 2020). 

10.22 Waiver and Second Amendment to Term Loan Credit Agreement dated as of June 25, 2020, among Abraxas Petroleum Corporation, as Borrower, the lenders party thereto and Angelo Gordon Energy Servicer, LLC, as Administrative Agent and as Sole Lead Arranger and Sole Bookrunner (Previously filed as Exhibit 10.2 to our Current Report on Form 8-K filed on June 26, 2020).  

10.23 Fee Letter Agreement dated as of June 25, 2020, among Abraxas Petroleum Corporation, as Borrower and Angelo Gordon Energy Servicer, LLC, as Administrative Agent for account of the lenders to the Waiver and Second Amendment to Term Loan Credit Agreement (Previously filed as Exhibit 10.3 to our Current Report on Form 8-K filed on June 26, 2020).

14.1 Abraxas Petroleum Corporation Code of Business Conduct and Ethics. (Filed as Exhibit 14.1 to our Annual Report on Form 10-K filed March 22, 2006).

21.1 Subsidiaries of Abraxas. (Previously filed as Exhibit 21.1 to our Annual Report on Form 10-K filed on March 15, 2016).

23.1 Consent of ADKF PC (Filed herewith).

23.2 Consent of BDO USA, LLP (Filed herewith).

23.3	Consent of DeGolyer and MacNaughton. (Filed herewith)
31.1	Certification – Chief Executive Officer. (Filed herewith).

31.2 Certification – Chief Financial Officer. (Filed herewith).

32.1 Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).

32.2 Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).

99.1 DeGolyer and MacNaughton's report  with respect to oil and reserves of Abraxas Petroleum. (Filed herewith).

* Management Compensatory Plan or Agreement.

Item 16. 10-K Summary

None

63

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Abraxas Petroleum Corporation and Subsidiaries
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements	F-8
Report of Independent Registered Public Accounting Firm on  Consolidated Financial Statements	F-3
Consolidated Balance Sheets at December 31, 2019 and 2020	F-3
Consolidated Statements of Operations for the years ended December 31, 2019 and 2020	F-5
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2019 and 2020	F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2019 and 2020	F-7
Notes to Consolidated Financial Statements	F-8

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and
Stockholders of Abraxas Petroleum Corporation

Opinion on the Financial Statements

We have audited the accompanying balance sheet of Abraxas Petroleum Corporation (the Company) as of December 31, 2020, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended, and the related notes (collectively referred to as the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

Substantial Doubt about the Company's Ability to Continue as a 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 has not satisfied certain covenants under its first lien credit facility as of December 31, 2020 which represents an event of default.  Additionally, the company does not anticipate maintaining compliance with all of its credit facilities over the next twelve months. These matters raise substantial doubt about the Company’s ability to continue as a "going concern". Management's plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

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 audit 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 audit 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.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. Communication of the critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Impact of estimated oil and gas reserves related to proved oil and gas properties on depletion expense and the ceiling test calculation

The Company calculates depletion expense for its proved oil and gas properties using the units-of-production method whereby capitalized costs, including estimated future development costs and asset retirement costs, are amortized over total estimated proved reserves. Additionally, the Company is required to perform a ceiling test calculation on a quarterly basis to evaluate impairment of its proved oil and gas properties. For the year ended December 31, 2020, the Company recorded depletion expense related to proved oil and gas properties of $24.4 million and recorded ceiling test impairments of $187.0 million.

We identified the impact of the estimate of proved oil and gas reserves used in the determination of depletion expense and the ceiling test calculation as a critical audit matter. There is a high degree of subjectivity in evaluating the estimate of proved oil and gas reserves as auditor judgment was required to evaluate the assumptions used by the Company related to forecasts of production, future operating costs and future development costs, and oil and gas prices inclusive of market differentials.

To address this critical audit matter we performed the following procedures. (1) We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists. (2) To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. 

/s/ ADKF, P.C.

We have served as the Company’s auditor since 2020.

San Antonio, Texas

May 6, 2021

F-2

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Abraxas Petroleum Corporation

San Antonio, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of Abraxas Petroleum Corporation (the “Company”) as of December 31, 2019, the related consolidated statements of operations, stockholders’ equity, and cash flows for the year ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2019, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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

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

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

/s/ BDO USA, LLP

We began serving as the Company's auditor in 2003 and became the predecessor auditor in 2020.

San Antonio, Texas

June 26, 2020 (May 6, 2021 as to the effects of the reverse stock split described in Note 3)

F-2

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

ASSETS

	December 31,
	2019			2020
	(In thousands, except per share/share data)
Assets
Current assets:
Cash and cash equivalents	$	-		$	2,775
Accounts receivable:
Joint owners, net		2,397			1,255
Oil and gas production sales		16,985			8,794
Other		263			-
Total accounts receivable		19,645			10,049
Derivative asset - short-term		83			9,639
Other current assets		1,193			1,588
Total current assets		20,921			24,051
Property and equipment
Proved oil and gas properties, full cost method		1,162,094			1,167,333
Other property and equipment		39,295			39,456
Total		1,201,389			1,206,789
Less accumulated depreciation, depletion, amortization and impairment		(872,431	)		(1,083,843	)
Total property and equipment - net		328,958			122,946
Operating lease right-of-use assets		327			228
Derivative asset - long term		4,170			10,281
Other assets		255			255
Total assets	$	354,631		$	157,761

See accompanying notes to consolidated financial statements.

F-3

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS (CONTINUED)

LIABILITIES AND STOCKHOLDERS’ EQUITY

	December 31,
	2019			2020
	(In thousands)
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	19,280		$	6,074
Joint interest oil and gas production payable		18,050			8,795
Accrued interest		133			86
Other accrued liabilities		361			230
Derivative liabilities - short-term		10,688			480
Right of use liability		98			53
Current maturities of long-term debt		280			202,751
Other current liabilities		582			850
Total current liabilities		49,472			219,319
Long-term debt - less current maturities		192,718			2,515
Paycheck protection program loan		-			1,384
Derivative liabilities long-term		999			-
Right of use liability		203			150
Future site restoration		7,420			7,360
Total liabilities		250,812			230,728
Commitments and contingencies (Note 8)
Stockholders' Equity
Preferred stock, par value $0.01 per share - authorized 1,000,000 shares; - 0- shares issued and outstanding		-			-
Common stock, par value $0.01 per share, authorized 20,000,000 shares; 8,436,498 and 8,421,910 issued and outstanding at December 31, 2019 and 2020, respectively		84			85
Additional paid-in capital		421,740			429,475
Accumulated deficit		(318,005	)		(502,527	)
Total stockholders' equity		103,819			(72,967	)
Total liabilities and stockholders' equity	$	354,631		$	157,761

See accompanying notes to consolidated financial statements.

F-4

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS 

	Years Ended December 31,
	2019			2020
	(In thousands, except per share data)
Revenues:
Oil	$	124,503		$	41,969
Gas		2,579			586
Natural gas liquids		1,910			429
Other		154			59
Total Revenue		129,146			43,043
Operating costs and expenses
Lease operating		27,619			16,458
Production and ad valorem taxes		10,610			4,632
Rig expense		1,333			762
Depreciation, depletion, amortization and accretion		52,703			24,846
Proved property impairment		51,293			186,980
General and administrative (including stock-based compensation of $1,911 and $1,312, respectively)		11,304			8,783
Total operating costs and expenses		154,862			242,461
Operating (loss) income		(25,716	)		(199,418	)
Other (income) expense:
Interest income		(65	)		(39	)
Interest expense		12,335			21,281
Amortization of deferred financing fees		543			2,565
Loss on debt extinguishment		-			4,108
Loss (gain) on derivative contracts		26,831			(42,880	)
Loss on sale of non-oil and gas assets		33			-
Other		(389	)		69
Total other expense (income)		39,288			(14,896	)
(Loss) income before income tax		(65,004	)		(184,522	)
Income tax (expense) benefit		-			-
Net (loss) income	$	(65,004	)	$	(184,522	)
Net (loss) income per common share - basic	$	(7.82	)	$	(22.01	)
Net (loss) income per common share - diluted	$	(7.82	)	$	(22.01	)
Weighted average shares outstanding
Basic		8,312			8,382
Diluted		8,315			8,382

See accompanying notes to consolidated financial statements.

F-5

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands except number of shares)

						Additional
	Common Stock					Paid in			Accumulated
	Shares			Amount		Capital			Deficit			Total
Balance at December 31, 2018		8,354,133		$	83	$	419,428		$	(253,001	)	$	166,510
Net loss		-			-		-			(65,004	)		(65,004	)
Stock-based compensation		-			-		1,911			-			1,911
Stock options exercised		21,169			-		402			-			402
Restricted stock issued, net of forfeitures		61,196			1		(1	)		-			-
Balance at December 31, 2019		8,436,498			84		421,740			(318,005	)		103,819
Net loss		-			-					(184,522	)		(184,522	)
Warrant issued		-			-		6,424						6,424
Stock-based compensation		-			-		1,312			-			1,312
Stock options exercised		-			-		-			-			-
Restricted stock forfeitures and cancellations		(14,588	)		-		-			-			-
Balance at December 31, 2020		8,421,910		$	84	$	429,476		$	(502,527	)	$	(72,967	)

See accompanying notes to consolidated financial statements.

F-6

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended December 31,
	2019			2020
Operating Activities:
Net (loss)	$	(65,004	)	$	(184,522	)
Adjustments to reconcile net (loss) to net cash provided by operating activities:
Loss(gain) on sale of non-oil and gas assets		33			-
Net loss (gain) on derivative contracts		26,831			(42,880	)
Net cash settlements (paid) received on derivative contracts		(4,317	)		16,006
Depreciation, depletion and amortization		52,267			24,432
Proved property impairment		51,293			186,980
Amortization of deferred financing fees and issuance discount		738			3,926
Accretion of future site restoration		436			414
Loss on debt extinguishment		-			4,108
Plugging cost		(890	)		(236	)
Non-cash interest		-			12,695
Stock-based compensation		1,911			1,312
Changes in operating assets and liabilities:
Accounts receivable		19,991			9,596
Other assets		1,092			(394	)
Accounts payable		(10,491	)		(15,304	)
Accrued expenses and other		(243	)		(148	)
Net cash provided by operating activities		73,647			15,985
Investing Activities
Capital expenditures, including purchase and development of properties		(108,673	)		(12,557	)
Proceeds from the sale of oil and gas properties		23,434			-
Proceeds from the sale of non-oil and gas assets		272			-
Net cash used in investing activities		(84,967	)		(12,557	)
Financing Activities
Proceeds from exercise of stock options and restricted stock		402			-
Proceeds from long-term borrowings - First Lien Credit Facility		40,203			8,000
Proceeds from long-term borrowings - Second Lien Credit Facility		96,500			-
Proceeds from PPP loan		-			1,384
Payments of long-term borrowings		(124,692	)		(9,059	)
Deferred financing fees		(1,960	)		(978	)
Net cash provided by (used) in financing activities		10,453			(653	)
(Decrease) increase in cash and cash equivalents		(867	)		2,775
Cash and cash equivalents at beginning of period		867			-
Cash and cash equivalents at end of period	$	-		$	2,775
Supplemental disclosure of cash flow information:
Interest paid	$	12,340		$	7,174
Income tax paid	$	-		$	-
Non-cash investing and financing activities
Change in asset retirement obligation cost and liabilities	$	855		$	(22	)
Asset retirement obligations associated with dispositions	$	(473	)	$	(216	)
Change in capital expenditures included in accounts payable	$	(16,489	)	$	(7,157	)

See accompanying notes to consolidated financial statements.

F-7

ABRAXAS PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Significant Accounting Policies

Nature of Operations

We are an independent energy company primarily engaged in the acquisition, exploitation, development and production of oil and gas in the United States.  Our oil and gas assets are located primarily in two operating regions in the United States: the Rocky Mountains and Permian/Delaware Basin.

The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including Raven Drilling LLC (“Raven Drilling”).

Going Concern

Our present level of indebtedness and the recent commodity price environment present challenges to our ability to comply with certain covenants in our credit facilities and under applicable auditing standards the independent accountants' opinion on our  financial statements for the year ended December 31, 2020 contains an explanatory paragraph regarding the Company's ability to continue as a "going concern".  At December 31, 2020, we had a total of $95.0  million outstanding under our First Lien Credit Facility, $112.7 million under our Second Lien Credit facility, and total indebtedness of  $220.5 million including a $10.0 million exit fee. As of April 30, 2021, we had a total of $89.5  million outstanding under our First Lien Credit Facility,  $127.2  million under our Second Lien Credit Facility, including a  $10.0 million exit fee, and total indebtedness of $219.4 million. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements.

Specifically, with regard to our credit agreements, we did not satisfy the first lien debt to consolidated EBITDAX ratio covenant under our First Lien Credit Facility as of the December 31, 2020 measurement date and such failure represented an event of default under our First Lien Credit Facility. In addition,  we do not anticipate that we will  maintain compliance with the Second Lien Credit Facility total leverage ratio covenant or the minimum asset coverage ratio (as defined in Note 4) both of which will be  first tested as of September 30, 2021, over the next twelve months and, accordingly, the audit report prepared by our auditors with respect to the financial statements for the year ended December 31, 2020 includes an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern.” The inability to maintain compliance with certain covenants of our Second Lien Credit Facility would represent an additional default under our First Lien Credit Facility as of the end of any such future fiscal quarters. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty.

We are evaluating the available financial alternatives and are in discussion with our lenders seeking additional waivers or amendments to the covenants or other provisions of our credit facilities to address any current and future default relating to the covenants in question. The existing defaults at  March 31, 2021 are subject to forbearance agreements with our lenders that currently expire on  May 6, 2021. No assurance can be provided that the forbearance agreements will be further extended. If, upon a future default, the Company is unable reach an agreement with its lenders or find acceptable alternative financing, the lenders under the Company's First Lien Credit Facility  may choose to accelerate repayment. If the Company's lenders accelerate the payment of amounts outstanding under its credit facilities, the Company does not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so. The Company could attempt to obtain additional sources of capital from asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination thereof. However, the Company cannot provide any assurances that it will be successful in obtaining capital from such transactions on acceptable terms, or at all. 

Under applicable accounting principles these circumstances are deemed to create substantial doubt regarding the Company's ability to continue as a "going concern". The consolidated financial statements have been prepared on a "going concern" basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business for the twelve-month period following the date of issuance of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amount, or the amount and classification of liabilities that may result should the Company be unable to continue as a "going concern".

In April 2021, we received notice that certain of our hedging agreements were being terminated as a result of events of default under the First Lien Credit Facility, and we voluntarily terminated most of our other  hedging arrangements. As a result of the settlement of the terminated hedges, we have outstanding obligations of $9.9 million. The settlement values of the terminated hedges were determined at various dates between April 15 and April 30, 2021. These obligations will be added to the balance of the First Lien Credit Facility and accrue interest  at the default interest rate, currently 6.7%, until repaid. Our remaining  hedging agreements may also be terminated as a result of such events of default. The settlement of terminated hedging agreements may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. See Note 14 “Subsequent Events” for current information regarding non-compliance with certain covenants.

Rig Accounting

In accordance with SEC Regulation S-X, no income is recognized in connection with contractual drilling services performed in connection with properties in which the Company or its affiliates holds an ownership, or other economic interest. Any income not recognized as a result of this limitation is credited to the full cost pool and recognized through lower amortization as reserves are produced. During part of 2019 and all of 2020 the drilling rig was idle, accordingly the cost of the rig was charged to the statement of operations.

Use of Estimates

The consolidated financial statements of the Company have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

The most significant estimates pertain to proved oil, gas and NGL reserves and related cash flow estimates used in impairment tests of oil and gas properties, the fair value of assets and liabilities acquired in business combinations, derivative contracts, the provision for income taxes including uncertain tax positions, stock based compensation, asset retirement obligations, accrued oil and gas revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates.

The process of estimating oil and gas reserves in accordance with SEC requirements is complex and involves decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data.  Accordingly, these estimates are imprecise.  Actual future production, oil and gas prices, differentials, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated.  Any significant variance could materially affect the estimated quantities and present value of our reserves.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, our ability to fund estimated development cost, prevailing oil and gas prices and other factors, many of which are beyond our control.

Reclassifications

Certain reclassifications have been made to the prior year financial statements to conform to the current period presentation.  These reclassifications were to share and per share data related to the 1 for 20 reverse stock split effective October 19, 2020 and had no effect on our previously reported results of operations.

Concentration of Credit Risk

Financial instruments which potentially expose the Company to credit risk consist principally of trade receivables and derivative contracts.  Accounts receivable are generally from companies with significant oil and gas marketing or operating activities.  The Company performs ongoing credit evaluations and, generally, requires no collateral from its customers. The counterparties to our derivative contracts are the same financial institutions from which we have outstanding debt; accordingly, we believe our exposure to credit risk to these counterparties is currently mitigated in part by this, as well as the current overall financial condition of the counterparties.

The Company maintains any cash and cash equivalents in excess of federally insured limits in prominent financial institutions considered by the Company to be of high credit quality.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three months or less.

Accounts Receivable

Accounts receivable are reported net of an allowance for doubtful accounts of approximately $0.1 million at  December 31, 2019 and 2020 . The allowance for doubtful accounts is determined based on the Company's historical losses, as well as a review of certain accounts. Accounts are charged off when collection efforts have failed and the account is deemed uncollectible.

F- 8

 

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development and production of oil and gas with all of the Company’s operational activities being  conducted in the U.S. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long lived assets located outside the U.S.

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas properties.  Under this method, certain direct costs and indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves.  Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Costs in excess of the present value of estimated future net revenues are charged to proved property impairment expense.  No gain or loss is recognized upon sale or disposition of oil and gas properties for full cost accounting companies with proceeds accounted for as an adjustment of capitalized cost. An exception to this rule occurs when the adjustment to the full cost pool results in a significant alteration of the relationship between capitalized cost and proved reserves. The Company applies the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. The impairment calculations do not consider the impact of our commodity derivative positions as generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges.   As of  December 31, 2019 and 2020, our capitalized cost of oil and gas properties exceeded the future net revenue from our estimated proved reserves resulting in the recognition of an impairment of $51.3 million  and  $187.0  million, respectively.

Other Property and Equipment

Other property and equipment are recorded at cost.  Depreciation of other property and equipment is provided over the estimated useful lives using the straight-line method.  Major renewals and improvements are recorded as additions to the property and equipment accounts.  Repairs that do not improve or extend the useful lives of assets are expensed.

Estimates of Proved Oil and Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

• the quality and quantity of available data;

• the interpretation of that data;

• the accuracy of various mandated economic assumptions; and

• the judgment of the persons preparing the estimate.

Our proved reserve information included in this report was based on studies performed by our independent petroleum engineers assisted by the engineering and operations departments of Abraxas. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may cause material revisions to the estimate.

In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the average of oil and gas prices based on the unweighted average 12 month first-day-of-month pricing. Future prices and costs may be materially higher or lower than these prices and costs which would impact the estimated value of our reserves.

The estimates of proved reserves materially impact depreciation, depletion and amortization, or DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields.

Derivative Instruments and Hedging Activities

The Company enters into agreements to hedge the risk of future oil and gas price fluctuations.  Such agreements are typically in the form of fixed price commodity and basis swaps, which limit the impact of price fluctuations with respect to the Company’s sale of oil and gas. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions could arise where actual production is less than estimated which could result in over hedged volumes.

All derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The derivative instruments the Company utilizes are based on index prices that may and often do differ from the actual oil and gas prices realized in its operations.  These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for hedge accounting rules as prescribed by Accounting Standards Codification (“ASC”) 815. Accordingly, the Company does not account for its derivative instruments as cash flow hedges for financial reporting purposes.  Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in net gains (losses) on commodity derivative contracts in the Consolidated Statements of Operations.

F- 9

 

Fair Value of Financial Instruments

The Company includes fair value information in the notes to consolidated financial statements when the fair value of its financial instruments is materially different from the carrying value.  The carrying value of those financial instruments that are classified as current, except for derivative instruments, approximates fair value because of the short maturity of these instruments.  For noncurrent financial instruments, the Company uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments.

Share-Based Payments

  Options granted are valued at the date of grant and expense is recognized over the vesting period. The Company currently utilizes a standard option pricing model (Black-Scholes) to measure the fair value of stock options granted to employees and directors. Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such restricted stock is determined using the market price on the grant date and expense is recorded over the vesting period. For the years ended  December 31, 2019  and 2020, stock-based compensation was approximately  $1.9 million and $1.3 million, respectively.

Restoration, Removal and Environmental Liabilities

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites.  Environmental expenditures are expensed or capitalized depending on their future economic benefit.  Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.

Liabilities for expenditures of a noncapital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable.

The fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period and the capitalized cost is depreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and we amortize these costs as a component of our depletion expense in the accompanying consolidated financial statements. Each year, the Company reviews, and to the extent necessary, revises its asset retirement obligation estimates.

The following table (in thousands) summarizes changes in the Company’s future site restoration obligations during the two years ended December 31: 

	2019			2020
Beginning future site restoration obligation	$	7,492		$	7,420
New wells placed on production and other		80			43
Deletions related to property disposals		(473	)		(216	)
Deletions related to plugging costs		(890	)		(235	)
Accretion expense and other		436			414
Revisions and other		775			(66	)
Ending future site restoration obligation	$	7,420		$	7,360

Revenue Recognition and Major Purchasers

The Company recognizes oil and gas revenue from its interest in producing wells as oil and gas is sold from those wells, net of royalties, control of the product has transferred to the purchaser and collectability  is reasonably assured. The Company had no material gas imbalances at  December 31, 2019 and 2020.

During 2019 two purchasers accounted for 71% of oil and gas revenues. During 2020, four purchasers accounted for 73% of oil and gas revenues.

Deferred Financing Fees

Deferred financing fees are being amortized on the effective yield basis over the term of the related debt.

F- 10

 

Income Taxes

Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to be in effect with respect to taxable income in the years in which those temporary differences are expected to be recovered or settled. Uncertainties exist as to the future utilization of the operating loss carryforwards. Therefore, we have established a valuation allowance of $117.27 million for deferred tax assets at December 31, 2020.

Accounting for Uncertainty in Income Taxes

Evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.

Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period in which the threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not criteria should be de-recognized in the first subsequent reporting period in which the threshold is no longer met. Penalties and interest are classified as income tax expense. The Company had no uncertain income tax positions as of December 31, 2020.

Adoption of New Accounting Standards 

Effective January 1, 2020, the Company adopted Accounting Standards Update ("ASU") 2016-13 and its related amendments.  This ASU primarily applies to the Company’s accounts receivable, of which the majority are due within 30 days. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analysis. The Company develops its estimated allowance for credit losses primarily using an aging method and analysis of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.

In November 2019, the FASB issued ASU 2019-12 – Income Taxes (“Topic 740”): Simplifying the Accounting for Income Taxes. The amendments in ASU 2019-12 are part of an initiative to reduce complexity in accounting standards and simplify the accounting for income taxes by removing certain exceptions from Topic 740 and making minor improvements to the codification. ASU 2019-12 and its related amendments will be effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.

In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 840): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (“ASU 2020-04”), which provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates (e.g., London Interbank Offered Rate (“LIBOR”)) that are expected to be discontinued. ASU 2020-04 allows, among other things, certain contract modifications, such as those within the scope of Topic 470 on debt, to be accounted as a continuation of the existing contract. This ASU was effective upon the issuance and its optional relief can be applied through December 31, 2022. The Company will consider this optional guidance prospectively, if applicable.

In May 2020, the SEC adopted final rules that amend the financial statement requirements for significant business acquisitions and dispositions. Among other changes, the final rules modify the significance tests and improve the disclosure requirements for acquired or to be acquired businesses and related pro forma financial information, the periods those financial statements must cover, and the form and content of the pro forma financial information. The final rules do not modify requirements for the acquisition and disposition of significant amounts of assets that do not constitute a business. The final rules are effective January 1, 2021, but earlier compliance is permitted. The Company will consider these final rules and update its disclosures, as applicable.

F- 11

 

2. Revenue from Contracts with Customers

Revenue Recognition

Sales of oil, gas and NGL are recognized at the point in time when control of the product is transferred to the customer and collectability is reasonably assured. The Company's contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, physical location, quality of the oil or gas, and prevailing supply and demand conditions. As a result, the price of the oil, gas and NGL fluctuates to remain competitive with other available oil, gas and NGL supplies in the market. The Company believes that the pricing provisions of our oil, gas and NGL contracts are customary in the industry.

Oil sales

The Company's oil sales contracts are generally structured such that it sells its oil production to a purchaser at a contractually specified delivery point at or near the wellhead. The crude oil production is priced on the delivery date based upon prevailing index prices less certain deductions related to oil quality, physical location and transportation costs incurred by the purchaser subsequent to delivery. The Company recognizes revenue when control transfers to the purchaser upon delivery at or near the wellhead at the net price received from the purchaser. Payment terms as customarily and normally paid on the twentieth day of the month following production.

Gas and NGL Sales

Under the Company's gas processing contracts, it delivers wet gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system.  There are no performance obligations related to these contracts. The midstream processing entity processes the gas and remits proceeds to the Company based upon either (i) the resulting sales price of NGL and residue gas received by the midstream processing entity from third party customers or (ii) the prevailing index prices for NGL and residue gas in the month of delivery to the midstream processing entity. Gathering, processing, transportation and other expenses incurred by the midstream processing entity are typically deducted from the proceeds that the Company receives.

In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. With respect to the Company's gas purchase contracts, the Company has concluded that it is the agent, and thus, the midstream processing entity is its customer. Accordingly, the Company recognizes revenue upon delivery to the midstream processing entity based on the net amount of the proceeds received from the midstream processing entity.

Imbalances  

The Company had no material gas imbalances at December 31, 2019 and 2020. 

Disaggregation of Revenue

The Company is focused on the development of oil and natural gas properties primarily located in the following three operating regions in the United States: (i) the Permian/Delaware Basin, (ii) Rocky Mountain and (iii) South Texas. Revenue attributable to each of those regions is disaggregated in the table below.

	Years Ended December 31,
	2019						2020
	Oil		Gas		NGL		Oil		Gas		NGL
Operating Region
Permian/Delaware Basin	$	52,789	$	494	$	602	$	22,891	$	335	$	163
Rocky Mountain	$	68,555	$	1,480	$	1,305	$	19,078	$	251	$	266
South Texas	$	3,159	$	605	$	3	$	-	$	-	$	-

F- 12

 

Significant Judgments

Principal versus agent

The Company engages in various types of transactions in which midstream entities process the Company's gas and subsequently market resulting NGL and residue gas to third-party customers on behalf of the Company, such as the Company's percentage-of-proceeds and gas purchase contracts. These types of transactions require judgment to determine whether we are the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net.

Transaction price allocated to remaining performance obligations

A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC Topic 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC Topic 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract balances

Under the Company's product sales contracts, the Company is entitled to payment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional. The Company records invoiced amounts as “Accounts receivable - Oil and gas production sales” in the accompanying condensed consolidated balance sheet.

To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as “Accounts receivable - Oil and gas production sales” in the accompanying condensed consolidated balance sheets. In this scenario, payment is also unconditional, as the Company has satisfied its performance obligations through delivery of the relevant product. As a result, the Company has concluded that its product sales do not give rise to contract assets or liabilities under ASU 2014-09. At  December 31, 2019 and December 31, 2020, our receivables from contracts with customers were $17.0 million and $8.8 million, respectively.

Prior-period performance obligations

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

The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

3. Reverse Stock Split 

On  October 19, 2020 the Company effected a 1-for-20 reverse stock split of its issued and outstanding shares of common stock, $0.01 par value (the "Reverse Stock Split"). The Company effected the Reverse Stock Split pursuant to the Company’s filing of a Certificate of Change  with the Secretary of State of the State of Nevada on September 29, 2020. Under Nevada law, no amendment to the Company’s Articles of Incorporation was required in connection with the Reverse Stock Split. The Company was authorized to issue 400,000,000 shares of Common Stock. As a result of the Reverse Stock Split, the Company will be authorized to issue 20,000,000 shares of Common Stock.  As a result of the Reverse Stock Split, 168,069,305 outstanding shares of the Company’s common stock were exchanged for approximately 8,453,466 shares of the Company's common stock (subject to adjustment due to the effect of rounding fractional shares into whole shares). Under the terms of the Reverse Stock Split, fractional shares issuable to stockholders were rounded up to the nearest whole share. The Reverse Stock Split will not have any effect on the stated par value of the Common Stock.   All per share amounts and number of shares in the condensed consolidated financial statements and related notes have been retroactively restated to reflect the Reverse Stock Split, resulting in the transfer of $1.6 million from common stock to additional paid in capital at September 30, 2020 and   December 31, 2019.

Additionally on the effective date of the Reverse Stock Split, all options, warrants and other convertible securities of the Company outstanding immediately prior to the Reverse Stock Split were adjusted by dividing the number of shares of common stock into which the options, warrants and other convertible securities are exercisable or convertible by 20, and multiplying the exercise or conversion price thereof by 20, all in accordance with the terms of the plans, agreements or arrangements governing such options, warrants and other convertible securities and subject to rounding to the nearest whole share.

4. Long-Term Debt

The following sections regarding the First Lien Credit Facility and Second Lien Credit Facility are qualified in their entirety by the disclosure contained in Note 1. Going Concern, which is expressly incorporated in the sections above.  Due to certain of covenant violations under our credit facilities as of December 31, 2020, and the potential for future violations, all of the debt related to our credit facilities has been classified as current liabilities.

The following is a description of the Company’s debt as of  December 31, 2019 and 2020, respectively:

	Years Ended December 31,
	2019			2020
	(In thousands)
First Lien Credit Facility	$	95,778		$	95,000
Second Lien Credit Facility		100,000			112,695
Exit fee - Second Lien Credit Facility		-			10,000
Real estate lien note		3,091			2,810
		198,869			220,505
Less current maturities		(280	)		(202,751	)
		198,589			17,754
Deferred financing fees and debt issuance cost - net		(5,871	)		(15,239	)
Total long-term debt, net of deferred financing fees and debt issuance costs	$	192,718		$	2,515

Maturities of long-term debt are as follows:

Years ending December 31, (In thousands)
2021	$	217,990
2022		310
2023		2,205
2024		-
2025		-
Thereafter		-
Total	$	220,505

First Lien Credit Facility

The Company has a senior secured First Lien Credit Facility with Société Générale, as administrative agent and issuing lender, and certain other lenders.  As of December 31, 2020, $95.0 million was outstanding under the First Lien Credit Facility. 

Outstanding amounts under the First Lien Credit Facility accrue interest at a rate per annum equal to (a)(i) for borrowings that we elect to accrue interest at the reference rate  at the greater of (x) the reference rate announced from time to time by Société Générale, (y) the federal funds rate plus 0.5%, and (z)  daily one-month LIBOR plus, in each case, 1.5%-2.5%, depending on the utilization of the borrowing base, and (ii) for borrowings that  we elect to accrue interest at the Eurodollar rate, LIBOR plus 2.5%-3.5% depending on the utilization of the borrowing base and (b) at any time an event of default exists, 3.0% plus the amounts set forth above. At December 31, 2020, the interest rate on the First Lien Credit Facility was approximately 3.6%.

Subject to earlier termination rights and events of default, the stated maturity date of the First Lien Credit Facility is May 16, 2022. Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. The Company is permitted to terminate the First Lien Credit Facility and is able, from time to time, to permanently reduce the lenders’ aggregate commitment under the First Lien Credit Facility in compliance with certain notice and dollar increment requirements.

Each of the Company's subsidiaries has guaranteed our obligations under the First Lien Credit Facility on a senior secured basis. Obligations under the First Lien Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of the Company and its subsidiary guarantors’ material property and assets. As of December 30, 2020, the collateral is required to include properties comprising at least 90% of the PV-9 of the Company's proven reserves and 95% of the PV-9 of the Company's PDP reserves.

Under the amended First Lien Credit Facility, the Company is subject to customary covenants, including financial covenants and reporting covenants. The amendment to the First Lien Credit Facility dated June 25, 2020 (the "1L Amendment") modified certain provisions of the First Lien Credit Facility, including (i) the addition of monthly mandatory prepayments from excess cash (defined as available cash minus certain cash set-asides and a $3.0 million working capital reserve) with corresponding reductions to the borrowing base; (ii) the elimination of scheduled redeterminations (which were previously made every six months) and interim redeterminations (which were previously made at the request of the lenders no more than once in the six month period between scheduled redeterminations) of the borrowing base; (iii) the replacement of total debt leverage ratio and minimum asset ratio covenants with a first lien debt leverage ratio covenant (comparing the outstanding debt of the First Lien Credit Facility to the consolidated EBITDAX of the Company and requiring that the ratio not exceed 2.75 to 1.00 as of the last day of each fiscal quarter) and a minimum first lien asset coverage ratio covenant (comparing the sum of, without duplication, (A) the PV-15 of producing and developed proven reserves of the Company, (B) the PV-9 of the Company’s hydrocarbon hedge agreements and (C) the PV-15 of proved reserves of the Company classified as “drilled uncompleted” (up to 20% of the sum of (A), (B) and (C)) to the outstanding debt of the First Lien Credit Facility and requiring that the ratio exceed 1.15 to 1.00 as of the last day of each fiscal quarter ending on or before December 31, 2020, and 1.25 to 1.00 for fiscal quarters ending thereafter); (iv) the elimination of current ratio and interest coverage ratio covenants; (v) additional restrictions on (A) capital expenditures (limiting capital expenditures to $3.0 million in any four fiscal quarter period (commencing with the four fiscal quarter period ended  June 30, 2020 and calculated on an annualized basis for the 1, 2 and 3 quarter periods ending on June 30, 2020, September 30, 2020 and December 31, 2020, respectively, subject to certain exceptions, including capital expenditures financed with the proceeds of newly permitted, structurally subordinated debt and capital expenditures made when (1) the first lien asset coverage ratio is at least 1.60 to 1.00, (2) the Company is in compliance with the first lien leverage ratio, (3) the amounts outstanding under the First Lien Credit Facility are less $50.0 million, (4) no default exists under the First Lien Credit Facility and (5) and all representations and warranties in the First Lien Credit Facility and the related credit documents are true and correct in all material respects), (B) outstanding accounts payable (limiting all outstanding and undisputed accounts payable to $7.5 million, undisputed accounts payable outstanding for more than 60 days to $2.0 million and undisputed accounts payable outstanding for more than 90 days to $1.0 million and (C) general and administrative expenses (limiting cash general and administrative expenses the Company may make or become legally obligated to make in any four fiscal quarter period to $9.0 million for the four fiscal quarter period ended  June 30, 2020, $8.25 million for the four fiscal quarter period ended  September 30, 2020, $6.9 million for the four fiscal quarter period ending December 31, 2020, and $6.5 million for the fiscal quarter from  March 31, 2021 through December 31, 2021 and $5.0 million thereafter; in all cases, general and administrative expense excludes up to $1.0 million in certain legal and professional fees; and (vi) permission for up to an additional $25.0 million in structurally subordinated debt to finance capital expenditures. Under the 1L Amendment, the borrowing base was adjusted to $102.0 million. The borrowing base will be reduced by any mandatory prepayments from excess cash flow (in an amount equal to such prepayment) and upon the disposition of the Company’s oil and gas properties.

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Table of Contents

The First Lien Credit Facility contains a number of covenants that, among other things, restrict our ability to: 

• incur or guarantee additional indebtedness;

• transfer or sell assets;

• pay dividends or make other distributions on capital stock or make other restricted payments;

• engage in transactions with affiliates other than on an "arm's length" basis;

• make any change in the principal nature of our business; and

• permit a change in control

The First Lien Credit Facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. 

As of December 31, 2020 we were not in compliance with the First Lien Debt to consolidated EBITDAX under the First Lien Credit Facility, as amended.

Second Lien Credit Facility

On November 13, 2019, we entered into the Term Loan Credit Agreement, with Angelo Gordon Energy Servicer, LLC, as administrative agent, and certain other lenders party thereto, which we refer to as the Second Lien Credit Facility. The Second Lien Credit facility was amended on June 25, 2020. The Second Lien Credit Facility has a maximum commitment of $100.0 million. On November 13, 2019, $95.0 million of the net proceeds obtained from the Second Lien Credit Facility were used to permanently reduce the borrowings outstanding on the First Lien Credit Facility.  As of December 31,  2020, the outstanding balance on the Second Lien Credit Facility was $122.7 million, which includes a $10.0 million exit fee. 

The stated maturity date of the Second Lien Credit Facility is November 13, 2022. Prior to the latest amendments of the Second Lien Credit Facility, accrued interest was payable quarterly on reference rate loans and at the end of each three-month interest period on Eurodollar loans. We are permitted to prepay the loans in whole or in part, in compliance with certain notice and dollar increment requirements.

Each of our subsidiaries has guaranteed our obligations under the Second Lien Credit Facility. Obligations under the Second Lien Credit Facility are secured by a first priority perfected security interest, subject to certain permitted liens, including those securing the indebtedness under the First Lien Credit Facility to the extent permitted by the Intercreditor Agreement, of even date with the Second Lien Credit Facility, among us, our subsidiaries, Angelo Gordon Energy Servicer, LLC and Société Générale, in all of our subsidiary guarantors’ material property and assets. As of December 31, 2020, the collateral is required to include properties comprising at least 90% of the PV-9 of the Company's proven reserves and 95% of the PV-9 of the Company's PDP reserves. 

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Table of Contents

Under the amended Second Lien Credit Facility, the Company is subject to customary covenants, including financial covenants and reporting covenants. The amendment to the Second Lien Credit Facility dated June 25, 2020 (the "2L Amendment") modified certain provisions of the Second Lien Credit Facility, including (i) a requirement that, while the obligations under the First Lien Credit Facility are outstanding, scheduled payments of accrued interest under the Second Lien Credit Facility will be paid in the form of capitalized interest; (ii) an increase in the interest rate by 200bps for interest payable in cash and 500bps for interest payable in kind; (iii) modification of the minimum asset ratio covenant to be the sum of, without duplication, (A) the PV-15 of producing and developed proven reserves of the Company, (B) the PV-9 of the Company’s hydrocarbon hedge agreements and (C) the PV-15 of proved reserves of the Company classified as “drilled uncompleted” (up to 20% of the sum of (A), (B) and (C)) to the total outstanding debt of the Company and requiring that the ratio not exceed 1.45 to 1.00 as of the last day of each fiscal quarter ending between September 30, 2021 to December 31, 2021, and 1.55 to 1.00 for fiscal quarters ending thereafter); (iv) modification of the total leverage ratio covenant to set the first test date to occur on September 30, 2021; (v) modification of the current ratio to eliminate the exclusion of certain valuation accounts associated with hedge contracts from current assets and from current liabilities, (vi) additional restrictions on (A) capital expenditures (limiting capital expenditures to those expenditures set forth in a plan of development approved by Angelo Gordon Energy Servicer, LLC, subject to certain exceptions, including capital expenditures financed with the proceeds of newly permitted, structurally subordinated debt), (B) outstanding accounts payable (limiting all outstanding and undisputed accounts payable to $7.5 million, undisputed accounts payable outstanding for more than 60 days to $2.0 million and undisputed accounts payable outstanding for more than 90 days to $1.0 million and (C) general and administrative expenses (limiting cash general and administrative expenses the Company may make or become legally obligated to make in any four fiscal quarter period to $9.0 million for the four fiscal quarter period ended  June 30, 2020, $8.25 million for the four fiscal quarter period ended  September 30, 2020, $6.5 million for fiscal quarter period from March 31, 2021 through December 31, 2021 and $5.0 million thereafter. 

The Second Lien Credit Facility contains a number of covenants that, among other things, restrict our ability to:

● incur or guarantee additional indebtedness;

● transfer or sell assets;

● create liens on assets;

● pay dividends or make other distributions on capital stock or make other restricted payments; 

● engage in transactions with affiliates other than on an “arm’s length” basis;

● make any change in the principal nature of our business; and

● permit a change of control

The Second Lien Credit Facility also contains customary events of default, including nonpayment of principal or interest, violation of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities.

Events of default have occurred, or are reasonably likely to occur, under the Second Lien Credit Facility as a result of (i) our failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, (ii) our failure to cause certain deposit accounts to be subject to control agreements in favor of the administrative agent for the Second Lien Credit Facility, (iii)  the failure of the Company to meet certain hedging requirements, and (iv) certain cross-defaults that have occurred, or may occur, as a result of the occurrence of events of default under the First Lien Credit Facility and the Second Lien Credit Facility and corresponding cross-defaults or similar termination events under our hedging contracts.

On April 16, 2021, we received a Notice of Default and Reservation of Rights (the “Notice of Default”) from Angelo Gordon stating that we have defaulted under the Second Lien Credit Facility, and that, as a result, the lenders have accelerated our obligations due thereunder and have reserved their rights to pursue additional remedies in the future.

The Notice of Default describes certain events of default that occurred under the Second Lien Credit Facility as a result of (i) our failure to file timely our Form 10-K for the fiscal year ended December 31, 2020, (ii) our failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, and (iii) other defaults under our revolving credit facility.

The Notice of Default declares that our obligations under the Second Lien Credit Facility are immediately due and payable, in each case without presentment, demand, protest or other requirements of any kind, and have begun to bear interest at the rate applicable to such amount under the Second Lien Credit Facility, plus an additional 3%. Additionally, the administrative agent and the lenders have reserved their right to exercise further rights, powers and remedies under the Second Lien Credit Facility, at any time or from time to time, with respect to any of the events of default described above. Angelo Gordon has agreed to forbear from exercising remedies available to it until May 6, 2021.

In connection with the amendment to the Second Lien Credit Facility on June 25, 2020, the Company entered into an Exit Fee and Warrant Agreement subject to NASDAQ approval for the issuance of the issuance of certain warrants. This agreement was finalized on August 11, 2020 at which time the Company issued a warrant to the lender to purchase a total of 33,445,792 shares of common stock at an exercise price of $0.01 per share. On October 19, 2020, the Company effected a reverse stock split of the Company’s authorized, issued and outstanding shares of common stock at a ratio of 1-for-20, thus the warrant was adjusted to provide that the lender may purchase a total of 1,672,290 shares of common stock at an exercise price of $0.20 per share. The warrant is exercisable immediately in whole or in part, on or before five years from the issuance date. The fair value of the warrant and exit fee were recorded as debt issuance costs, presented in the consolidated balance sheets as a deduction from the carrying amount of the note payable, and are being amortized over the loan term. The exit fee shall be due and payable in cash on the earliest to occur of maturity of the obligation under the Second Lien Credit Agreement or the earlier acceleration or payment in full of the same. The 2L Amendment, including the impact of the Exit Fee and Warrant Agreement finalized on August 11, 2020, resulted in the 2L Amendment meeting the criteria of debt extinguishment under the guidance of ASC 470: Debt. Accordingly, all debt issuance cost, including the original discount, of the original Second Lien Credit Facility, were charged to debt extinguishment loss in the accompanying Condensed Consolidated Statement of Operation in the amount of $4.1 million.

Real Estate Lien Note

We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. The outstanding principal accrues interest at a fixed rate of 4.9%. The note is payable in monthly installments of principal and interest in the amount of $35,672.  The maturity date of the note is July 20, 2023. As of   December 31, 2019, and 2020, $3.1 million and $2.8 million, respectively, were outstanding on the note.

5. Property and Equipment

The major components of property and equipment, at cost, are as follows:

	Estimated		December 31,
	Useful life		2019			2020
	Years		(In thousands)
Oil and gas properties (1)		-	$	1,162,094		$	1,167,333
Equipment and other		3-39		15,187			15,348
Drilling rig		15		24,108			24,108
				1,201,389			1,206,789
Accumulated depreciation, depletion, amortization and impairment				(872,431	)		(1,083,843	)
Net Property and Equipment			$	328,958		$	122,946

(1) Oil and gas properties are amortized utilizing the units of production method.

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6.  Stock-Based Compensation and Option Plans

The Company’s Amended and Restated 2005 Employee Long-Term Equity Incentive Plan reserves 0.6 million shares of Abraxas common stock, subject to adjustment following certain events. Awards may be in options or shares of restricted stock. Options have a term not to exceed 10 years. Options issued under this plan vest according to a vesting schedule as determined by the compensation committee of the Company’s board of directors. Vesting may occur upon (1) the attainment of one or more performance goals or targets established by the committee, (2) the optionee’s continued employment or service for a specified period of time, (3) the occurrence of any event or the satisfaction of any other condition specified by the committee, or (4) a combination of any of the foregoing.

Stock Options

The Company grants options to its officers, directors, and other employees under various stock option and incentive plans. There were no options granted in  2019 or 2020

The following table is a summary of the Company’s stock option activity for the three years ended December 31:

	Options			Weighted average		Weighted average		Intrinsic value
	(000s)			exercise price		remaining life		per share
Options outstanding December 31, 2018		378		$	47.35
Granted		-			-
Exercised		(23	)		19.63
Forfeited/Expired		(58	)		48.02
Options outstanding December 31, 2019		297		$	49.41
Granted		-			-
Exercised		-			-
Forfeited/Expired		(101	)		48.96
Options outstanding December 31, 2020		196			49.69		3.8	$	0.00
Exercisable at end of year		192			49.64		3.9	$	0.00

Other information pertaining to the Company’s stock option activity for the three years ended December 31:

	2019		2020
Weighted average grant date fair value of stock options granted (per share)	$	-	$	-
Total fair value of options vested (000's)	$	732	$	275
Total intrinsic value of options exercised (000's)	$	141	$	-

As of December 31, 2020, the total compensation cost related to non-vested awards not yet recognized was approximately $0.06 million, which will be recognized in 2021 through 2022. For the years ended December 31, 2019, and 2020, we recognized $0.4 million and $0.1 million, respectively, in stock-based compensation expense relating to options.

The following table represents the range of stock option prices and the weighted average remaining life of outstanding options as of   December 31, 2020:

	Outstanding Options						Exercisable
			Weighted		Weighted				Weighted		Weighted
			average		average				average		average
	Number		remaining		exercise		Number		remaining		exercise
Range of stock option prices	Outstanding		life		price		Outstanding		life		price
19.40-29.99		66,025		4.9	$	20.02		66,025		4.9	$	20.02
30.00-39.99		5,350		6.4	$	37.47		5,263		6.4	$	34.46
40.00-49.99		19,459		2.2	$	47.73		19,447		2.2	$	47.73
50.00-59.99		13,900		6.0	$	55.81		11,400		5.7	$	56.33
60.00-69.99		52,646		3.8	$	63.14		52,646		3.8	$	63.14
70.00-79.99		19,075		1.8	$	73.22		19,075		1.8	$	73.22
80.00-89.99		3,650		2.9	$	84.15		3,650		2.9	$	84.14
90.00-99.99		12,625		1.8	$	93.38		12,625		1.8	$	93.38
100.00-125.60		2,450		3.3	$	107.97		2,450		3.3	$	17.97
		195,180		3.9	$	49.69		192,581		3.8	$	49.64

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Restricted Stock Awards

Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such stock is determined using the market price on the grant date. Compensation expense is recorded over the applicable restricted stock vesting periods. As of December 31, 2020, the total compensation cost related to non-vested awards not yet recognized was approximately $1.4 million, which will be recognized from 2020 through 2022. For the years ended  December 31, 2019 and 2020, we recognized  $1.0 million and $0.9 million, respectively, in stock-based compensation expense related to restricted stock awards.

The following table is a summary of the Company’s restricted stock activity for the three years ended December 31, 2020:

	Number of Shares			Weighted average grant date fair value
Unvested December 31, 2018		42		$	43.07
Granted		66			26.75
Vested/Released		(14	)		42.98
Forfeited/Expired		(5	)		30.71
Unvested December 31, 2019		89		$	31.67
Granted		-			-
Vested/Released		(33	)		32.11
Forfeited/Expired		(15	)		31.52
Unvested December 31, 2020		41		$	31.37

Performance Based Restricted Stock Awards

Effective on April 1, 2018, the Company issued performance-based shares of restricted stock to certain officers and employees under the Abraxas Petroleum Corporation Amended and Restated 2005 Employee Long-Term Equity Incentive Plan. The shares will vest in 2021 upon the achievement of performance goals based on the Company’s Total Shareholder Return (“TSR”) as compared to a peer group of companies.  The number of shares which would vest depends upon the rank of the Company’s TSR as compared to the peer group at the end of the three-year vesting period, and can range from zero percent of the initial grant up to 200% of the initial grant.

The table below provides a summary of  Performance Based Restricted Stock as of the date indicated (shares in thousands):

	Number of Shares			Weighted average grant date fair value
Unvested December 31, 2018		20			47.40
Granted		40			26.80
Vested/Released		-			-
Forfeited		(3	)		30.38
Unvested December 31, 2019		57		$	33.86
Granted		-			-
Vested/Released		-			-
Forfeited		(13	)		34.29
Unvested December 31, 2020		44		$	33.73

Compensation expense associated with the performance based restricted stock is based on the grant date fair value of a single share as determined using a Monte Carlo Simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the performance based restricted stock awards with shares of the Company's common stock, the awards are accounted for as equity awards and the expense is calculated on the grant date assuming a 100% target payout and amortized over the life of the awards.

As of December 31, 2020, the total compensation cost related to non-vested awards not yet recognized was approximately $0.4 million, which will be recognized from 2020 through 2022.  For the years ended  December 31, 2019 and 2020, we recognized $0.5 million and $0.3 million, respectively, in stock-based compensation expense related to performance based restricted stock awards.

Director Stock Awards

The 2005 Directors Plan (as amended and restated) reserves 70,000 shares of Abraxas common stock, subject to adjustment following certain events. The 2005 Directors Plan provides that each year, at the first regular meeting of the board of directors immediately following Abraxas’ annual stockholder’s meeting, each non-employee director shall be granted or issued awards restricted stock with a value at the date of the grant of $12,000, for participation in board and committee meetings during the previous calendar year. This grant did not take place in 2020.

The maximum annual award for any one person is 1,250 shares of Abraxas common stock or options for common stock.  If options, as opposed to shares, are awarded, the exercise price shall be no less than 100% of the fair market value on the date of the award while the option terms and vesting schedules are at the discretion of the committee.  

Warrants for Common Stock

As of December 31, 2020, outstanding warrants to purchase shares of common stock were as follows:

Issuance Date	Exercisable for	Expiration Date	Exercise Price		Number of Shares
August 11, 2020	Common Stock	August 11, 2025	$	0.20		1,672,290

In connection with the amended Second Lien Credit Agreement, on August 11, 2020, the Company issued a warrant to the lender to purchase a total of 33,445,792 shares of common stock at an exercise price of $0.01 per share. On October 19, 2020 the Company effected a reverse stock split of the Company's authorized, issued and outstanding shares of common stock at a ratio of 1-for-20, thus the warrant was adjusted to provide that the lender may purchase a total of 1,672,290 shares of common stock at an exercise price of $0.20 per share the warrant is  exercisable immediately, in whole or in part, on or before five years from the issuance date. The fair value of the warrant was recorded as debt issuance costs, presented in the consolidated balance sheets as a deduction from the carrying amount of the note payable, and is being amortized over the loan term. 

At December 31, 2020, the Company had approximately 450 thousand shares reserved for future issuance for conversion of its stock options, and incentive plans for the Company’s directors, employees and consultants.

F- 17

 

7. Income Taxes

The Company has determined that a revision was required to correct the December 31, 2019 disclosure of deferred tax liabilities, certain deferred tax assets and the valuation allowance to reflect state income taxes. The effect of these revisions to the net deferred tax asset balance had no impact on the Company’s consolidated balance sheet, statements of operations or statement of cash flow as previously reported. The revisions have been reflected in the 2019 amounts in the following tables.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.  Significant components of the Company’s deferred tax liabilities and assets are as follows:

	As of December 31,
	2019			2020
	(In thousands)
Deferred tax liabilities:
Hedge contracts	$	-		$	4,299
Other		3,158			2,137
Total deferred tax liabilities		3,158			6,436
Deferred tax assets:
US full cost pool	$	9,595			35,500
Depletion carryforward		3,722			461
U.S. net operating loss carryforward		68,250			84,927
Alternative minimum tax credit		6			-
Hedge contracts		1,661			-
Interest disallowed		-			2,818
Total deferred tax assets		83,234			123,706
Valuation allowance for deferred tax assets		(80,076	)		(117,270	)
Net deferred tax assets		3,158			6,436
Net deferred tax	$	-		$	-

Significant components of the provision (benefit) for income taxes are as follows:

	Years Ended December 31,
	2019		2020
	(In thousands)
Current:
Federal	$	-	$	-
State		-		-
	$	-	$	-
Deferred:
Federal	$	-	$	-
	$	-	$	-

At December 31, 2020, the Company had, $245.20 million of pre 2018 NOLs for U.S. tax purposes and $140.0 million of post 2017 NOLs for U.S. tax purposes.  Our pre-2018 NOLs will expire in varying amounts from 2022 through 2037, if not utilized; and can offset 100% of future taxable income for regular tax purposes. Any NOLs arising in 2018, 2019 and 2020 can generally be carried back five years, carried forward indefinitely and can offset 100% of future taxable income for tax years before January 1, 2021 and up to 80% of future taxable income for tax years after December 31, 2020. Any NOLs arising on or after January 1, 2021, cannot be carried back and can generally be carried forward indefinitely and can offset up to 80% of future taxable income for regular tax purposes, (the alternative minimum tax no longer applies to corporations after January 1, 2018).

The use of our NOLs will be limited if there is an "ownership change" in our common stock, generally a cumulative ownership change exceeding 50% during a three year period, as determined under Section 382 of the Internal Revenue Code. As of December 31, 2020, we have not had an ownership change as defined by Section 382. Given historical losses, uncertainties exist as to the future utilization of the NOL carryforwards, therefore, the Company has established a valuation allowance of $80.08  million at  December 31, 2019 and $117.27 million at December 31, 2020.

The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is:

	Years Ended December 31,
	2019			2020
	(in thousands)
Tax benefit at U.S. Statutory rates	$	13,651		$	38,749
Change in deferred tax asset valuation allowance		(12,767	)		(37,193	)
Alternative minimum tax expense		(745	)		-
Expired capital loss carryover		(3,966	)		-
Permanent differences		(403	)		(276	)
Return to provision estimated revision		341			(3,069	)
State income taxes, net of federal effect		3,892			1,789
Other		(3	)		-
	$	-		$	-

As of   December 31, 2019 and 2020, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years 2014 through 2020 remain open to examination by the tax jurisdictions to which the Company is subject.

New tax legislation, commonly referred to as the Tax Cuts and Jobs Act (H.R. 1), was enacted on December 22, 2017. Since our federal deferred tax asset was fully offset by a valuation allowance, the reduction in the U.S. corporate income tax rate to 21% did not materially affect the Company's financial statements. Significant provisions  that may impact income taxes in future years include: the repeal of the corporate Alternative Minimum Tax, the limitation on the current deductibility of net interest expense in excess of 30% of adjusted taxable income for levered balance sheets, (for tax years 2019 & 2020, the CARES Act temporarily adjusted the limitation in excess of 50% of adjusted taxable income for levered balance sheets at the taxpayer’s discretionary election), a limitation on utilization of net operating losses generated after tax year 2017 to 80% of taxable income, the unlimited carryforward of net operating losses generated after tax year 2017, temporary 100% expensing of certain business assets, additional limitations on certain general and administrative expenses, and changes in determining the excessive compensation limitation. Currently, we do not anticipate paying cash federal income taxes in the near term due to any of the legislative changes, primarily due to the availability of our net operating loss carryforwards. Future interpretations relating to the recently enacted U.S. federal income tax legislation which vary from our current interpretation and possible changes to state tax laws in response to the recently enacted federal legislation may have a significant effect on this projection. 

F- 18

 

8. Commitments and Contingencies

Litigation and Contingencies

From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business.  At December 31, 2020, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on the Company.

9. Earnings per Share

The following table sets forth the computation of basic and diluted earnings per share:

	Years Ended December 31,
	2019			2020
Numerator:
Net (loss)	$	(65,004	)	$	(184,522	)
Denominator for basic earnings per share - weighted-average common shares outstanding		8,312			8,382
Effect of dilutive securities: Stock options, restricted shares and performance based shares		3			-
Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options, restricted shares and performance based shares		8,315			8,382
Net (loss) per common share - basic	$	(7.82	)	$	(22.01	)
Net (loss) per common share - diluted	$	(7.82	)	$	(22.01	)

Basic earnings per share, excluding any dilutive effects of stock options and unvested restricted stock, is computed by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted income (loss) per share is computed similar to basic; however diluted income (loss) per share reflects the assumed conversion of all potentially dilutive securities.   For the year ended December 31, 2019,  four thousand potential shares relating to stock options and unvested restricted shares were excluded from the calculation of diluted (loss) income per share since their inclusion would have been anti-dilutive due to a loss in the period and the fact that all outstanding options are underwater.

F- 19

 

10. Benefit Plans

The Company has a defined contribution plan (401(k) plan) covering all eligible employees. For  2019, in accordance with the safe harbor provisions of the Plan, the Company contributed $284,905. The Company will contribute $142,820 to the plan for 2020. The Company adopted the safe harbor provisions which requires it to contribute a fixed match to each participating employee’s contribution to the plan. The fixed match is set at the rate of dollar for dollar on the first 1% of eligible pay contributed, then 50 cents on the dollar for each additional percentage point of eligible pay contributed, up to 5%. Each employee’s eligible pay with respect to calculating the fixed match is limited by IRS regulations. In addition, the Board of Directors, at its sole discretion, may authorize the Company to make additional contributions to each participating employee. The employee contribution limit for 2019 was $19,000 for employees under the age of 50 and $25,000 for employees 50 years of age or older. The employee contribution limit was increased in 2020 to $19,500 for employees under the age of 50 and $26,000 for employees 50 years of age and older. 

F- 20

 

11. Hedging Program and Derivatives

The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations.  Our derivative contracts have not been designated for hedge accounting as prescribed by ASC 815; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. There are no netting agreements relating to these derivative contracts and there is no policy to offset.

The following table sets forth the summary position of our derivative contracts as of December 31, 2020

	Oil - WTI
Contract Periods	Daily Volume (Bbl)		Swap Price (per Bbl)
Fixed Swaps
January - December 2021		2,889	$	57.62
January - December 2022		2,412	$	50.60
January - December 2023		1,498	$	50.60
January - December 2024		1,585	$	50.60

The following table illustrates the impact of derivative contracts on the Company’s balance sheet:

Fair Value Derivative Contracts as of December 31, 2019
	Asset Derivatives			Liability Derivatives
Derivatives not designated as hedging instruments	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity price derivatives	Derivatives - current	$	83	Derivatives - current	$	10,688
Commodity price derivatives	Derivatives - long-term		4,170	Derivatives - long-term		999
		$	4,253		$	11,687

Fair Value Derivative Contracts as of December 31, 2020
	Asset Derivatives			Liability Derivatives
Derivatives not designated as hedging instruments	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity price derivatives	Derivatives - current	$	9,639	Derivatives - current	$	480
Commodity price derivatives	Derivatives - long-term		10,281	Derivatives - long-term		-
		$	19,920		$	480

Gains and losses from derivative activities are reflected as “Loss (gain) on derivative contracts” in the accompanying Consolidated Statements of Operations.  The net estimated value of our commodity derivative contracts was an asset of approximately  $19.4 million as of December 31, 2020. For the year-ended December 31, 2020, we recognized a gain of $42.9 million, consisting of a gain of $17.5 million on closed contracts and a gain of  $25.4 million on the mark to market valuation on open contracts. For the year ended December 31, 2019, we recognized  a loss on our derivative contracts of million approximately $26.8 million, consisting of a loss of $6.0 million on closed contracts and a loss of $20.8 million on the mark to market valuation of open contracts.

F- 21

 

12. Financial Instruments

There is 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 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

• Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

• Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Company is further required to assess the creditworthiness of the counter-party to the derivative contract. The results of the assessment of non-performance risk, based on the counter-party’s credit risk, could result in an adjustment of the carrying value of the derivative instrument. The following tables sets forth information about the Company’s assets and liabilities measured at fair value on a recurring basis as of  December 31, 2019 and 2020, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2019
Assets:
NYMEX fixed price derivative contracts	$	-	$	4,253	$	-	$	4,253
NYMEX basis differential swap		-		-		-		-
Total Assets	$	-	$	4,253	$	-	$	4,253
Liabilities:
NYMEX fixed price derivative contracts	$	-	$	5,583	$	-	$	5,583
NYMEX basis differential swap		-		-		6,104		6,104
Total Liabilities	$	-	$	5,583	$	6,104	$	11,687

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2020
Assets:
NYMEX fixed price derivative contracts	$	-	$	19,920	$	-	$	19,920
Total Assets	$	-	$	19,920	$	-	$	19,920
Liabilities:
NYMEX fixed price derivative contracts	$	-	$	480	$	-	$	480
Total Liabilities	$	-	$	480	$	-	$	480

The Company’s derivative contracts at December 31, 2020 and  December 31, 2019 consisted of NYMEX-based fixed price commodity swaps and basis differential swaps.  The NYMEX-based fixed price derivative contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity and are commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivative contracts. As the fair value of these derivative contracts is based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, we have characterized these derivative contracts as Level 2. In order to verify the third party valuation, we enter the various inputs into a model and compare our results to the third party for reasonableness. The fair value of the basis swaps are based on inputs that are not as observable as the fixed price swaps. In addition to the actively quoted market price, variables such as time value, volatility and other unobservable inputs are used. Accordingly, these instruments have been classified as Level 3.

Additional information for the Company's recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the year ended December 31, 2020.

	(In thousands)
Fair value at January 1, 2020	$	(6,104	)
Changes in market value		4,577
Settlements during the period		1,527
Fair value at December 31, 2020	$	-

There were no transfers from level 3 in 2020.

F- 22

 

Nonrecurring Fair Value Measurements

Non-financial assets and liabilities measured at fair value on a nonrecurring basis included certain non-financial assets and liabilities as may be acquired in a business combination and thereby measured at fair value and the initial recognition of asset retirement obligations for which fair value is used. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, the economic viability of development if proved reserves were assigned and other current market conditions. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligation is presented in Note 1.

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable and accounts payable approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying value of our debt approximates fair value as the interest rates are market rates and this debt is considered Level 2.

13. Lease Accounting Standard

Nature of Leases

We lease certain real estate, field equipment and other equipment under cancelable and non-cancelable leases to support our operations. A more detailed description of our significant lease types is included below.

Real Estate Leases

We rent a residence in North Dakota from a third party for living accommodations for certain field employees. Our real estate lease is non-cancelable with a term of five years, through August 31, 2024. We have concluded our real estate agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreements subsequent to the primary term.

Field Equipment

We rent compressors and coolers from third parties in order to facilitate the downstream movement of our production from our drilling operations to market. Our compressor and cooler arrangements are typically structured with a non-cancelable primary term of one year and continue thereafter on a month-to-month basis subject to termination by either party with thirty days' notice. These leases are considered short term and are not capitalized. We have a small number of compressor leases that are longer than  twelve months. We have concluded that our compressor and cooler rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term. We enter into daywork contracts for drilling rigs with third parties to support our drilling activities. Our drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells or well pads by providing thirty days' notice prior to the end of the original contract term. We have concluded that our drilling rig arrangements represent short-term operating leases. The accounting guidance requires us to make an assessment at contract commencement if we are reasonably certain that we will exercise the option to extend the term. Due to the continuously evolving nature of our drilling schedules and the potential volatility in commodity prices in an annual period, our strategy to enter into shorter term drilling rig arrangements allows us the flexibility to respond to changes in our operating and economic environment. We exercise our discretion in choosing to extend or not extend contracts on a rig by rig basis depending on the conditions present at the time the contract expires. At the time of contract commencement, we have determined we cannot conclude with reasonable certainty if we will choose to extend the contract beyond its original term. Pursuant to the full cost method, these costs are capitalized as part of natural gas and oil properties on our balance sheet when paid.

Discount Rate

Our leases typically do not provide an implicit rate. Accordingly, we are required to use our incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our incremental borrowing rate reflects the estimated rate of interest that we would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. We use the implicit rate in the limited circumstances in which that rate is readily determinable.

F- 23

 

Practical Expedients and Accounting Policy Elections

Certain of our lease agreements include lease and non-lease components. For all existing asset classes with multiple component types, we have utilized the practical expedient that exempts us from separating lease components from non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component. In addition, for all of our existing asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less and does not include an option to purchase the underlying asset that we are reasonably certain to exercise). Accordingly, we recognize lease payments related to our short-term leases in our statement of operations on a straight-line basis over the lease term which has not changed from our prior recognition. To the extent that there are variable lease payments, we recognize those payments in our statement of operations in the period in which the obligation for those payments is incurred. None of our current leases contain variable payments.  Refer to “Nature of Leases” above for further information regarding those asset classes that include material short-term leases.

The components of our total lease expense for the years ended December 31,2019 and  December 31, 2020, the majority of which is included in lease operating expense, are as follows:

	For the Year Ended December 31,
	2019		2020
	(in thousands)
Operating lease cost	$	478	$	114
Short-term lease expense (1)		1,992		2,183
Total lease expense	$	2,470	$	2,297
Short-term lease costs (2)	$	4,900	$	973

(1)	Short-term lease expense represents expense related to leases with a contract term of 12 months or less.
(2)	These short-term lease costs are related to leases with a contract term of 12 months or less which are related to drilling rigs and are capitalized as part of natural gas and oil properties on our balance sheet.

Supplemental balance sheet information related to our operating leases is included in the table below:
 

	For the Year Ended December 31,
	2019		2020
	(in thousands)
Operating lease Right of Use asset	$	327	$	228
Operating lease liability - current	$	98	$	53
Operating lease liabilities - long-term	$	203	$	150

Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows:

	For the Year Ended December 31,
	2019			2020
	(in thousands)
Weighted Average Remaining Lease Term (in years)		8.66			10.68
Weighted Average Discount Rate		6	%		6	%

Our lease liabilities with enforceable contract terms that are greater than one year mature as follows:

	Operating Leases
	(in thousands)
2021	$	63
2022		48
2023		41
2024		28
2025		4
Thereafter		98
Total lease payments		282
Less imputed interest		(79	)
Total lease liability	$	203

Supplemental cash flow information related to our operating leases is included in the table below:

	For the Year Ended December 31,
	2019		2020
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities	$	478	$	114
Right of Use assets added in exchange for lease obligations (since adoption)	$	770	$	125

F- 24

 

14. Subsequent Events

Paycheck Protection Program Loan

On May 4, 2020, the Company entered into an unsecured loan with the U.S. Small Business Administration ("SBA") in the amount of $1.4 million under the Paycheck Protection Program (the "PPP Loan") with an interest rate of 1.0% and maturity date two years from the effective date of the PPP Laon. The Paycheck Protection Program was established under the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act") and is administered by the SBA.  Payments are required to be made in seventeen monthly installments of principal and interest, with the first payment being due on the date that is seven months after the date of the PPP loan. Under the CARES Act, the PPP Loan was eligible for forgiveness for the portion of the PPP Loan proceeds used for payroll costs and other designated operating expenses for up to eight weeks, provided at least 75% of PPP Loan proceeds are used for payroll costs and the Company meets all necessary criteria for forgiveness. Receipt of these funds required the Company to, in good faith, certify that the PPP Loan was necessary to support ongoing operations of the Company during the economic uncertainty created by the COVID-19 pandemic. This certification further required the Company to take into account current business activity and the ability to access other sources of liquidity sufficient to support ongoing operations in a manner that was not significantly detrimental to the business. The PPP Loan, including accrued interest, was forgiven by the SBA in  January 2021. Accordingly, the Company will recognize a gain from debt extinguishment of $1.4 million in the first quarter of 2021.

In connection with the completion of our financial statements for the year ended December 31, 2020, the Company tested its financial ratios for the fiscal quarter ended December 31, 2020 and determined that it was not in compliance the first lien debt to consolidated EBITDAX ratio covenant under the First Lien Credit Facility.  Our failure to comply with such covenant contributed to our independent accountant’s including an explanatory paragraph with regard to the Company's ability to continue as a "going concern" in issuing their opinion on our financial statements for the year ended December 31, 2020.  The "going  concern" opinion resulted in an additional event of default under the First Lien Credit Facility and the Second Lien Credit Facility.  A discussion of the events of default follows.

First Lien Credit Facility

Events of default have occurred, or are reasonably likely to occur, under the First Lien Credit Facility as a result of (i) the Company's failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, (ii) its inability to comply with the first lien debt to consolidated EBITDAX ratio for the fiscal quarter ended December 31, 2020, (iii) our failure to cause certain deposit accounts to be subject to control agreements in favor of the administrative agent for the First Lien Credit Facility,  and (iv) certain cross-defaults that have occurred, or may occur, as a result of the events of default under the First Lien Credit Agreement and corresponding cross-defaults under the Second Lien Credit Facility and cross-defaults or similar termination events under our hedging contracts.

Second Lien Credit Facility

Events of default have occurred, or are reasonably likely to occur, under the Second Lien Credit Facility as a result of (i) the Company's failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, (ii) its failure to cause certain deposit accounts to be subject to control agreements in favor of the administrative agent for the Second Lien Credit Facility and (iii) the failure of the Company to meet certain hedging requirements, and (iv) certain cross-defaults that have occurred, or may occur, as a result of the occurrence of events of default under the First Lien Credit Facility and corresponding cross-defaults or similar termination events under our hedging contracts.

On April 16, 2021, we received a Notice of Default and Reservation of Rights (the “Notice of Default”) from Angelo Gordon stating that we have defaulted under the Second Lien Credit Facility, and that, as a result, the lenders have accelerated our obligations due thereunder and have reserved their rights to pursue additional remedies in the future.

The Notice of Default describes certain events of default that occurred under the Second Lien Credit Facility as a result of (i) our failure to file timely our Form 10-K for the fiscal year ended December 31, 2020, (ii) our failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, and (iii) other defaults under our revolving credit facility.

The Notice of Default declares that our obligations under the Second Lien Credit Facility are immediately due and payable, in each case without presentment, demand, protest or other requirements of any kind, and have begun to bear interest at the rate applicable to such amount under the Second Lien Credit Facility, plus an additional 3%. Additionally, the administrative agent and the lenders have reserved their right to exercise further rights, powers and remedies under the Second Lien Credit Facility, at any time or from time to time, with respect to any of the events of default described above. Angelo Gordon has agreed to forbear from exercising remedies available to it until May 6, 2021.

Hedging Contracts

Effective April 12, 2021, Morgan Stanley Capital Group, Inc. ("Morgan Stanley"), a hedge counterparty to several of our hedging contracts sent us notice of events of default and early termination with respect to the hedging contracts to which they are a counterparty.  The notice indicates Morgan Stanley’s election to exercise termination rights under the hedge contract, which Morgan Stanley asserts have arisen as a result of the occurrence of events of default under the First Lien Credit Facility, of which Morgan Stanley is a lender, holding approximately 3.7% of the outstanding obligations under the First Lien Credit Facility.  The termination value of the hedge contracts with Morgan Stanley as of the effective date of the notice was approximately $9.1 million.  We subsequently voluntarily terminated most of our other hedging arrangements. As a result of the settlement of the terminated hedges, we have outstanding obligations of $9.9 million, including the $9.1 million to Morgan Stanley. The settlement values of the terminated hedges were determined at various dates between April 15 and April 30, 2021. These obligations will be added to the balance of the First Lien Credit Facility and accrue interest  at the default interest rate, currently 6.7% until repaid. Other hedging agreements may also be terminated as a result as a result of the events of default. The termination of additional hedging contracts may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. Amounts that we may owe as a result of terminated hedging contracts will accrue interest for so long as such amounts remain unpaid.

Forbearance Discussions

The existing events of default under the credit facilities are subject to forbearance agreements with our lenders that currently expire on May 6, 2021,  but no assurances can be provided that the forbearance agreements will be further extended.  If the forbearance agreements are extended, we would expect to negotiate with the lenders and the hedge counterparties during the forbearance period regarding a waiver of existing and prospective defaults.  No assurances can be provided that any waivers will be obtained.

F- 25

 

15. Quarterly Results of Operations (Unaudited)

Selected results of operations for each of the fiscal quarters during the years ended  December 31, 2019 and 2020 are as follows:

	1st			2nd			3rd			4th
	Quarter			Quarter			Quarter			Quarter
	(In thousands, except per share data)
Year Ended December 31, 2019
Net revenue	$	34,514		$	34,820		$	31,536		$	28,276
Operating income (loss)	$	6,708		$	8,935		$	8,053		$	(49,412	)
Net income (loss)	$	(25,455	)	$	11,678		$	17,041		$	(68,268	)
Net income (loss) per common share - basic	$	(3.00	)	$	1.40		$	2.00		$	(8.20	)
Net income (loss) per common share - diluted	$	(3.00	)	$	1.40		$	2.00		$	(8.20	)
Year Ended December 31, 2020
Net revenue	$	15,726		$	1,993		$	12,595		$	12,729
Operating income (loss)	$	(29,781	)	$	(61,474	)	$	(56,661	)	$	(51,502	)
Net income (loss)	$	41,443		$	(83,256	)	$	(73,615	)	$	(69,094	)
Net income (loss) per common share - basic	$	4.80		$	(10.00	)	$	(8.80	)	$	(8.21	)
Net income (loss) per common share - diluted	$	4.80		$	(10.00	)	$	(8.80	)	$	(8.21	)

F- 26

 

16. Supplemental Oil and Gas Disclosures (Unaudited)

The accompanying tables present information concerning the Company’s oil and gas producing activities “Disclosures about Oil and Gas Producing Activities.”  Capitalized costs relating to oil and gas producing activities are as follows as of December 31:

	Years Ended December 31,
	(in thousands)
	2019			2020
Proved oil and gas properties	$	1,162,094		$	1,167,333
Unproved properties		-			-
Total		1,162,094			1,167,333
Accumulated depreciation, depletion, amortization and impairment		(851,107	)		(1,060,649	)
Net capitalized costs	$	310,987		$	106,684

Cost incurred in oil and gas property acquisition and development activities were as follows for the years ended December 31 (in thousands):

	2019		2020
Development costs	$	92,884	$	5,238
Exploration costs		-		-
Property acquisition costs		-		-
	$	92,884	$	5,238

Results of operations from oil and gas producing activities were as follows for the years ended December 31:

	2019			2020
Revenues	$	128,992		$	42,984
Production costs		(38,229	)		(21,090	)
Depreciation, depletion and amortization		(51,041	)		(22,679	)
Accretion of future site restoration		(436	)		(414	)
Proved property impairment		(51,293	)		(186,980	)
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$	(12,007	)	$	(188,179	)
Depletion rate per barrel of oil equivalent	$	14.12		$	12.59

F- 27

 

Estimated Quantities of Proved Oil and Gas Reserves

Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and gas properties.  Accordingly, the estimates are expected to change as future information becomes available.  The estimates have been predominately prepared by independent petroleum reserve engineers. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. All of the Company’s proved reserves are located in the continental United States.

Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements; therefore, the unweighted average prior 12-month first-day-of-the-month commodity prices and year-end costs were used in estimating reserve volumes and future net cash flows for the periods presented.

The following set forth changes in estimated net proved reserves for the years ended December 31, 2019 and 2020.

										Oil
	Oil			NGL			Gas			Equivalents
	(MBbl)			(MBbl)			(MMcf)			(Mboe)
Change in Proved Reserves
Balance at December 31, 2018		42,237			10,034			89,744			67,228
Revisions of previous estimates		(15,616	)		(2,713	)		(23,178	)		(22,192	)
Extensions and discoveries		13,477			2,285			14,073			18,109
Purchases of minerals in place		-			-			-			-
Sales of minerals in place		(1,431	)		(86	)		(9,898	)		(3,167	)
Production		(2,388	)		(548	)		(4,076	)		(3,616	)
Balance at December 31, 2019		36,279			8,972			66,665			56,362
Revisions of previous estimates		(16,922	)		(3,549	)		(27,921	)		(25,125	)
Extensions and discoveries		-			-			-			-
Removal of PUDs		(8,687	)		(1,922	)		(12,291	)		(12,658	)
Production		(1,132	)		(313	)		(2,135	)		(1,801	)
Balance at December 31, 2020		9,538			3,188			24,318			16,778

F- 28

 

The following is a summary of the changes to the Company’s proved reserves that occurred during 2020:

Revisions to prior estimates:

 There was a decrease of 56 MBoe of net reserves attributable to changes in projections for the Company’s producing wells based on actual performance during 2020. 

The Company converted 29 proved undeveloped Wolfcamp A1 locations, and 25 3rd Bone Spring locations in Ward County, Texas, to probable undeveloped reserves during 2020 accounting for 17,616 MBoe of net reserves.  The Company converted five proved undeveloped Middle Bakken locations and nine Three Forks locations in McKenzie County, North Dakota, to probable undeveloped reserves during 2020 accounting for 5,153 MBoe of net reserves.  The Company converted two proved undeveloped Delaware Montoya locations in Ward County, Texas, to probable undeveloped reserves during 2020 accounting for 2,300 MBoe of net reserves.  These locations are no longer included in the Company’s five-year development schedule.

Extensions, discoveries and other additions: 

The Company did not add any new proved reserves during 2020 due to either extensions or discoveries.

Purchases:

The Company did not acquire any new proved reserves during 2020.

Sales: 

The Company did not sell any proved reserves during 2020.

Production: 

The Company produced 1,801 MBoe of net proved reserves during 2020. 

The following is a summary of the changes to the Company’s proved reserves that occurred during 2019:

Revisions to prior estimates:

There was a decrease of 8,790 MBoe of net reserves attributable to changes in projections for the Company’s producing wells based on actual performance during 2019.  The Company also converted eight proved undeveloped Wolfcamp A1 locations, twenty-four Wolfcamp A2 locations, one 3rd Bone Spring location, and two Wolfcamp B locations in Ward County, Texas, to probable undeveloped reserves during 2019 accounting for 13,402 MBoe of net reserves.  These locations are no longer included in the Company’s five-year development plan.

Extensions, discoveries and other additions: 

The Company added two new proved undeveloped Wolfcamp A locations, and nine 3rd Bone Spring locations in Ward County, Texas, accounting for 3,776 MBoe of net reserves.  These locations are direct offsets to either successful Abraxas producing wells or those operated by others. The Company converted eighteen probable undeveloped Wolfcamp A1 locations, twenty-four Wolfcamp 3rd Bone Spring locations in Ward County, Texas, and one Three Forks location in McKenzie County, North Dakota to proved undeveloped reserves during 2019 accounting for 14,333 MBoe of net reserves.

Purchases:

The Company did not acquire new wells during 2019.

Sales: 

The Company sold all its holdings in the Gulf Coast Area accounting for 1,839 MBoe of net proved reserves. The Company sold fourteen producing non-operated Permian locations in Marion, Pecos, and Reeves Counties, Texas, accounting for 42 MBoe of net reserves. The Company sold substantially all its holdings in the non-operated Bakken Area accounting for 1,268 MBoe of net proved reserves.  Other miscellaneous asset sales during the year accounted for 18 MBoe of net reserves.

Production: 

The Company produced 3,616 MBoe of net reserves during 2019. 

F- 29

 

The following table presents the Company's estimate of its net proved developed and undeveloped oil and gas reserves as of December 31, 2019 and 2020:

	Total
							Oil
	Oil		NGL		Gas		Equivalents
	(MBbl)		(MBbl)		(MMcf)		(Mboe)
Proved Developed Reserves:
December 31, 2019		10,964		2,699		21,439		17,237
December 31, 2020		9,538		3,187		24,318		16,778
Proved Undeveloped Reserves:
December 31, 2019		25,315		6,273		45,226		39,125
December 31, 2020		-		-		-		-

F- 30

 

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The Company’s proved oil and gas reserves have been estimated by the independent petroleum engineering firm, DeGolyer & MacNaughton, assisted by the engineering and operations departments of the Company as of  December 31, 2019 and  December 31, 2020. The following information has been prepared in accordance with SEC rules and accounting standards based on the 12-month first-day-of-the-month unweighted average prices in accordance with provisions of the FASB’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future net cash flows have not been adjusted for commodity derivative contracts outstanding at the end of each year. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the tax basis and net operating losses associated with the properties.  Since prices used in the calculation are average prices for 2019, and 2020, the standardized measure could vary significantly from year to year based on the market conditions that occurred during a given year.

The technical personnel responsible for preparing the reserve estimates at DeGolyer & MacNaughton meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer & MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.    All reports by DeGolyer & MacNaughton were developed utilizing studies performed by DeGolyer & MacNaughton and assisted by the Engineering and Operations departments of Abraxas. Reserves are estimated by independent petroleum engineers.  The report of DeGolyer & MacNaughton dated February 12, 2021, contains further discussions of the reserve estimates and evaluations prepared by DeGolyer & MacNaughton as well as the qualifications of DeGolyer & MacNaughton’s technical personnel responsible for overseeing such estimates and evaluations is attached as Exhibit 99.1 to this report.

Estimates of proved reserves at  December 31, 2019 and 2020 were based on studies performed by our independent petroleum engineers assisted by the Engineering and Operations departments of Abraxas.  The Engineering department is directly responsible for Abraxas’ reserve evaluation process.  The Vice President of Engineering is the manager of this department and is the primary technical person responsible for this process.  The Vice President of Engineering holds a Bachelor of Science degree in Petroleum Engineering and has 42 years of experience in reserve evaluations. The Vice President of Engineering is a Registered Professional Engineer in the State of Texas.  The operations department of Abraxas assisted in the process.

The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted to represent the fair market value of the Company’s proved oil and gas reserves.  An estimate of fair market value would also take into account, among other factors, the recovery of reserves not classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure. The table below sets forth the Standardized Measure of our proved oil and gas reserves for the years ended  December 31, 2019  and 2020 :

	Years Ended December 31,
	(in thousands)
	2019			2020
Future cash inflows	$	1,890,579		$	345,869
Future production costs		(598,714	)		(166,781	)
Future development costs		(544,111	)		(6,291	)
Future income tax expense		-			-
Future net cash flows		747,754			172,797
Discount	$	(440,142	)	$	(66,113	)
Standardized Measure of discounted future net cash relating to proved reserves	$	307,612		$	106,684

F- 31

 

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following is an analysis of the changes in the Standardized Measure for the periods indicated (in thousands):

	Years Ended December 31,
	(in thousands)
	2019			2020
Standardized Measure, beginning of year	$	651,884		$	307,612
Sales and transfers of oil and gas produced, net of production costs		(90,763	)		(21,894	)
Net change in prices and development and production costs from prior year		(218,092	)		(96,688	)
Extensions, discoveries, and improved recovery, less related costs		98,780			-
Sales of minerals in place		(17,276	)		-
Removal of PUDs		-			(80,416	)
Revisions of previous estimates		(227,477	)		(159,613	)
Change in timing and other		(13,744	)		126,922
Change in future income tax expense		59,112			-
Accretion of discount		65,188			30,761
Standardized Measure, end of year	$	307,612		$	106,684

The standardized measure is based on the following oil and gas prices over the life of the properties as of the following dates:

	Years Ended December 31,
	2019		2020
Oil (per Bbl) (1)	$	55.73	$	39.54
Gas (per Mmbtu) (2)	$	2.54	$	2.03
Oil (per Bbl) (3)	$	52.14	$	37.05
Gas (per Mmbtu) (4)	$	0.63	$	0.27
NGL's (per Bbl) (5)	$	3.48	$	1.37

_____________________

(1) The quoted oil price for the year ended December 31 of each year,  2019 and 2020 is the 12-month unweighted average first-day-of-the-month West Texas Intermediate spot price for each month of  2019 and 2020.

(2) The quoted gas price for the year ended  December 31, 2019 and 2020 is the 12-month unweighted average first-day-of-the-month Henry Hub spot price for each month of  2019 and 2020.

(3) The oil price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.

(4) The gas price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.

(5) The NGL price is the realized price as of December 31 of each year after the appropriate differentials have been applied.

F- 32

Exhibit Index

23.1 Consent of ADKF P.C. (Filed herewith).

23.2 Consent of BDO USA, LLP. (Filed herewith).

23.3 Consent of DeGolyer and MacNaughton. (Filed herewith).

31.1 Certification – Chief Executive Officer. (Filed herewith).

31.2 Certification – Chief Financial Officer. (Filed herewith).

32.1 Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).

32.2 Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).

99.1 DeGolyer and MacNaughton's report  with respect to oil and reserves of Abraxas Petroleum. (Filed herewith).

101.INS	Inline XBRL Instance Document (the Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document)
101.SCH	Inline XBRL Taxonomy Extension Schema Document
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

* Management Compensatory Plan or Agreement.

79

SIGNATURES

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

ABRAXAS PETROLEUM CORPORATION

By:	/s/Robert L.G. Watson	By:	/s/Steven P. Harris	By:	/s/ G. William Krog, Jr.
	President and Principal Executive Officer		Vice President and Chief Financial Officer Principal Financial Officer		Vice President and Chief Accounting Officer Principal Accounting Officer

DATED:  May 6, 2021

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 date indicated.

Signature	Name and Title	Date
/s/ Robert L.G. Watson Robert L.G. Watson	Chairman of the Board, President (Principal Executive Officer) and Director	May 6,  2021
/s/ Steven P. Harris Steven P. Harris	Vice President, CFO (Principal Financial Officer)	May 6,  2021
/s/ G. William Krog, Jr. G. William Krog, Jr.	Vice President, Chief Accounting Officer (Principal Accounting Officer)	May 6,  2021
/s/ Ralph F. Cox Ralph F. Cox	Director	May 6,  2021
/s/ Brian L. Melton Brian L. Melton	Director	May 6,  2021
/s/ Angela A. Meyer Angela A. Meyer	Director	May 6,  2021

80

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

Abraxas Petroleum Corporation

San Antonio, Texas

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-219873), Form S-4 (No. 333-212340) and Form S-8 (Nos. 333-219877, 333-17375, 333-17377, 033-81416, 333-55691, 333-74614, 333-74592, 333-135032, 333-153635, 333-162358, 333-168022, 333-188117, 333-204744 and 333-212341) of Abraxas Petroleum Corporation of our reports dated March XX, 2021, relating to the consolidated financial statements of Abraxas Petroleum Corporation, included in the Annual Report (Form 10-K) for the year ended December 31, 2020.

/s/ ADKF, P.C.

San Antonio, Texas

May 6, 2021

EX-23.2

Exhibit 23.2

Consent of Independent Registered Public Accounting Firm

Abraxas Petroleum Corporation

San Antonio, Texas

We hereby consent to the incorporation by reference in the Registration Statements on Form S‐3 (No. 333-219873), Form S-4 (No. 333-212340) and Form S-8 (Nos. 333-219877, 333-17375, 333-17377, 033-81416, 333-55691, 333-74614, 333-74592, 333-135032, 333-153635, 333-162358, 333-168022, 333-188117, 333-204744 and 333-212341) of Abraxas Petroleum Corporation of our report dated June 26, 2020 (May 6, 2021, as to the effects of the reverse stock split described in Note 3), relating to the 2019 consolidated financial statements, which appears in this Annual Report on Form 10-K.

/s/ BDO USA, LLP

Dallas, Texas

May 6, 2021

EX-23.3

Exhibit 23.3

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

March 31, 2021

Abraxas Petroleum Corporation

18803 Meisner Drive

San Antonio, TX 78258

Ladies and Gentlemen:

We consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer and MacNaughton, and to the inclusion of information taken from our reports entitled “Report as of December 31, 2020 on Reserves and Revenue of Certain Properties with interests attributable to Abraxas Petroleum Corporation” and “Report as of December 31, 2019 on Reserves and Revenue of Certain Properties with interests attributable to Abraxas Petroleum Corporation” (our Reports) under the headings “Item 1. Business – General,” “Item 2. Properties – Reserves Information,” and “Notes to Consolidated Financial Statements – 16. Supplemental Oil and Gas Disclosures (Unaudited)” in the Abraxas Petroleum Corporation Annual Report on Form 10-K for the year ended December 31, 2020. We also consent to the inclusion of our report of third party dated February 12, 2021, in the Annual Report on Form 10-K of Abraxas Petroleum Corporation as Exhibit 99.1. We further consent to the incorporation by reference in the Registration Statements on Form S-3 (File Nos. 333-212342 and 333‑219873), Form S-4 (File No. 333‑212340), and Form S-8 (File Nos. 333-219877, 333-17375, 333-17377, 033-81416, 333-55691, 333-74614, 333-74592, 333-135032, 333-153635, 333-162358, 333-168022, 333-188117, 333‑204744, and 333-212341) of information from our Reports.

Very truly yours,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON    

                                                                    Texas Registered Engineering Firm F-716

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Robert L. G. Watson, certify that:    

1. I have reviewed this annual report on Form 10-K of Abraxas Petroleum Corporation.

2. Based on my knowledge, this annual 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 controls 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 fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

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 6, 2021

/s/ Robert L.G. Watson

Robert L.G. Watson

Chairman of the Board, President and Principal Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Steven P. Harris, certify that:    

1. I have reviewed this annual report on Form 10-K of Abraxas Petroleum Corporation.

2. Based on my knowledge, this annual 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 controls 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 fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

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 6, 2021

/s/Steven P. Harris

Steven P. Harris

Vice President and Principal 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

In connection with the Annual Report of Abraxas Petroleum Corporation (the “Company”) on Form 10-K for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert L.G. Watson, Chairman of the Board, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Robert L.G. Watson

Robert L.G. Watson

Chairman of the Board, President and Chief Executive Officer

May 6, 2021

This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of §18 of the Securities Exchange Act of 1934, as amended.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

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

In connection with the Annual Report of Abraxas Petroleum Corporation (the “Company”) on Form 10-K for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Steven P. Harris, Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/Steven P. Harris

Steven P. Harris

Vice President and Chief Financial Officer

 May 6, 2021

This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of §18 of the Securities Exchange Act of 1934, as amended.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 12, 2021

Abraxas Petroleum Corporation

18803 Meisner Drive

San Antonio, Texas 78258

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2020, of the extent and value of the estimated net proved oil, natural gas liquids (NGL), and gas reserves of certain properties in which Abraxas Petroleum Corporation (Abraxas) has represented it holds an interest. This evaluation was completed on February 12, 2021. The properties evaluated herein consist of working interests located in North Dakota and Texas. Abraxas has represented that these properties account for 98 percent on a net equivalent barrel basis of Abraxas’ net proved reserves as of December 31, 2020. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by Abraxas.

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2020. Net reserves are defined as that portion of the gross reserves attributable to the interests held by Abraxas after deducting all interests held by others.

Values for proved reserves in this report are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is defined as that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting production taxes, ad valorem taxes, operating expenses, capital costs, and abandonment costs from future gross revenue. Operating expenses include field
operating expenses, transportation and processing expenses, compression charges, and an allocation of overhead that directly relates to production activities. Capital costs include drilling and completion costs, facilities costs, and field maintenance costs. Abandonment costs are represented by Abraxas to be inclusive of those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment. At the request of Abraxas, future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a nominal discount rate of 10 percent per year compounded annually over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.

Estimates of reserves and revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Information used in the preparation of this report was obtained from Abraxas and from public sources. In the preparation of this report we have relied, without independent verification, upon information furnished by Abraxas with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report.

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a)
(1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified 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 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.

Developed oil and gas reserves – 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.

Undeveloped oil and gas reserves – 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 [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by Abraxas, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The proved undeveloped reserves estimates were based on opportunities identified in the plan of development provided by Abraxas.

Abraxas has represented that its senior management is committed to the development plan provided by Abraxas and that Abraxas has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.

For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for this report. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas).

Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs.

In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.

Data provided by Abraxas from wells drilled through December 31, 2020, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through October 2020. Estimated cumulative production, as of December 31, 2020, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 2 months.

Oil reserves estimated herein are those to be recovered by normal field separation. NGL reserves estimated herein include pentanes and heavier fractions (C₅₊) and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions, and are the result of low-temperature plant processing. Oil and NGL reserves included in this report are expressed in thousands of barrels (Mbbl). In these estimates, 1 barrel equals 42 United States gallons.

Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the pressure base of the state in which the quantities are located. Gas quantities included in this report are expressed in millions of cubic feet (MMcf).

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include only associated gas.

At the request of Abraxas, sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

Primary Economic Assumptions

Revenue values in this report were estimated using initial prices, expenses, and costs provided by Abraxas. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the revenue values reported herein:

Oil and NGL Prices

Abraxas has represented that the oil and NGL prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. The oil and NGL prices were calculated using differentials furnished by Abraxas to a West Texas Intermediate (WTI) price of $39.54 per barrel and held constant thereafter. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $35.49 per barrel of oil and $2.26 per barrel of NGL.

Gas Prices

Abraxas has represented that the gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12‑month period prior to the end of the reporting period, unless prices are defined by contractual agreements. The gas prices were calculated for each property using differentials furnished by Abraxas to a Henry Hub (HH) price of $2.03 per million Btu and held constant thereafter. Btu factors provided by Abraxas were used to convert prices from dollars per million Btu to dollars per thousand cubic feet. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $0.304 per thousand cubic feet of gas.

Production and Ad Valorem Taxes

Production taxes were calculated using the tax rates for each state in which the reserves are located, including, where appropriate, abatements for enhanced recovery programs. Ad valorem taxes were calculated using rates provided by Abraxas based on recent payments.

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses, provided by Abraxas and based on current expenses, were held constant for the lives of the properties. Future capital expenditures were estimated using 2020 values, provided by Abraxas, and were not adjusted for inflation. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by Abraxas for all properties and were not adjusted for inflation. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of undeveloped reserves estimated herein.

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, NGL, and gas contained in this report has been prepared in accordance with Paragraphs 932‑235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932‑235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

Summary of Conclusions

The estimated net proved reserves, as of December 31, 2020, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2020
	Oil (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)
Proved Developed	9,007	2,924	18,048	14,939
Proved Undeveloped	8,687	1,922	12,292	12,658
Total Proved	17,694	4,846	30,340	27,597
Note: Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

The estimated future revenue to be derived from the production and sale of the net proved reserves, as of December 31, 2020, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):

	Proved Developed (M$)	Total Proved (M$)
Future Gross Revenue	324,804	642,580
Production and Ad Valorem Taxes	29,606	56,239
Operating Expenses	139,454	220,510
Capital and Abandonment Costs	3,691	133,867
Future Net Revenue	152,053	231,964
Present Worth at 10 Percent	98,375	120,191
Note: Future income taxes have not been taken into account in the preparation of these estimates.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2020, estimated reserves.DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Abraxas. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Abraxas. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

DeGOLYER and MacNAUGHTON                                                                      

 Texas Registered Engineering Firm F-716

Dilhan Ilk, P.E.

Senior Vice President

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Dilhan Ilk, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1. That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare this report of third party addressed to Abraxas dated
February 12, 2021, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.

2. That I attended Istanbul Technical University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 2003, a Master of Science degree from Texas A&M University in 2005, and a Doctor in Philosophy degree from Texas A&M University in 2010; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 10 years of experience in oil and gas reservoir studies and reserves evaluations.

XML

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2020	Apr. 30, 2021	Jun. 30, 2020
Document Information [Line Items]
Entity Central Index Key	0000867665
Entity Registrant Name	ABRAXAS PETROLEUM CORP
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2020
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Document Transition Report	false
Entity File Number	001-16071
Entity Incorporation, State or Country Code	NV
Entity Tax Identification Number	74-2584033
Entity Address, Address Line One	18803 Meisner Drive
Entity Address, City or Town	San Antonio
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	78258
City Area Code	210
Local Phone Number	490-4788
Title of 12(b) Security	Common Stock, par value $.01 per share
Trading Symbol	AXAS
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 31,865,614
Entity Common Stock, Shares Outstanding		8,421,910

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 2,775	$ 0
Accounts receivable:
Joint owners, net	1,255	2,397
Oil and gas production sales	8,794	16,985
Other	0	263
Total accounts receivable	10,049	19,645
Derivative asset - short-term	9,639	83
Other current assets	1,588	1,193
Total current assets	24,051	20,921
Proved oil and gas properties, full cost method	1,167,333	1,162,094
Other property and equipment	39,456	39,295
Total	1,206,789	1,201,389
Less accumulated depreciation, depletion, amortization and impairment	(1,083,843)	(872,431)
Total property and equipment - net	122,946	328,958
Operating lease right-of-use assets	228	327
Derivative asset, long-term	10,281	4,170
Other assets	255	255
Total assets	157,761	354,631
Current liabilities:
Accounts payable	6,074	19,280
Joint interest oil and gas production payable	8,795	18,050
Accrued interest	86	133
Other accrued liabilities	230	361
Derivative liabilities - short-term	480	10,688
Right of use liability	53	98
Current maturities of long-term debt	202,751	280
Other current liabilities	850	582
Total current liabilities	219,319	49,472
Derivative liabilities long-term	0	999
Right of use liability	150	203
Future site restoration	7,360	7,420
Total liabilities	230,728	250,812
Commitments and contingencies (Note 8)
Stockholders' Equity
Preferred stock, par value $0.01 per share - authorized 1,000,000 shares; - 0- shares issued and outstanding	0	0
Common stock, par value $0.01 per share, authorized 20,000,000 shares; 8,436,498 and 8,421,910 issued and outstanding at December 31, 2019 and 2020, respectively	85	84
Additional paid-in capital	429,475	421,740
Accumulated deficit	(502,527)	(318,005)
Total stockholders' equity	(72,967)	103,819
Total liabilities and stockholders' equity	157,761	354,631
Debt Instruments Excluding PPP Loan [Member]
Current liabilities:
Long-term debt - less current maturities	2,515	192,718
Paycheck Protection Program, CARES Act [Member]
Current liabilities:
Long-term debt - less current maturities	$ 1,384	$ 0

XML

Consolidated Balance Sheets (Parentheticals) - $ / shares	Dec. 31, 2020	Dec. 31, 2019
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, authorized (in shares)	1,000,000	1,000,000
Preferred stock, issued (in shares)	0	0
Preferred stock, outstanding (in shares)	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, authorized (in shares)	20,000,000	20,000,000
Common stock, issued (in shares)	8,421,910	8,436,498
Common stock, outstanding (in shares)	8,421,910	8,436,498

XML

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenues:
Other	$ 59	$ 154
Total Revenue	43,043	129,146
Operating costs and expenses
Lease operating	16,458	27,619
Production and ad valorem taxes	4,632	10,610
Rig expense	762	1,333
Depreciation, depletion, amortization and accretion	24,846	52,703
Proved property impairment	186,980	51,293
General and administrative (including stock-based compensation of $1,911 and $1,312, respectively)	8,783	11,304
Total operating costs and expenses	242,461	154,862
Operating (loss) income	(199,418)	(25,716)
Other (income) expense:
Interest income	(39)	(65)
Interest expense	21,281	12,335
Amortization of deferred financing fees	2,565	543
Loss on debt extinguishment	4,108	0
Loss (gain) on derivative contracts	(42,880)	26,831
Loss on sale of non-oil and gas assets	0	33
Other	69	(389)
Total other expense (income)	(14,896)	39,288
(Loss) income before income tax	(184,522)	(65,004)
Income tax (expense) benefit	0	0
Net (loss) income	$ (184,522)	$ (65,004)
Net (loss) income per common share - basic (in dollars per share)	$ (22.01)	$ (7.82)
Net (loss) income per common share - diluted (in dollars per share)	$ (22.01)	$ (7.82)
Weighted average shares outstanding
Basic (in shares)	8,382	8,312
Diluted (in shares)	8,382	8,315
Oil Revenues [Member]
Revenues:
Revenues	$ 41,969	$ 124,503
Gas Revenues [Member]
Revenues:
Revenues	586	2,579
Natural Gas Liquids Revenues [Member]
Revenues:
Revenues	$ 429	$ 1,910

XML

Consolidated Statements of Operations (Parentheticals) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Stock-based compensation	$ 1,312	$ 1,911

XML

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Total
Balance (in shares) at Dec. 31, 2018	8,354,133
Balance at Dec. 31, 2018	$ 83	$ 419,428	$ (253,001)	$ 166,510
Net loss	0	0	(65,004)	(65,004)
Stock-based compensation	0	1,911	0	1,911
Stock options exercised	$ 0	402	0	402
Restricted stock issued, net of forfeitures (in shares)	61,196
Restricted stock issued, net of forfeitures	$ 1	(1)	0	$ 0
Balance (in shares) at Dec. 31, 2019	8,436,498			8,436,498
Balance at Dec. 31, 2019	$ 84	421,740	(318,005)	$ 103,819
Net loss	0		(184,522)	(184,522)
Stock-based compensation	0	1,312	0	1,312
Stock options exercised	0	0	0	0
Warrant issued	$ 0	6,424		$ 6,424
Restricted stock forfeitures and cancellations (in shares)	(14,588)
Balance (in shares) at Dec. 31, 2020	8,421,910			8,421,910
Balance at Dec. 31, 2020	$ 84	$ 429,476	$ (502,527)	$ (72,967)

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Operating Activities:
Net (loss)	$ (184,522)	$ (65,004)
Adjustments to reconcile net (loss) to net cash provided by operating activities:
Loss on sale of non-oil and gas assets	0	33
Net loss (gain) on derivative contracts	(42,880)	26,831
Net cash settlements (paid) received on derivative contracts	16,006	(4,317)
Depreciation, depletion and amortization	24,432	52,267
Proved property impairment	186,980	51,293
Amortization of deferred financing fees and issuance discount	3,926	738
Accretion expense and other	414	436
Loss on debt extinguishment	4,108	0
Plugging cost	(236)	(890)
Non-cash interest	12,695	0
Stock-based compensation	1,312	1,911
Changes in operating assets and liabilities:
Accounts receivable	9,596	19,991
Other assets	(394)	1,092
Accounts payable	(15,304)	(10,491)
Accrued expenses and other	(148)	(243)
Net cash provided by operating activities	15,985	73,647
Investing Activities
Capital expenditures, including purchase and development of properties	(12,557)	(108,673)
Proceeds from the sale of oil and gas properties	0	23,434
Proceeds from the sale of non-oil and gas assets	0	272
Net cash used in investing activities	(12,557)	(84,967)
Financing Activities
Proceeds from exercise of stock options and restricted stock	0	402
Payments of long-term borrowings	(9,059)	(124,692)
Deferred financing fees	(978)	(1,960)
Net cash provided by (used) in financing activities	(653)	10,453
(Decrease) increase in cash and cash equivalents	2,775	(867)
Cash and cash equivalents at beginning of period	0	867
Cash and cash equivalents at end of period	2,775	0
Supplemental disclosure of cash flow information:
Interest paid	7,174	12,340
Income tax paid	0	0
Non-cash investing and financing activities
Change in asset retirement obligation cost and liabilities	(22)	855
Asset retirement obligations associated with dispositions	(216)	(473)
Change in capital expenditures included in accounts payable	(7,157)	(16,489)
Paycheck Protection Program, CARES Act [Member]
Financing Activities
Proceeds from long-term borrowings	1,384	0
First Lien Credit Facility [Member]
Financing Activities
Proceeds from long-term borrowings	8,000	40,203
Second Lien Credit Facility [Member]
Financing Activities
Proceeds from long-term borrowings	$ 0	$ 96,500

XML

Note 1 - Organization and Significant Accounting Policies

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block]

1. Organization and Significant Accounting Policies

Nature of Operations

We are an independent energy company primarily engaged in the acquisition, exploitation, development and production of oil and gas in the United States.  Our oil and gas assets are located primarily in two operating regions in the United States: the Rocky Mountains and Permian/Delaware Basin.

The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including Raven Drilling LLC (“Raven Drilling”).

Going Concern

Our present level of indebtedness and the recent commodity price environment present challenges to our ability to comply with certain covenants in our credit facilities and under applicable auditing standards the independent accountants' opinion on our  financial statements for the year ended December 31, 2020 contains an explanatory paragraph regarding the Company's ability to continue as a "going concern".  At December 31, 2020, we had a total of $95.0  million outstanding under our First Lien Credit Facility, $112.7 million under our Second Lien Credit facility, and total indebtedness of  $220.5 million including a $10.0 million exit fee. As of April 30, 2021, we had a total of $89.5  million outstanding under our First Lien Credit Facility,  $127.2  million under our Second Lien Credit Facility, including a  $10.0 million exit fee, and total indebtedness of $219.4 million. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements.

Specifically, with regard to our credit agreements, we did not satisfy the first lien debt to consolidated EBITDAX ratio covenant under our First Lien Credit Facility as of the December 31, 2020 measurement date and such failure represented an event of default under our First Lien Credit Facility. In addition,  we do not anticipate that we will  maintain compliance with the Second Lien Credit Facility total leverage ratio covenant or the minimum asset coverage ratio (as defined in Note 4) both of which will be  first tested as of September 30, 2021, over the next twelve months and, accordingly, the audit report prepared by our auditors with respect to the financial statements for the year ended December 31, 2020 includes an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern.” The inability to maintain compliance with certain covenants of our Second Lien Credit Facility would represent an additional default under our First Lien Credit Facility as of the end of any such future fiscal quarters. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty.

We are evaluating the available financial alternatives and are in discussion with our lenders seeking additional waivers or amendments to the covenants or other provisions of our credit facilities to address any current and future default relating to the covenants in question. The existing defaults at  March 31, 2021 are subject to forbearance agreements with our lenders that currently expire on  May 6, 2021. No assurance can be provided that the forbearance agreements will be further extended. If, upon a future default, the Company is unable reach an agreement with its lenders or find acceptable alternative financing, the lenders under the Company's First Lien Credit Facility  may choose to accelerate repayment. If the Company's lenders accelerate the payment of amounts outstanding under its credit facilities, the Company does not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so. The Company could attempt to obtain additional sources of capital from asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination thereof. However, the Company cannot provide any assurances that it will be successful in obtaining capital from such transactions on acceptable terms, or at all. 

Under applicable accounting principles these circumstances are deemed to create substantial doubt regarding the Company's ability to continue as a "going concern". The consolidated financial statements have been prepared on a "going concern" basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business for the twelve-month period following the date of issuance of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amount, or the amount and classification of liabilities that may result should the Company be unable to continue as a "going concern".

In April 2021, we received notice that certain of our hedging agreements were being terminated as a result of events of default under the First Lien Credit Facility, and we voluntarily terminated most of our other  hedging arrangements. As a result of the settlement of the terminated hedges, we have outstanding obligations of $9.9 million. The settlement values of the terminated hedges were determined at various dates between April 15 and April 30, 2021. These obligations will be added to the balance of the First Lien Credit Facility and accrue interest  at the default interest rate, currently 6.7%, until repaid. Our remaining  hedging agreements may also be terminated as a result of such events of default. The settlement of terminated hedging agreements may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. See Note 14 “Subsequent Events” for current information regarding non-compliance with certain covenants.

Rig Accounting

In accordance with SEC Regulation S-X, no income is recognized in connection with contractual drilling services performed in connection with properties in which the Company or its affiliates holds an ownership, or other economic interest. Any income not recognized as a result of this limitation is credited to the full cost pool and recognized through lower amortization as reserves are produced. During part of 2019 and all of 2020 the drilling rig was idle, accordingly the cost of the rig was charged to the statement of operations.

Use of Estimates

The consolidated financial statements of the Company have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

The most significant estimates pertain to proved oil, gas and NGL reserves and related cash flow estimates used in impairment tests of oil and gas properties, the fair value of assets and liabilities acquired in business combinations, derivative contracts, the provision for income taxes including uncertain tax positions, stock based compensation, asset retirement obligations, accrued oil and gas revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates.

The process of estimating oil and gas reserves in accordance with SEC requirements is complex and involves decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data.  Accordingly, these estimates are imprecise.  Actual future production, oil and gas prices, differentials, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated.  Any significant variance could materially affect the estimated quantities and present value of our reserves.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, our ability to fund estimated development cost, prevailing oil and gas prices and other factors, many of which are beyond our control.

Reclassifications

Certain reclassifications have been made to the prior year financial statements to conform to the current period presentation.  These reclassifications were to share and per share data related to the 1 for 20 reverse stock split effective October 19, 2020 and had no effect on our previously reported results of operations.

Concentration of Credit Risk

Financial instruments which potentially expose the Company to credit risk consist principally of trade receivables and derivative contracts.  Accounts receivable are generally from companies with significant oil and gas marketing or operating activities.  The Company performs ongoing credit evaluations and, generally, requires no collateral from its customers. The counterparties to our derivative contracts are the same financial institutions from which we have outstanding debt; accordingly, we believe our exposure to credit risk to these counterparties is currently mitigated in part by this, as well as the current overall financial condition of the counterparties.

The Company maintains any cash and cash equivalents in excess of federally insured limits in prominent financial institutions considered by the Company to be of high credit quality.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three months or less.

Accounts Receivable

Accounts receivable are reported net of an allowance for doubtful accounts of approximately $0.1 million at  December 31, 2019 and 2020 . The allowance for doubtful accounts is determined based on the Company's historical losses, as well as a review of certain accounts. Accounts are charged off when collection efforts have failed and the account is deemed uncollectible.

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development and production of oil and gas with all of the Company’s operational activities being  conducted in the U.S. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long lived assets located outside the U.S.

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas properties.  Under this method, certain direct costs and indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves.  Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Costs in excess of the present value of estimated future net revenues are charged to proved property impairment expense.  No gain or loss is recognized upon sale or disposition of oil and gas properties for full cost accounting companies with proceeds accounted for as an adjustment of capitalized cost. An exception to this rule occurs when the adjustment to the full cost pool results in a significant alteration of the relationship between capitalized cost and proved reserves. The Company applies the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. The impairment calculations do not consider the impact of our commodity derivative positions as generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges.   As of  December 31, 2019 and 2020, our capitalized cost of oil and gas properties exceeded the future net revenue from our estimated proved reserves resulting in the recognition of an impairment of $51.3 million  and  $187.0  million, respectively.

Other Property and Equipment

Other property and equipment are recorded at cost.  Depreciation of other property and equipment is provided over the estimated useful lives using the straight-line method.  Major renewals and improvements are recorded as additions to the property and equipment accounts.  Repairs that do not improve or extend the useful lives of assets are expensed.

Estimates of Proved Oil and Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

• the quality and quantity of available data;

• the interpretation of that data;

• the accuracy of various mandated economic assumptions; and

• the judgment of the persons preparing the estimate.

Our proved reserve information included in this report was based on studies performed by our independent petroleum engineers assisted by the engineering and operations departments of Abraxas. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may cause material revisions to the estimate.

In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the average of oil and gas prices based on the unweighted average 12 month first-day-of-month pricing. Future prices and costs may be materially higher or lower than these prices and costs which would impact the estimated value of our reserves.

The estimates of proved reserves materially impact depreciation, depletion and amortization, or DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields.

Derivative Instruments and Hedging Activities

The Company enters into agreements to hedge the risk of future oil and gas price fluctuations.  Such agreements are typically in the form of fixed price commodity and basis swaps, which limit the impact of price fluctuations with respect to the Company’s sale of oil and gas. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions could arise where actual production is less than estimated which could result in over hedged volumes.

All derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The derivative instruments the Company utilizes are based on index prices that may and often do differ from the actual oil and gas prices realized in its operations.  These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for hedge accounting rules as prescribed by Accounting Standards Codification (“ASC”) 815. Accordingly, the Company does not account for its derivative instruments as cash flow hedges for financial reporting purposes.  Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in net gains (losses) on commodity derivative contracts in the Consolidated Statements of Operations.

Fair Value of Financial Instruments

The Company includes fair value information in the notes to consolidated financial statements when the fair value of its financial instruments is materially different from the carrying value.  The carrying value of those financial instruments that are classified as current, except for derivative instruments, approximates fair value because of the short maturity of these instruments.  For noncurrent financial instruments, the Company uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments.

Share-Based Payments

  Options granted are valued at the date of grant and expense is recognized over the vesting period. The Company currently utilizes a standard option pricing model (Black-Scholes) to measure the fair value of stock options granted to employees and directors. Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such restricted stock is determined using the market price on the grant date and expense is recorded over the vesting period. For the years ended  December 31, 2019  and 2020, stock-based compensation was approximately  $1.9 million and $1.3 million, respectively.

Restoration, Removal and Environmental Liabilities

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites.  Environmental expenditures are expensed or capitalized depending on their future economic benefit.  Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.

Liabilities for expenditures of a noncapital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable.

The fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period and the capitalized cost is depreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and we amortize these costs as a component of our depletion expense in the accompanying consolidated financial statements. Each year, the Company reviews, and to the extent necessary, revises its asset retirement obligation estimates.

The following table (in thousands) summarizes changes in the Company’s future site restoration obligations during the two years ended December 31: 

	2019			2020
Beginning future site restoration obligation	$	7,492		$	7,420
New wells placed on production and other		80			43
Deletions related to property disposals		(473	)		(216	)
Deletions related to plugging costs		(890	)		(235	)
Accretion expense and other		436			414
Revisions and other		775			(66	)
Ending future site restoration obligation	$	7,420		$	7,360

Revenue Recognition and Major Purchasers

The Company recognizes oil and gas revenue from its interest in producing wells as oil and gas is sold from those wells, net of royalties, control of the product has transferred to the purchaser and collectability  is reasonably assured. The Company had no material gas imbalances at  December 31, 2019 and 2020.

During 2019 two purchasers accounted for 71% of oil and gas revenues. During 2020, four purchasers accounted for 73% of oil and gas revenues.

Deferred Financing Fees

Deferred financing fees are being amortized on the effective yield basis over the term of the related debt.

Income Taxes

Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to be in effect with respect to taxable income in the years in which those temporary differences are expected to be recovered or settled. Uncertainties exist as to the future utilization of the operating loss carryforwards. Therefore, we have established a valuation allowance of $117.27 million for deferred tax assets at December 31, 2020.

Accounting for Uncertainty in Income Taxes

Evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.

Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period in which the threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not criteria should be de-recognized in the first subsequent reporting period in which the threshold is no longer met. Penalties and interest are classified as income tax expense. The Company had no uncertain income tax positions as of December 31, 2020.

Adoption of New Accounting Standards 

Effective January 1, 2020, the Company adopted Accounting Standards Update ("ASU") 2016-13 and its related amendments.  This ASU primarily applies to the Company’s accounts receivable, of which the majority are due within 30 days. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analysis. The Company develops its estimated allowance for credit losses primarily using an aging method and analysis of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.

In November 2019, the FASB issued ASU 2019-12 – Income Taxes (“Topic 740”): Simplifying the Accounting for Income Taxes. The amendments in ASU 2019-12 are part of an initiative to reduce complexity in accounting standards and simplify the accounting for income taxes by removing certain exceptions from Topic 740 and making minor improvements to the codification. ASU 2019-12 and its related amendments will be effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.

In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 840): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (“ASU 2020-04”), which provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates (e.g., London Interbank Offered Rate (“LIBOR”)) that are expected to be discontinued. ASU 2020-04 allows, among other things, certain contract modifications, such as those within the scope of Topic 470 on debt, to be accounted as a continuation of the existing contract. This ASU was effective upon the issuance and its optional relief can be applied through December 31, 2022. The Company will consider this optional guidance prospectively, if applicable.

In May 2020, the SEC adopted final rules that amend the financial statement requirements for significant business acquisitions and dispositions. Among other changes, the final rules modify the significance tests and improve the disclosure requirements for acquired or to be acquired businesses and related pro forma financial information, the periods those financial statements must cover, and the form and content of the pro forma financial information. The final rules do not modify requirements for the acquisition and disposition of significant amounts of assets that do not constitute a business. The final rules are effective January 1, 2021, but earlier compliance is permitted. The Company will consider these final rules and update its disclosures, as applicable.

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Note 2 - Revenue From Contracts With Customers

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Revenue from Contract with Customer [Text Block]

2. Revenue from Contracts with Customers

Revenue Recognition

Sales of oil, gas and NGL are recognized at the point in time when control of the product is transferred to the customer and collectability is reasonably assured. The Company's contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, physical location, quality of the oil or gas, and prevailing supply and demand conditions. As a result, the price of the oil, gas and NGL fluctuates to remain competitive with other available oil, gas and NGL supplies in the market. The Company believes that the pricing provisions of our oil, gas and NGL contracts are customary in the industry.

Oil sales

The Company's oil sales contracts are generally structured such that it sells its oil production to a purchaser at a contractually specified delivery point at or near the wellhead. The crude oil production is priced on the delivery date based upon prevailing index prices less certain deductions related to oil quality, physical location and transportation costs incurred by the purchaser subsequent to delivery. The Company recognizes revenue when control transfers to the purchaser upon delivery at or near the wellhead at the net price received from the purchaser. Payment terms as customarily and normally paid on the twentieth day of the month following production.

Gas and NGL Sales

Under the Company's gas processing contracts, it delivers wet gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system.  There are no performance obligations related to these contracts. The midstream processing entity processes the gas and remits proceeds to the Company based upon either (i) the resulting sales price of NGL and residue gas received by the midstream processing entity from third party customers or (ii) the prevailing index prices for NGL and residue gas in the month of delivery to the midstream processing entity. Gathering, processing, transportation and other expenses incurred by the midstream processing entity are typically deducted from the proceeds that the Company receives.

In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. With respect to the Company's gas purchase contracts, the Company has concluded that it is the agent, and thus, the midstream processing entity is its customer. Accordingly, the Company recognizes revenue upon delivery to the midstream processing entity based on the net amount of the proceeds received from the midstream processing entity.

Imbalances  

The Company had no material gas imbalances at December 31, 2019 and 2020. 

Disaggregation of Revenue

The Company is focused on the development of oil and natural gas properties primarily located in the following three operating regions in the United States: (i) the Permian/Delaware Basin, (ii) Rocky Mountain and (iii) South Texas. Revenue attributable to each of those regions is disaggregated in the table below.

	Years Ended December 31,
	2019						2020
	Oil		Gas		NGL		Oil		Gas		NGL
Operating Region
Permian/Delaware Basin	$	52,789	$	494	$	602	$	22,891	$	335	$	163
Rocky Mountain	$	68,555	$	1,480	$	1,305	$	19,078	$	251	$	266
South Texas	$	3,159	$	605	$	3	$	-	$	-	$	-

Significant Judgments

Principal versus agent

The Company engages in various types of transactions in which midstream entities process the Company's gas and subsequently market resulting NGL and residue gas to third-party customers on behalf of the Company, such as the Company's percentage-of-proceeds and gas purchase contracts. These types of transactions require judgment to determine whether we are the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net.

Transaction price allocated to remaining performance obligations

A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC Topic 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC Topic 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract balances

Under the Company's product sales contracts, the Company is entitled to payment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional. The Company records invoiced amounts as “Accounts receivable - Oil and gas production sales” in the accompanying condensed consolidated balance sheet.

To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as “Accounts receivable - Oil and gas production sales” in the accompanying condensed consolidated balance sheets. In this scenario, payment is also unconditional, as the Company has satisfied its performance obligations through delivery of the relevant product. As a result, the Company has concluded that its product sales do not give rise to contract assets or liabilities under ASU 2014-09. At  December 31, 2019 and December 31, 2020, our receivables from contracts with customers were $17.0 million and $8.8 million, respectively.

Prior-period performance obligations

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

The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

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Note 3 - Reverse Stock Split

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Reverse Stock Split [Text Block]

3. Reverse Stock Split 

On  October 19, 2020 the Company effected a 1-for-20 reverse stock split of its issued and outstanding shares of common stock, $0.01 par value (the "Reverse Stock Split"). The Company effected the Reverse Stock Split pursuant to the Company’s filing of a Certificate of Change  with the Secretary of State of the State of Nevada on September 29, 2020. Under Nevada law, no amendment to the Company’s Articles of Incorporation was required in connection with the Reverse Stock Split. The Company was authorized to issue 400,000,000 shares of Common Stock. As a result of the Reverse Stock Split, the Company will be authorized to issue 20,000,000 shares of Common Stock.  As a result of the Reverse Stock Split, 168,069,305 outstanding shares of the Company’s common stock were exchanged for approximately 8,453,466 shares of the Company's common stock (subject to adjustment due to the effect of rounding fractional shares into whole shares). Under the terms of the Reverse Stock Split, fractional shares issuable to stockholders were rounded up to the nearest whole share. The Reverse Stock Split will not have any effect on the stated par value of the Common Stock.   All per share amounts and number of shares in the condensed consolidated financial statements and related notes have been retroactively restated to reflect the Reverse Stock Split, resulting in the transfer of $1.6 million from common stock to additional paid in capital at September 30, 2020 and   December 31, 2019.

Additionally on the effective date of the Reverse Stock Split, all options, warrants and other convertible securities of the Company outstanding immediately prior to the Reverse Stock Split were adjusted by dividing the number of shares of common stock into which the options, warrants and other convertible securities are exercisable or convertible by 20, and multiplying the exercise or conversion price thereof by 20, all in accordance with the terms of the plans, agreements or arrangements governing such options, warrants and other convertible securities and subject to rounding to the nearest whole share.

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Note 4 - Long-term Debt

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Long-term Debt [Text Block]

4. Long-Term Debt

The following sections regarding the First Lien Credit Facility and Second Lien Credit Facility are qualified in their entirety by the disclosure contained in Note 1. Going Concern, which is expressly incorporated in the sections above.  Due to certain of covenant violations under our credit facilities as of December 31, 2020, and the potential for future violations, all of the debt related to our credit facilities has been classified as current liabilities.

The following is a description of the Company’s debt as of  December 31, 2019 and 2020, respectively:

	Years Ended December 31,
	2019			2020
	(In thousands)
First Lien Credit Facility	$	95,778		$	95,000
Second Lien Credit Facility		100,000			112,695
Exit fee - Second Lien Credit Facility		-			10,000
Real estate lien note		3,091			2,810
		198,869			220,505
Less current maturities		(280	)		(202,751	)
		198,589			17,754
Deferred financing fees and debt issuance cost - net		(5,871	)		(15,239	)
Total long-term debt, net of deferred financing fees and debt issuance costs	$	192,718		$	2,515

Maturities of long-term debt are as follows:

Years ending December 31, (In thousands)
2021	$	217,990
2022		310
2023		2,205
2024		-
2025		-
Thereafter		-
Total	$	220,505

First Lien Credit Facility

The Company has a senior secured First Lien Credit Facility with Société Générale, as administrative agent and issuing lender, and certain other lenders.  As of December 31, 2020, $95.0 million was outstanding under the First Lien Credit Facility. 

Outstanding amounts under the First Lien Credit Facility accrue interest at a rate per annum equal to (a)(i) for borrowings that we elect to accrue interest at the reference rate  at the greater of (x) the reference rate announced from time to time by Société Générale, (y) the federal funds rate plus 0.5%, and (z)  daily one-month LIBOR plus, in each case, 1.5%-2.5%, depending on the utilization of the borrowing base, and (ii) for borrowings that  we elect to accrue interest at the Eurodollar rate, LIBOR plus 2.5%-3.5% depending on the utilization of the borrowing base and (b) at any time an event of default exists, 3.0% plus the amounts set forth above. At December 31, 2020, the interest rate on the First Lien Credit Facility was approximately 3.6%.

Subject to earlier termination rights and events of default, the stated maturity date of the First Lien Credit Facility is May 16, 2022. Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. The Company is permitted to terminate the First Lien Credit Facility and is able, from time to time, to permanently reduce the lenders’ aggregate commitment under the First Lien Credit Facility in compliance with certain notice and dollar increment requirements.

Each of the Company's subsidiaries has guaranteed our obligations under the First Lien Credit Facility on a senior secured basis. Obligations under the First Lien Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of the Company and its subsidiary guarantors’ material property and assets. As of December 30, 2020, the collateral is required to include properties comprising at least 90% of the PV-9 of the Company's proven reserves and 95% of the PV-9 of the Company's PDP reserves.

Under the amended First Lien Credit Facility, the Company is subject to customary covenants, including financial covenants and reporting covenants. The amendment to the First Lien Credit Facility dated June 25, 2020 (the "1L Amendment") modified certain provisions of the First Lien Credit Facility, including (i) the addition of monthly mandatory prepayments from excess cash (defined as available cash minus certain cash set-asides and a $3.0 million working capital reserve) with corresponding reductions to the borrowing base; (ii) the elimination of scheduled redeterminations (which were previously made every six months) and interim redeterminations (which were previously made at the request of the lenders no more than once in the six month period between scheduled redeterminations) of the borrowing base; (iii) the replacement of total debt leverage ratio and minimum asset ratio covenants with a first lien debt leverage ratio covenant (comparing the outstanding debt of the First Lien Credit Facility to the consolidated EBITDAX of the Company and requiring that the ratio not exceed 2.75 to 1.00 as of the last day of each fiscal quarter) and a minimum first lien asset coverage ratio covenant (comparing the sum of, without duplication, (A) the PV-15 of producing and developed proven reserves of the Company, (B) the PV-9 of the Company’s hydrocarbon hedge agreements and (C) the PV-15 of proved reserves of the Company classified as “drilled uncompleted” (up to 20% of the sum of (A), (B) and (C)) to the outstanding debt of the First Lien Credit Facility and requiring that the ratio exceed 1.15 to 1.00 as of the last day of each fiscal quarter ending on or before December 31, 2020, and 1.25 to 1.00 for fiscal quarters ending thereafter); (iv) the elimination of current ratio and interest coverage ratio covenants; (v) additional restrictions on (A) capital expenditures (limiting capital expenditures to $3.0 million in any four fiscal quarter period (commencing with the four fiscal quarter period ended  June 30, 2020 and calculated on an annualized basis for the 1, 2 and 3 quarter periods ending on June 30, 2020, September 30, 2020 and December 31, 2020, respectively, subject to certain exceptions, including capital expenditures financed with the proceeds of newly permitted, structurally subordinated debt and capital expenditures made when (1) the first lien asset coverage ratio is at least 1.60 to 1.00, (2) the Company is in compliance with the first lien leverage ratio, (3) the amounts outstanding under the First Lien Credit Facility are less $50.0 million, (4) no default exists under the First Lien Credit Facility and (5) and all representations and warranties in the First Lien Credit Facility and the related credit documents are true and correct in all material respects), (B) outstanding accounts payable (limiting all outstanding and undisputed accounts payable to $7.5 million, undisputed accounts payable outstanding for more than 60 days to $2.0 million and undisputed accounts payable outstanding for more than 90 days to $1.0 million and (C) general and administrative expenses (limiting cash general and administrative expenses the Company may make or become legally obligated to make in any four fiscal quarter period to $9.0 million for the four fiscal quarter period ended  June 30, 2020, $8.25 million for the four fiscal quarter period ended  September 30, 2020, $6.9 million for the four fiscal quarter period ending December 31, 2020, and $6.5 million for the fiscal quarter from  March 31, 2021 through December 31, 2021 and $5.0 million thereafter; in all cases, general and administrative expense excludes up to $1.0 million in certain legal and professional fees; and (vi) permission for up to an additional $25.0 million in structurally subordinated debt to finance capital expenditures. Under the 1L Amendment, the borrowing base was adjusted to $102.0 million. The borrowing base will be reduced by any mandatory prepayments from excess cash flow (in an amount equal to such prepayment) and upon the disposition of the Company’s oil and gas properties.

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The First Lien Credit Facility contains a number of covenants that, among other things, restrict our ability to: 

• incur or guarantee additional indebtedness;

• transfer or sell assets;

• pay dividends or make other distributions on capital stock or make other restricted payments;

• engage in transactions with affiliates other than on an "arm's length" basis;

• make any change in the principal nature of our business; and

• permit a change in control

The First Lien Credit Facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. 

As of December 31, 2020 we were not in compliance with the First Lien Debt to consolidated EBITDAX under the First Lien Credit Facility, as amended.

Second Lien Credit Facility

On November 13, 2019, we entered into the Term Loan Credit Agreement, with Angelo Gordon Energy Servicer, LLC, as administrative agent, and certain other lenders party thereto, which we refer to as the Second Lien Credit Facility. The Second Lien Credit facility was amended on June 25, 2020. The Second Lien Credit Facility has a maximum commitment of $100.0 million. On November 13, 2019, $95.0 million of the net proceeds obtained from the Second Lien Credit Facility were used to permanently reduce the borrowings outstanding on the First Lien Credit Facility.  As of December 31,  2020, the outstanding balance on the Second Lien Credit Facility was $122.7 million, which includes a $10.0 million exit fee. 

The stated maturity date of the Second Lien Credit Facility is November 13, 2022. Prior to the latest amendments of the Second Lien Credit Facility, accrued interest was payable quarterly on reference rate loans and at the end of each three-month interest period on Eurodollar loans. We are permitted to prepay the loans in whole or in part, in compliance with certain notice and dollar increment requirements.

Each of our subsidiaries has guaranteed our obligations under the Second Lien Credit Facility. Obligations under the Second Lien Credit Facility are secured by a first priority perfected security interest, subject to certain permitted liens, including those securing the indebtedness under the First Lien Credit Facility to the extent permitted by the Intercreditor Agreement, of even date with the Second Lien Credit Facility, among us, our subsidiaries, Angelo Gordon Energy Servicer, LLC and Société Générale, in all of our subsidiary guarantors’ material property and assets. As of December 31, 2020, the collateral is required to include properties comprising at least 90% of the PV-9 of the Company's proven reserves and 95% of the PV-9 of the Company's PDP reserves. 

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Under the amended Second Lien Credit Facility, the Company is subject to customary covenants, including financial covenants and reporting covenants. The amendment to the Second Lien Credit Facility dated June 25, 2020 (the "2L Amendment") modified certain provisions of the Second Lien Credit Facility, including (i) a requirement that, while the obligations under the First Lien Credit Facility are outstanding, scheduled payments of accrued interest under the Second Lien Credit Facility will be paid in the form of capitalized interest; (ii) an increase in the interest rate by 200bps for interest payable in cash and 500bps for interest payable in kind; (iii) modification of the minimum asset ratio covenant to be the sum of, without duplication, (A) the PV-15 of producing and developed proven reserves of the Company, (B) the PV-9 of the Company’s hydrocarbon hedge agreements and (C) the PV-15 of proved reserves of the Company classified as “drilled uncompleted” (up to 20% of the sum of (A), (B) and (C)) to the total outstanding debt of the Company and requiring that the ratio not exceed 1.45 to 1.00 as of the last day of each fiscal quarter ending between September 30, 2021 to December 31, 2021, and 1.55 to 1.00 for fiscal quarters ending thereafter); (iv) modification of the total leverage ratio covenant to set the first test date to occur on September 30, 2021; (v) modification of the current ratio to eliminate the exclusion of certain valuation accounts associated with hedge contracts from current assets and from current liabilities, (vi) additional restrictions on (A) capital expenditures (limiting capital expenditures to those expenditures set forth in a plan of development approved by Angelo Gordon Energy Servicer, LLC, subject to certain exceptions, including capital expenditures financed with the proceeds of newly permitted, structurally subordinated debt), (B) outstanding accounts payable (limiting all outstanding and undisputed accounts payable to $7.5 million, undisputed accounts payable outstanding for more than 60 days to $2.0 million and undisputed accounts payable outstanding for more than 90 days to $1.0 million and (C) general and administrative expenses (limiting cash general and administrative expenses the Company may make or become legally obligated to make in any four fiscal quarter period to $9.0 million for the four fiscal quarter period ended  June 30, 2020, $8.25 million for the four fiscal quarter period ended  September 30, 2020, $6.5 million for fiscal quarter period from March 31, 2021 through December 31, 2021 and $5.0 million thereafter. 

The Second Lien Credit Facility contains a number of covenants that, among other things, restrict our ability to:

● incur or guarantee additional indebtedness;

● transfer or sell assets;

● create liens on assets;

● pay dividends or make other distributions on capital stock or make other restricted payments; 

● engage in transactions with affiliates other than on an “arm’s length” basis;

● make any change in the principal nature of our business; and

● permit a change of control

The Second Lien Credit Facility also contains customary events of default, including nonpayment of principal or interest, violation of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities.

Events of default have occurred, or are reasonably likely to occur, under the Second Lien Credit Facility as a result of (i) our failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, (ii) our failure to cause certain deposit accounts to be subject to control agreements in favor of the administrative agent for the Second Lien Credit Facility, (iii)  the failure of the Company to meet certain hedging requirements, and (iv) certain cross-defaults that have occurred, or may occur, as a result of the occurrence of events of default under the First Lien Credit Facility and the Second Lien Credit Facility and corresponding cross-defaults or similar termination events under our hedging contracts.

On April 16, 2021, we received a Notice of Default and Reservation of Rights (the “Notice of Default”) from Angelo Gordon stating that we have defaulted under the Second Lien Credit Facility, and that, as a result, the lenders have accelerated our obligations due thereunder and have reserved their rights to pursue additional remedies in the future.

The Notice of Default describes certain events of default that occurred under the Second Lien Credit Facility as a result of (i) our failure to file timely our Form 10-K for the fiscal year ended December 31, 2020, (ii) our failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, and (iii) other defaults under our revolving credit facility.

The Notice of Default declares that our obligations under the Second Lien Credit Facility are immediately due and payable, in each case without presentment, demand, protest or other requirements of any kind, and have begun to bear interest at the rate applicable to such amount under the Second Lien Credit Facility, plus an additional 3%. Additionally, the administrative agent and the lenders have reserved their right to exercise further rights, powers and remedies under the Second Lien Credit Facility, at any time or from time to time, with respect to any of the events of default described above. Angelo Gordon has agreed to forbear from exercising remedies available to it until May 6, 2021.

In connection with the amendment to the Second Lien Credit Facility on June 25, 2020, the Company entered into an Exit Fee and Warrant Agreement subject to NASDAQ approval for the issuance of the issuance of certain warrants. This agreement was finalized on August 11, 2020 at which time the Company issued a warrant to the lender to purchase a total of 33,445,792 shares of common stock at an exercise price of $0.01 per share. On October 19, 2020, the Company effected a reverse stock split of the Company’s authorized, issued and outstanding shares of common stock at a ratio of 1-for-20, thus the warrant was adjusted to provide that the lender may purchase a total of 1,672,290 shares of common stock at an exercise price of $0.20 per share. The warrant is exercisable immediately in whole or in part, on or before five years from the issuance date. The fair value of the warrant and exit fee were recorded as debt issuance costs, presented in the consolidated balance sheets as a deduction from the carrying amount of the note payable, and are being amortized over the loan term. The exit fee shall be due and payable in cash on the earliest to occur of maturity of the obligation under the Second Lien Credit Agreement or the earlier acceleration or payment in full of the same. The 2L Amendment, including the impact of the Exit Fee and Warrant Agreement finalized on August 11, 2020, resulted in the 2L Amendment meeting the criteria of debt extinguishment under the guidance of ASC 470: Debt. Accordingly, all debt issuance cost, including the original discount, of the original Second Lien Credit Facility, were charged to debt extinguishment loss in the accompanying Condensed Consolidated Statement of Operation in the amount of $4.1 million.

Real Estate Lien Note

We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. The outstanding principal accrues interest at a fixed rate of 4.9%. The note is payable in monthly installments of principal and interest in the amount of $35,672.  The maturity date of the note is July 20, 2023. As of   December 31, 2019, and 2020, $3.1 million and $2.8 million, respectively, were outstanding on the note.

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Note 5 - Property and Equipment

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Property, Plant and Equipment Disclosure [Text Block]

5. Property and Equipment

The major components of property and equipment, at cost, are as follows:

	Estimated		December 31,
	Useful life		2019			2020
	Years		(In thousands)
Oil and gas properties (1)		-	$	1,162,094		$	1,167,333
Equipment and other		3-39		15,187			15,348
Drilling rig		15		24,108			24,108
				1,201,389			1,206,789
Accumulated depreciation, depletion, amortization and impairment				(872,431	)		(1,083,843	)
Net Property and Equipment			$	328,958		$	122,946

(1) Oil and gas properties are amortized utilizing the units of production method.

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Note 6 - Stock-based Compensation and Option Plans

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Share-based Payment Arrangement [Text Block]

6.  Stock-Based Compensation and Option Plans

The Company’s Amended and Restated 2005 Employee Long-Term Equity Incentive Plan reserves 0.6 million shares of Abraxas common stock, subject to adjustment following certain events. Awards may be in options or shares of restricted stock. Options have a term not to exceed 10 years. Options issued under this plan vest according to a vesting schedule as determined by the compensation committee of the Company’s board of directors. Vesting may occur upon (1) the attainment of one or more performance goals or targets established by the committee, (2) the optionee’s continued employment or service for a specified period of time, (3) the occurrence of any event or the satisfaction of any other condition specified by the committee, or (4) a combination of any of the foregoing.

Stock Options

The Company grants options to its officers, directors, and other employees under various stock option and incentive plans. There were no options granted in  2019 or 2020

The following table is a summary of the Company’s stock option activity for the three years ended December 31:

	Options			Weighted average		Weighted average		Intrinsic value
	(000s)			exercise price		remaining life		per share
Options outstanding December 31, 2018		378		$	47.35
Granted		-			-
Exercised		(23	)		19.63
Forfeited/Expired		(58	)		48.02
Options outstanding December 31, 2019		297		$	49.41
Granted		-			-
Exercised		-			-
Forfeited/Expired		(101	)		48.96
Options outstanding December 31, 2020		196			49.69		3.8	$	0.00
Exercisable at end of year		192			49.64		3.9	$	0.00

Other information pertaining to the Company’s stock option activity for the three years ended December 31:

	2019		2020
Weighted average grant date fair value of stock options granted (per share)	$	-	$	-
Total fair value of options vested (000's)	$	732	$	275
Total intrinsic value of options exercised (000's)	$	141	$	-

As of December 31, 2020, the total compensation cost related to non-vested awards not yet recognized was approximately $0.06 million, which will be recognized in 2021 through 2022. For the years ended December 31, 2019, and 2020, we recognized $0.4 million and $0.1 million, respectively, in stock-based compensation expense relating to options.

The following table represents the range of stock option prices and the weighted average remaining life of outstanding options as of   December 31, 2020:

	Outstanding Options						Exercisable
			Weighted		Weighted				Weighted		Weighted
			average		average				average		average
	Number		remaining		exercise		Number		remaining		exercise
Range of stock option prices	Outstanding		life		price		Outstanding		life		price
19.40-29.99		66,025		4.9	$	20.02		66,025		4.9	$	20.02
30.00-39.99		5,350		6.4	$	37.47		5,263		6.4	$	34.46
40.00-49.99		19,459		2.2	$	47.73		19,447		2.2	$	47.73
50.00-59.99		13,900		6.0	$	55.81		11,400		5.7	$	56.33
60.00-69.99		52,646		3.8	$	63.14		52,646		3.8	$	63.14
70.00-79.99		19,075		1.8	$	73.22		19,075		1.8	$	73.22
80.00-89.99		3,650		2.9	$	84.15		3,650		2.9	$	84.14
90.00-99.99		12,625		1.8	$	93.38		12,625		1.8	$	93.38
100.00-125.60		2,450		3.3	$	107.97		2,450		3.3	$	17.97
		195,180		3.9	$	49.69		192,581		3.8	$	49.64

Restricted Stock Awards

Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such stock is determined using the market price on the grant date. Compensation expense is recorded over the applicable restricted stock vesting periods. As of December 31, 2020, the total compensation cost related to non-vested awards not yet recognized was approximately $1.4 million, which will be recognized from 2020 through 2022. For the years ended  December 31, 2019 and 2020, we recognized  $1.0 million and $0.9 million, respectively, in stock-based compensation expense related to restricted stock awards.

The following table is a summary of the Company’s restricted stock activity for the three years ended December 31, 2020:

	Number of Shares			Weighted average grant date fair value
Unvested December 31, 2018		42		$	43.07
Granted		66			26.75
Vested/Released		(14	)		42.98
Forfeited/Expired		(5	)		30.71
Unvested December 31, 2019		89		$	31.67
Granted		-			-
Vested/Released		(33	)		32.11
Forfeited/Expired		(15	)		31.52
Unvested December 31, 2020		41		$	31.37

Performance Based Restricted Stock Awards

Effective on April 1, 2018, the Company issued performance-based shares of restricted stock to certain officers and employees under the Abraxas Petroleum Corporation Amended and Restated 2005 Employee Long-Term Equity Incentive Plan. The shares will vest in 2021 upon the achievement of performance goals based on the Company’s Total Shareholder Return (“TSR”) as compared to a peer group of companies.  The number of shares which would vest depends upon the rank of the Company’s TSR as compared to the peer group at the end of the three-year vesting period, and can range from zero percent of the initial grant up to 200% of the initial grant.

The table below provides a summary of  Performance Based Restricted Stock as of the date indicated (shares in thousands):

	Number of Shares			Weighted average grant date fair value
Unvested December 31, 2018		20			47.40
Granted		40			26.80
Vested/Released		-			-
Forfeited		(3	)		30.38
Unvested December 31, 2019		57		$	33.86
Granted		-			-
Vested/Released		-			-
Forfeited		(13	)		34.29
Unvested December 31, 2020		44		$	33.73

Compensation expense associated with the performance based restricted stock is based on the grant date fair value of a single share as determined using a Monte Carlo Simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the performance based restricted stock awards with shares of the Company's common stock, the awards are accounted for as equity awards and the expense is calculated on the grant date assuming a 100% target payout and amortized over the life of the awards.

As of December 31, 2020, the total compensation cost related to non-vested awards not yet recognized was approximately $0.4 million, which will be recognized from 2020 through 2022.  For the years ended  December 31, 2019 and 2020, we recognized $0.5 million and $0.3 million, respectively, in stock-based compensation expense related to performance based restricted stock awards.

Director Stock Awards

The 2005 Directors Plan (as amended and restated) reserves 70,000 shares of Abraxas common stock, subject to adjustment following certain events. The 2005 Directors Plan provides that each year, at the first regular meeting of the board of directors immediately following Abraxas’ annual stockholder’s meeting, each non-employee director shall be granted or issued awards restricted stock with a value at the date of the grant of $12,000, for participation in board and committee meetings during the previous calendar year. This grant did not take place in 2020.

The maximum annual award for any one person is 1,250 shares of Abraxas common stock or options for common stock.  If options, as opposed to shares, are awarded, the exercise price shall be no less than 100% of the fair market value on the date of the award while the option terms and vesting schedules are at the discretion of the committee.  

Warrants for Common Stock

As of December 31, 2020, outstanding warrants to purchase shares of common stock were as follows:

Issuance Date	Exercisable for	Expiration Date	Exercise Price		Number of Shares
August 11, 2020	Common Stock	August 11, 2025	$	0.20		1,672,290

In connection with the amended Second Lien Credit Agreement, on August 11, 2020, the Company issued a warrant to the lender to purchase a total of 33,445,792 shares of common stock at an exercise price of $0.01 per share. On October 19, 2020 the Company effected a reverse stock split of the Company's authorized, issued and outstanding shares of common stock at a ratio of 1-for-20, thus the warrant was adjusted to provide that the lender may purchase a total of 1,672,290 shares of common stock at an exercise price of $0.20 per share the warrant is  exercisable immediately, in whole or in part, on or before five years from the issuance date. The fair value of the warrant was recorded as debt issuance costs, presented in the consolidated balance sheets as a deduction from the carrying amount of the note payable, and is being amortized over the loan term. 

At December 31, 2020, the Company had approximately 450 thousand shares reserved for future issuance for conversion of its stock options, and incentive plans for the Company’s directors, employees and consultants.

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Note 7 - Income Taxes

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Income Tax Disclosure [Text Block]

7. Income Taxes

The Company has determined that a revision was required to correct the December 31, 2019 disclosure of deferred tax liabilities, certain deferred tax assets and the valuation allowance to reflect state income taxes. The effect of these revisions to the net deferred tax asset balance had no impact on the Company’s consolidated balance sheet, statements of operations or statement of cash flow as previously reported. The revisions have been reflected in the 2019 amounts in the following tables.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.  Significant components of the Company’s deferred tax liabilities and assets are as follows:

	As of December 31,
	2019			2020
	(In thousands)
Deferred tax liabilities:
Hedge contracts	$	-		$	4,299
Other		3,158			2,137
Total deferred tax liabilities		3,158			6,436
Deferred tax assets:
US full cost pool	$	9,595			35,500
Depletion carryforward		3,722			461
U.S. net operating loss carryforward		68,250			84,927
Alternative minimum tax credit		6			-
Hedge contracts		1,661			-
Interest disallowed		-			2,818
Total deferred tax assets		83,234			123,706
Valuation allowance for deferred tax assets		(80,076	)		(117,270	)
Net deferred tax assets		3,158			6,436
Net deferred tax	$	-		$	-

Significant components of the provision (benefit) for income taxes are as follows:

	Years Ended December 31,
	2019		2020
	(In thousands)
Current:
Federal	$	-	$	-
State		-		-
	$	-	$	-
Deferred:
Federal	$	-	$	-
	$	-	$	-

At December 31, 2020, the Company had, $245.20 million of pre 2018 NOLs for U.S. tax purposes and $140.0 million of post 2017 NOLs for U.S. tax purposes.  Our pre-2018 NOLs will expire in varying amounts from 2022 through 2037, if not utilized; and can offset 100% of future taxable income for regular tax purposes. Any NOLs arising in 2018, 2019 and 2020 can generally be carried back five years, carried forward indefinitely and can offset 100% of future taxable income for tax years before January 1, 2021 and up to 80% of future taxable income for tax years after December 31, 2020. Any NOLs arising on or after January 1, 2021, cannot be carried back and can generally be carried forward indefinitely and can offset up to 80% of future taxable income for regular tax purposes, (the alternative minimum tax no longer applies to corporations after January 1, 2018).

The use of our NOLs will be limited if there is an "ownership change" in our common stock, generally a cumulative ownership change exceeding 50% during a three year period, as determined under Section 382 of the Internal Revenue Code. As of December 31, 2020, we have not had an ownership change as defined by Section 382. Given historical losses, uncertainties exist as to the future utilization of the NOL carryforwards, therefore, the Company has established a valuation allowance of $80.08  million at  December 31, 2019 and $117.27 million at December 31, 2020.

The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is:

	Years Ended December 31,
	2019			2020
	(in thousands)
Tax benefit at U.S. Statutory rates	$	13,651		$	38,749
Change in deferred tax asset valuation allowance		(12,767	)		(37,193	)
Alternative minimum tax expense		(745	)		-
Expired capital loss carryover		(3,966	)		-
Permanent differences		(403	)		(276	)
Return to provision estimated revision		341			(3,069	)
State income taxes, net of federal effect		3,892			1,789
Other		(3	)		-
	$	-		$	-

As of   December 31, 2019 and 2020, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years 2014 through 2020 remain open to examination by the tax jurisdictions to which the Company is subject.

New tax legislation, commonly referred to as the Tax Cuts and Jobs Act (H.R. 1), was enacted on December 22, 2017. Since our federal deferred tax asset was fully offset by a valuation allowance, the reduction in the U.S. corporate income tax rate to 21% did not materially affect the Company's financial statements. Significant provisions  that may impact income taxes in future years include: the repeal of the corporate Alternative Minimum Tax, the limitation on the current deductibility of net interest expense in excess of 30% of adjusted taxable income for levered balance sheets, (for tax years 2019 & 2020, the CARES Act temporarily adjusted the limitation in excess of 50% of adjusted taxable income for levered balance sheets at the taxpayer’s discretionary election), a limitation on utilization of net operating losses generated after tax year 2017 to 80% of taxable income, the unlimited carryforward of net operating losses generated after tax year 2017, temporary 100% expensing of certain business assets, additional limitations on certain general and administrative expenses, and changes in determining the excessive compensation limitation. Currently, we do not anticipate paying cash federal income taxes in the near term due to any of the legislative changes, primarily due to the availability of our net operating loss carryforwards. Future interpretations relating to the recently enacted U.S. federal income tax legislation which vary from our current interpretation and possible changes to state tax laws in response to the recently enacted federal legislation may have a significant effect on this projection. 

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Note 8 - Commitments and Contingencies

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Commitments and Contingencies Disclosure [Text Block]

8. Commitments and Contingencies

Litigation and Contingencies

From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business.  At December 31, 2020, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on the Company.

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Note 9 - Earnings Per Share

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Earnings Per Share [Text Block]

9. Earnings per Share

The following table sets forth the computation of basic and diluted earnings per share:

	Years Ended December 31,
	2019			2020
Numerator:
Net (loss)	$	(65,004	)	$	(184,522	)
Denominator for basic earnings per share - weighted-average common shares outstanding		8,312			8,382
Effect of dilutive securities: Stock options, restricted shares and performance based shares		3			-
Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options, restricted shares and performance based shares		8,315			8,382
Net (loss) per common share - basic	$	(7.82	)	$	(22.01	)
Net (loss) per common share - diluted	$	(7.82	)	$	(22.01	)

Basic earnings per share, excluding any dilutive effects of stock options and unvested restricted stock, is computed by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted income (loss) per share is computed similar to basic; however diluted income (loss) per share reflects the assumed conversion of all potentially dilutive securities.   For the year ended December 31, 2019,  four thousand potential shares relating to stock options and unvested restricted shares were excluded from the calculation of diluted (loss) income per share since their inclusion would have been anti-dilutive due to a loss in the period and the fact that all outstanding options are underwater.

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Note 10 - Benefit Plans

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Compensation and Employee Benefit Plans [Text Block]

10. Benefit Plans

The Company has a defined contribution plan (401(k) plan) covering all eligible employees. For  2019, in accordance with the safe harbor provisions of the Plan, the Company contributed $284,905. The Company will contribute $142,820 to the plan for 2020. The Company adopted the safe harbor provisions which requires it to contribute a fixed match to each participating employee’s contribution to the plan. The fixed match is set at the rate of dollar for dollar on the first 1% of eligible pay contributed, then 50 cents on the dollar for each additional percentage point of eligible pay contributed, up to 5%. Each employee’s eligible pay with respect to calculating the fixed match is limited by IRS regulations. In addition, the Board of Directors, at its sole discretion, may authorize the Company to make additional contributions to each participating employee. The employee contribution limit for 2019 was $19,000 for employees under the age of 50 and $25,000 for employees 50 years of age or older. The employee contribution limit was increased in 2020 to $19,500 for employees under the age of 50 and $26,000 for employees 50 years of age and older. 

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Note 11 - Hedging Program and Derivatives

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Derivative Instruments and Hedging Activities Disclosure [Text Block]

11. Hedging Program and Derivatives

The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations.  Our derivative contracts have not been designated for hedge accounting as prescribed by ASC 815; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. There are no netting agreements relating to these derivative contracts and there is no policy to offset.

The following table sets forth the summary position of our derivative contracts as of December 31, 2020

	Oil - WTI
Contract Periods	Daily Volume (Bbl)		Swap Price (per Bbl)
Fixed Swaps
January - December 2021		2,889	$	57.62
January - December 2022		2,412	$	50.60
January - December 2023		1,498	$	50.60
January - December 2024		1,585	$	50.60

The following table illustrates the impact of derivative contracts on the Company’s balance sheet:

Fair Value Derivative Contracts as of December 31, 2019
	Asset Derivatives			Liability Derivatives
Derivatives not designated as hedging instruments	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity price derivatives	Derivatives - current	$	83	Derivatives - current	$	10,688
Commodity price derivatives	Derivatives - long-term		4,170	Derivatives - long-term		999
		$	4,253		$	11,687

Fair Value Derivative Contracts as of December 31, 2020
	Asset Derivatives			Liability Derivatives
Derivatives not designated as hedging instruments	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity price derivatives	Derivatives - current	$	9,639	Derivatives - current	$	480
Commodity price derivatives	Derivatives - long-term		10,281	Derivatives - long-term		-
		$	19,920		$	480

Gains and losses from derivative activities are reflected as “Loss (gain) on derivative contracts” in the accompanying Consolidated Statements of Operations.  The net estimated value of our commodity derivative contracts was an asset of approximately  $19.4 million as of December 31, 2020. For the year-ended December 31, 2020, we recognized a gain of $42.9 million, consisting of a gain of $17.5 million on closed contracts and a gain of  $25.4 million on the mark to market valuation on open contracts. For the year ended December 31, 2019, we recognized  a loss on our derivative contracts of million approximately $26.8 million, consisting of a loss of $6.0 million on closed contracts and a loss of $20.8 million on the mark to market valuation of open contracts.

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Note 12 - Financial Instruments

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Fair Value Disclosures [Text Block]

12. Financial Instruments

There is 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 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

• Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

• Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Company is further required to assess the creditworthiness of the counter-party to the derivative contract. The results of the assessment of non-performance risk, based on the counter-party’s credit risk, could result in an adjustment of the carrying value of the derivative instrument. The following tables sets forth information about the Company’s assets and liabilities measured at fair value on a recurring basis as of  December 31, 2019 and 2020, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2019
Assets:
NYMEX fixed price derivative contracts	$	-	$	4,253	$	-	$	4,253
NYMEX basis differential swap		-		-		-		-
Total Assets	$	-	$	4,253	$	-	$	4,253
Liabilities:
NYMEX fixed price derivative contracts	$	-	$	5,583	$	-	$	5,583
NYMEX basis differential swap		-		-		6,104		6,104
Total Liabilities	$	-	$	5,583	$	6,104	$	11,687

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2020
Assets:
NYMEX fixed price derivative contracts	$	-	$	19,920	$	-	$	19,920
Total Assets	$	-	$	19,920	$	-	$	19,920
Liabilities:
NYMEX fixed price derivative contracts	$	-	$	480	$	-	$	480
Total Liabilities	$	-	$	480	$	-	$	480

The Company’s derivative contracts at December 31, 2020 and  December 31, 2019 consisted of NYMEX-based fixed price commodity swaps and basis differential swaps.  The NYMEX-based fixed price derivative contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity and are commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivative contracts. As the fair value of these derivative contracts is based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, we have characterized these derivative contracts as Level 2. In order to verify the third party valuation, we enter the various inputs into a model and compare our results to the third party for reasonableness. The fair value of the basis swaps are based on inputs that are not as observable as the fixed price swaps. In addition to the actively quoted market price, variables such as time value, volatility and other unobservable inputs are used. Accordingly, these instruments have been classified as Level 3.

Additional information for the Company's recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the year ended December 31, 2020.

	(In thousands)
Fair value at January 1, 2020	$	(6,104	)
Changes in market value		4,577
Settlements during the period		1,527
Fair value at December 31, 2020	$	-

There were no transfers from level 3 in 2020.

Nonrecurring Fair Value Measurements

Non-financial assets and liabilities measured at fair value on a nonrecurring basis included certain non-financial assets and liabilities as may be acquired in a business combination and thereby measured at fair value and the initial recognition of asset retirement obligations for which fair value is used. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, the economic viability of development if proved reserves were assigned and other current market conditions. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligation is presented in Note 1.

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable and accounts payable approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying value of our debt approximates fair value as the interest rates are market rates and this debt is considered Level 2.

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Note 13 - Lease Accounting Standard

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Lessee, Operating Leases [Text Block]

13. Lease Accounting Standard

Nature of Leases

We lease certain real estate, field equipment and other equipment under cancelable and non-cancelable leases to support our operations. A more detailed description of our significant lease types is included below.

Real Estate Leases

We rent a residence in North Dakota from a third party for living accommodations for certain field employees. Our real estate lease is non-cancelable with a term of five years, through August 31, 2024. We have concluded our real estate agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreements subsequent to the primary term.

Field Equipment

We rent compressors and coolers from third parties in order to facilitate the downstream movement of our production from our drilling operations to market. Our compressor and cooler arrangements are typically structured with a non-cancelable primary term of one year and continue thereafter on a month-to-month basis subject to termination by either party with thirty days' notice. These leases are considered short term and are not capitalized. We have a small number of compressor leases that are longer than  twelve months. We have concluded that our compressor and cooler rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term. We enter into daywork contracts for drilling rigs with third parties to support our drilling activities. Our drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells or well pads by providing thirty days' notice prior to the end of the original contract term. We have concluded that our drilling rig arrangements represent short-term operating leases. The accounting guidance requires us to make an assessment at contract commencement if we are reasonably certain that we will exercise the option to extend the term. Due to the continuously evolving nature of our drilling schedules and the potential volatility in commodity prices in an annual period, our strategy to enter into shorter term drilling rig arrangements allows us the flexibility to respond to changes in our operating and economic environment. We exercise our discretion in choosing to extend or not extend contracts on a rig by rig basis depending on the conditions present at the time the contract expires. At the time of contract commencement, we have determined we cannot conclude with reasonable certainty if we will choose to extend the contract beyond its original term. Pursuant to the full cost method, these costs are capitalized as part of natural gas and oil properties on our balance sheet when paid.

Discount Rate

Our leases typically do not provide an implicit rate. Accordingly, we are required to use our incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our incremental borrowing rate reflects the estimated rate of interest that we would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. We use the implicit rate in the limited circumstances in which that rate is readily determinable.

Practical Expedients and Accounting Policy Elections

Certain of our lease agreements include lease and non-lease components. For all existing asset classes with multiple component types, we have utilized the practical expedient that exempts us from separating lease components from non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component. In addition, for all of our existing asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less and does not include an option to purchase the underlying asset that we are reasonably certain to exercise). Accordingly, we recognize lease payments related to our short-term leases in our statement of operations on a straight-line basis over the lease term which has not changed from our prior recognition. To the extent that there are variable lease payments, we recognize those payments in our statement of operations in the period in which the obligation for those payments is incurred. None of our current leases contain variable payments.  Refer to “Nature of Leases” above for further information regarding those asset classes that include material short-term leases.

The components of our total lease expense for the years ended December 31,2019 and  December 31, 2020, the majority of which is included in lease operating expense, are as follows:

	For the Year Ended December 31,
	2019		2020
	(in thousands)
Operating lease cost	$	478	$	114
Short-term lease expense (1)		1,992		2,183
Total lease expense	$	2,470	$	2,297
Short-term lease costs (2)	$	4,900	$	973

(1)	Short-term lease expense represents expense related to leases with a contract term of 12 months or less.
(2)	These short-term lease costs are related to leases with a contract term of 12 months or less which are related to drilling rigs and are capitalized as part of natural gas and oil properties on our balance sheet.

Supplemental balance sheet information related to our operating leases is included in the table below:
 

	For the Year Ended December 31,
	2019		2020
	(in thousands)
Operating lease Right of Use asset	$	327	$	228
Operating lease liability - current	$	98	$	53
Operating lease liabilities - long-term	$	203	$	150

Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows:

	For the Year Ended December 31,
	2019			2020
	(in thousands)
Weighted Average Remaining Lease Term (in years)		8.66			10.68
Weighted Average Discount Rate		6	%		6	%

Our lease liabilities with enforceable contract terms that are greater than one year mature as follows:

	Operating Leases
	(in thousands)
2021	$	63
2022		48
2023		41
2024		28
2025		4
Thereafter		98
Total lease payments		282
Less imputed interest		(79	)
Total lease liability	$	203

Supplemental cash flow information related to our operating leases is included in the table below:

	For the Year Ended December 31,
	2019		2020
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities	$	478	$	114
Right of Use assets added in exchange for lease obligations (since adoption)	$	770	$	125

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Note 14 - Subsequent Events

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Subsequent Events [Text Block]

14. Subsequent Events

Paycheck Protection Program Loan

On May 4, 2020, the Company entered into an unsecured loan with the U.S. Small Business Administration ("SBA") in the amount of $1.4 million under the Paycheck Protection Program (the "PPP Loan") with an interest rate of 1.0% and maturity date two years from the effective date of the PPP Laon. The Paycheck Protection Program was established under the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act") and is administered by the SBA.  Payments are required to be made in seventeen monthly installments of principal and interest, with the first payment being due on the date that is seven months after the date of the PPP loan. Under the CARES Act, the PPP Loan was eligible for forgiveness for the portion of the PPP Loan proceeds used for payroll costs and other designated operating expenses for up to eight weeks, provided at least 75% of PPP Loan proceeds are used for payroll costs and the Company meets all necessary criteria for forgiveness. Receipt of these funds required the Company to, in good faith, certify that the PPP Loan was necessary to support ongoing operations of the Company during the economic uncertainty created by the COVID-19 pandemic. This certification further required the Company to take into account current business activity and the ability to access other sources of liquidity sufficient to support ongoing operations in a manner that was not significantly detrimental to the business. The PPP Loan, including accrued interest, was forgiven by the SBA in  January 2021. Accordingly, the Company will recognize a gain from debt extinguishment of $1.4 million in the first quarter of 2021.

In connection with the completion of our financial statements for the year ended December 31, 2020, the Company tested its financial ratios for the fiscal quarter ended December 31, 2020 and determined that it was not in compliance the first lien debt to consolidated EBITDAX ratio covenant under the First Lien Credit Facility.  Our failure to comply with such covenant contributed to our independent accountant’s including an explanatory paragraph with regard to the Company's ability to continue as a "going concern" in issuing their opinion on our financial statements for the year ended December 31, 2020.  The "going  concern" opinion resulted in an additional event of default under the First Lien Credit Facility and the Second Lien Credit Facility.  A discussion of the events of default follows.

First Lien Credit Facility

Events of default have occurred, or are reasonably likely to occur, under the First Lien Credit Facility as a result of (i) the Company's failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, (ii) its inability to comply with the first lien debt to consolidated EBITDAX ratio for the fiscal quarter ended December 31, 2020, (iii) our failure to cause certain deposit accounts to be subject to control agreements in favor of the administrative agent for the First Lien Credit Facility,  and (iv) certain cross-defaults that have occurred, or may occur, as a result of the events of default under the First Lien Credit Agreement and corresponding cross-defaults under the Second Lien Credit Facility and cross-defaults or similar termination events under our hedging contracts.

Second Lien Credit Facility

Events of default have occurred, or are reasonably likely to occur, under the Second Lien Credit Facility as a result of (i) the Company's failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, (ii) its failure to cause certain deposit accounts to be subject to control agreements in favor of the administrative agent for the Second Lien Credit Facility and (iii) the failure of the Company to meet certain hedging requirements, and (iv) certain cross-defaults that have occurred, or may occur, as a result of the occurrence of events of default under the First Lien Credit Facility and corresponding cross-defaults or similar termination events under our hedging contracts.

On April 16, 2021, we received a Notice of Default and Reservation of Rights (the “Notice of Default”) from Angelo Gordon stating that we have defaulted under the Second Lien Credit Facility, and that, as a result, the lenders have accelerated our obligations due thereunder and have reserved their rights to pursue additional remedies in the future.

The Notice of Default describes certain events of default that occurred under the Second Lien Credit Facility as a result of (i) our failure to file timely our Form 10-K for the fiscal year ended December 31, 2020, (ii) our failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, and (iii) other defaults under our revolving credit facility.

The Notice of Default declares that our obligations under the Second Lien Credit Facility are immediately due and payable, in each case without presentment, demand, protest or other requirements of any kind, and have begun to bear interest at the rate applicable to such amount under the Second Lien Credit Facility, plus an additional 3%. Additionally, the administrative agent and the lenders have reserved their right to exercise further rights, powers and remedies under the Second Lien Credit Facility, at any time or from time to time, with respect to any of the events of default described above. Angelo Gordon has agreed to forbear from exercising remedies available to it until May 6, 2021.

Hedging Contracts

Effective April 12, 2021, Morgan Stanley Capital Group, Inc. ("Morgan Stanley"), a hedge counterparty to several of our hedging contracts sent us notice of events of default and early termination with respect to the hedging contracts to which they are a counterparty.  The notice indicates Morgan Stanley’s election to exercise termination rights under the hedge contract, which Morgan Stanley asserts have arisen as a result of the occurrence of events of default under the First Lien Credit Facility, of which Morgan Stanley is a lender, holding approximately 3.7% of the outstanding obligations under the First Lien Credit Facility.  The termination value of the hedge contracts with Morgan Stanley as of the effective date of the notice was approximately $9.1 million.  We subsequently voluntarily terminated most of our other hedging arrangements. As a result of the settlement of the terminated hedges, we have outstanding obligations of $9.9 million, including the $9.1 million to Morgan Stanley. The settlement values of the terminated hedges were determined at various dates between April 15 and April 30, 2021. These obligations will be added to the balance of the First Lien Credit Facility and accrue interest  at the default interest rate, currently 6.7% until repaid. Other hedging agreements may also be terminated as a result as a result of the events of default. The termination of additional hedging contracts may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. Amounts that we may owe as a result of terminated hedging contracts will accrue interest for so long as such amounts remain unpaid.

Forbearance Discussions

The existing events of default under the credit facilities are subject to forbearance agreements with our lenders that currently expire on May 6, 2021,  but no assurances can be provided that the forbearance agreements will be further extended.  If the forbearance agreements are extended, we would expect to negotiate with the lenders and the hedge counterparties during the forbearance period regarding a waiver of existing and prospective defaults.  No assurances can be provided that any waivers will be obtained.

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Note 15 - Quarterly Results of Operations (Unaudited)

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Quarterly Financial Information [Text Block]

15. Quarterly Results of Operations (Unaudited)

Selected results of operations for each of the fiscal quarters during the years ended  December 31, 2019 and 2020 are as follows:

	1st			2nd			3rd			4th
	Quarter			Quarter			Quarter			Quarter
	(In thousands, except per share data)
Year Ended December 31, 2019
Net revenue	$	34,514		$	34,820		$	31,536		$	28,276
Operating income (loss)	$	6,708		$	8,935		$	8,053		$	(49,412	)
Net income (loss)	$	(25,455	)	$	11,678		$	17,041		$	(68,268	)
Net income (loss) per common share - basic	$	(3.00	)	$	1.40		$	2.00		$	(8.20	)
Net income (loss) per common share - diluted	$	(3.00	)	$	1.40		$	2.00		$	(8.20	)
Year Ended December 31, 2020
Net revenue	$	15,726		$	1,993		$	12,595		$	12,729
Operating income (loss)	$	(29,781	)	$	(61,474	)	$	(56,661	)	$	(51,502	)
Net income (loss)	$	41,443		$	(83,256	)	$	(73,615	)	$	(69,094	)
Net income (loss) per common share - basic	$	4.80		$	(10.00	)	$	(8.80	)	$	(8.21	)
Net income (loss) per common share - diluted	$	4.80		$	(10.00	)	$	(8.80	)	$	(8.21	)

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2020

Notes to Financial Statements

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

16. Supplemental Oil and Gas Disclosures (Unaudited)

The accompanying tables present information concerning the Company’s oil and gas producing activities “Disclosures about Oil and Gas Producing Activities.”  Capitalized costs relating to oil and gas producing activities are as follows as of December 31:

	Years Ended December 31,
	(in thousands)
	2019			2020
Proved oil and gas properties	$	1,162,094		$	1,167,333
Unproved properties		-			-
Total		1,162,094			1,167,333
Accumulated depreciation, depletion, amortization and impairment		(851,107	)		(1,060,649	)
Net capitalized costs	$	310,987		$	106,684

Cost incurred in oil and gas property acquisition and development activities were as follows for the years ended December 31 (in thousands):

	2019		2020
Development costs	$	92,884	$	5,238
Exploration costs		-		-
Property acquisition costs		-		-
	$	92,884	$	5,238

Results of operations from oil and gas producing activities were as follows for the years ended December 31:

	2019			2020
Revenues	$	128,992		$	42,984
Production costs		(38,229	)		(21,090	)
Depreciation, depletion and amortization		(51,041	)		(22,679	)
Accretion of future site restoration		(436	)		(414	)
Proved property impairment		(51,293	)		(186,980	)
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$	(12,007	)	$	(188,179	)
Depletion rate per barrel of oil equivalent	$	14.12		$	12.59

Estimated Quantities of Proved Oil and Gas Reserves

Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and gas properties.  Accordingly, the estimates are expected to change as future information becomes available.  The estimates have been predominately prepared by independent petroleum reserve engineers. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. All of the Company’s proved reserves are located in the continental United States.

Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements; therefore, the unweighted average prior 12-month first-day-of-the-month commodity prices and year-end costs were used in estimating reserve volumes and future net cash flows for the periods presented.

The following set forth changes in estimated net proved reserves for the years ended December 31, 2019 and 2020.

										Oil
	Oil			NGL			Gas			Equivalents
	(MBbl)			(MBbl)			(MMcf)			(Mboe)
Change in Proved Reserves
Balance at December 31, 2018		42,237			10,034			89,744			67,228
Revisions of previous estimates		(15,616	)		(2,713	)		(23,178	)		(22,192	)
Extensions and discoveries		13,477			2,285			14,073			18,109
Purchases of minerals in place		-			-			-			-
Sales of minerals in place		(1,431	)		(86	)		(9,898	)		(3,167	)
Production		(2,388	)		(548	)		(4,076	)		(3,616	)
Balance at December 31, 2019		36,279			8,972			66,665			56,362
Revisions of previous estimates		(16,922	)		(3,549	)		(27,921	)		(25,125	)
Extensions and discoveries		-			-			-			-
Removal of PUDs		(8,687	)		(1,922	)		(12,291	)		(12,658	)
Production		(1,132	)		(313	)		(2,135	)		(1,801	)
Balance at December 31, 2020		9,538			3,188			24,318			16,778

The following is a summary of the changes to the Company’s proved reserves that occurred during 2020:

Revisions to prior estimates:

 There was a decrease of 56 MBoe of net reserves attributable to changes in projections for the Company’s producing wells based on actual performance during 2020. 

The Company converted 29 proved undeveloped Wolfcamp A1 locations, and 25 3rd Bone Spring locations in Ward County, Texas, to probable undeveloped reserves during 2020 accounting for 17,616 MBoe of net reserves.  The Company converted five proved undeveloped Middle Bakken locations and nine Three Forks locations in McKenzie County, North Dakota, to probable undeveloped reserves during 2020 accounting for 5,153 MBoe of net reserves.  The Company converted two proved undeveloped Delaware Montoya locations in Ward County, Texas, to probable undeveloped reserves during 2020 accounting for 2,300 MBoe of net reserves.  These locations are no longer included in the Company’s five-year development schedule.

Extensions, discoveries and other additions: 

The Company did not add any new proved reserves during 2020 due to either extensions or discoveries.

Purchases:

The Company did not acquire any new proved reserves during 2020.

Sales: 

The Company did not sell any proved reserves during 2020.

Production: 

The Company produced 1,801 MBoe of net proved reserves during 2020. 

The following is a summary of the changes to the Company’s proved reserves that occurred during 2019:

Revisions to prior estimates:

There was a decrease of 8,790 MBoe of net reserves attributable to changes in projections for the Company’s producing wells based on actual performance during 2019.  The Company also converted eight proved undeveloped Wolfcamp A1 locations, twenty-four Wolfcamp A2 locations, one 3rd Bone Spring location, and two Wolfcamp B locations in Ward County, Texas, to probable undeveloped reserves during 2019 accounting for 13,402 MBoe of net reserves.  These locations are no longer included in the Company’s five-year development plan.

Extensions, discoveries and other additions: 

The Company added two new proved undeveloped Wolfcamp A locations, and nine 3rd Bone Spring locations in Ward County, Texas, accounting for 3,776 MBoe of net reserves.  These locations are direct offsets to either successful Abraxas producing wells or those operated by others. The Company converted eighteen probable undeveloped Wolfcamp A1 locations, twenty-four Wolfcamp 3rd Bone Spring locations in Ward County, Texas, and one Three Forks location in McKenzie County, North Dakota to proved undeveloped reserves during 2019 accounting for 14,333 MBoe of net reserves.

Purchases:

The Company did not acquire new wells during 2019.

Sales: 

The Company sold all its holdings in the Gulf Coast Area accounting for 1,839 MBoe of net proved reserves. The Company sold fourteen producing non-operated Permian locations in Marion, Pecos, and Reeves Counties, Texas, accounting for 42 MBoe of net reserves. The Company sold substantially all its holdings in the non-operated Bakken Area accounting for 1,268 MBoe of net proved reserves.  Other miscellaneous asset sales during the year accounted for 18 MBoe of net reserves.

Production: 

The Company produced 3,616 MBoe of net reserves during 2019. 

The following table presents the Company's estimate of its net proved developed and undeveloped oil and gas reserves as of December 31, 2019 and 2020:

	Total
							Oil
	Oil		NGL		Gas		Equivalents
	(MBbl)		(MBbl)		(MMcf)		(Mboe)
Proved Developed Reserves:
December 31, 2019		10,964		2,699		21,439		17,237
December 31, 2020		9,538		3,187		24,318		16,778
Proved Undeveloped Reserves:
December 31, 2019		25,315		6,273		45,226		39,125
December 31, 2020		-		-		-		-

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The Company’s proved oil and gas reserves have been estimated by the independent petroleum engineering firm, DeGolyer & MacNaughton, assisted by the engineering and operations departments of the Company as of  December 31, 2019 and  December 31, 2020. The following information has been prepared in accordance with SEC rules and accounting standards based on the 12-month first-day-of-the-month unweighted average prices in accordance with provisions of the FASB’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future net cash flows have not been adjusted for commodity derivative contracts outstanding at the end of each year. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the tax basis and net operating losses associated with the properties.  Since prices used in the calculation are average prices for 2019, and 2020, the standardized measure could vary significantly from year to year based on the market conditions that occurred during a given year.

The technical personnel responsible for preparing the reserve estimates at DeGolyer & MacNaughton meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer & MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.    All reports by DeGolyer & MacNaughton were developed utilizing studies performed by DeGolyer & MacNaughton and assisted by the Engineering and Operations departments of Abraxas. Reserves are estimated by independent petroleum engineers.  The report of DeGolyer & MacNaughton dated February 12, 2021, contains further discussions of the reserve estimates and evaluations prepared by DeGolyer & MacNaughton as well as the qualifications of DeGolyer & MacNaughton’s technical personnel responsible for overseeing such estimates and evaluations is attached as Exhibit 99.1 to this report.

Estimates of proved reserves at  December 31, 2019 and 2020 were based on studies performed by our independent petroleum engineers assisted by the Engineering and Operations departments of Abraxas.  The Engineering department is directly responsible for Abraxas’ reserve evaluation process.  The Vice President of Engineering is the manager of this department and is the primary technical person responsible for this process.  The Vice President of Engineering holds a Bachelor of Science degree in Petroleum Engineering and has 42 years of experience in reserve evaluations. The Vice President of Engineering is a Registered Professional Engineer in the State of Texas.  The operations department of Abraxas assisted in the process.

The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted to represent the fair market value of the Company’s proved oil and gas reserves.  An estimate of fair market value would also take into account, among other factors, the recovery of reserves not classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure. The table below sets forth the Standardized Measure of our proved oil and gas reserves for the years ended  December 31, 2019  and 2020 :

	Years Ended December 31,
	(in thousands)
	2019			2020
Future cash inflows	$	1,890,579		$	345,869
Future production costs		(598,714	)		(166,781	)
Future development costs		(544,111	)		(6,291	)
Future income tax expense		-			-
Future net cash flows		747,754			172,797
Discount	$	(440,142	)	$	(66,113	)
Standardized Measure of discounted future net cash relating to proved reserves	$	307,612		$	106,684

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following is an analysis of the changes in the Standardized Measure for the periods indicated (in thousands):

	Years Ended December 31,
	(in thousands)
	2019			2020
Standardized Measure, beginning of year	$	651,884		$	307,612
Sales and transfers of oil and gas produced, net of production costs		(90,763	)		(21,894	)
Net change in prices and development and production costs from prior year		(218,092	)		(96,688	)
Extensions, discoveries, and improved recovery, less related costs		98,780			-
Sales of minerals in place		(17,276	)		-
Removal of PUDs		-			(80,416	)
Revisions of previous estimates		(227,477	)		(159,613	)
Change in timing and other		(13,744	)		126,922
Change in future income tax expense		59,112			-
Accretion of discount		65,188			30,761
Standardized Measure, end of year	$	307,612		$	106,684

The standardized measure is based on the following oil and gas prices over the life of the properties as of the following dates:

	Years Ended December 31,
	2019		2020
Oil (per Bbl) (1)	$	55.73	$	39.54
Gas (per Mmbtu) (2)	$	2.54	$	2.03
Oil (per Bbl) (3)	$	52.14	$	37.05
Gas (per Mmbtu) (4)	$	0.63	$	0.27
NGL's (per Bbl) (5)	$	3.48	$	1.37

_____________________

(1) The quoted oil price for the year ended December 31 of each year,  2019 and 2020 is the 12-month unweighted average first-day-of-the-month West Texas Intermediate spot price for each month of  2019 and 2020.

(2) The quoted gas price for the year ended  December 31, 2019 and 2020 is the 12-month unweighted average first-day-of-the-month Henry Hub spot price for each month of  2019 and 2020.

(3) The oil price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.

(4) The gas price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.

(5) The NGL price is the realized price as of December 31 of each year after the appropriate differentials have been applied.

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Consolidation, Policy [Policy Text Block]

Nature of Operations

We are an independent energy company primarily engaged in the acquisition, exploitation, development and production of oil and gas in the United States.  Our oil and gas assets are located primarily in two operating regions in the United States: the Rocky Mountains and Permian/Delaware Basin.

The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including Raven Drilling LLC (“Raven Drilling”).

Going Concern Qualification, Policy [Policy Text Block]

Going Concern

Our present level of indebtedness and the recent commodity price environment present challenges to our ability to comply with certain covenants in our credit facilities and under applicable auditing standards the independent accountants' opinion on our  financial statements for the year ended December 31, 2020 contains an explanatory paragraph regarding the Company's ability to continue as a "going concern".  At December 31, 2020, we had a total of $95.0  million outstanding under our First Lien Credit Facility, $112.7 million under our Second Lien Credit facility, and total indebtedness of  $220.5 million including a $10.0 million exit fee. As of April 30, 2021, we had a total of $89.5  million outstanding under our First Lien Credit Facility,  $127.2  million under our Second Lien Credit Facility, including a  $10.0 million exit fee, and total indebtedness of $219.4 million. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements.

Specifically, with regard to our credit agreements, we did not satisfy the first lien debt to consolidated EBITDAX ratio covenant under our First Lien Credit Facility as of the December 31, 2020 measurement date and such failure represented an event of default under our First Lien Credit Facility. In addition,  we do not anticipate that we will  maintain compliance with the Second Lien Credit Facility total leverage ratio covenant or the minimum asset coverage ratio (as defined in Note 4) both of which will be  first tested as of September 30, 2021, over the next twelve months and, accordingly, the audit report prepared by our auditors with respect to the financial statements for the year ended December 31, 2020 includes an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern.” The inability to maintain compliance with certain covenants of our Second Lien Credit Facility would represent an additional default under our First Lien Credit Facility as of the end of any such future fiscal quarters. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty.

We are evaluating the available financial alternatives and are in discussion with our lenders seeking additional waivers or amendments to the covenants or other provisions of our credit facilities to address any current and future default relating to the covenants in question. The existing defaults at  March 31, 2021 are subject to forbearance agreements with our lenders that currently expire on  May 6, 2021. No assurance can be provided that the forbearance agreements will be further extended. If, upon a future default, the Company is unable reach an agreement with its lenders or find acceptable alternative financing, the lenders under the Company's First Lien Credit Facility  may choose to accelerate repayment. If the Company's lenders accelerate the payment of amounts outstanding under its credit facilities, the Company does not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so. The Company could attempt to obtain additional sources of capital from asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination thereof. However, the Company cannot provide any assurances that it will be successful in obtaining capital from such transactions on acceptable terms, or at all. 

Under applicable accounting principles these circumstances are deemed to create substantial doubt regarding the Company's ability to continue as a "going concern". The consolidated financial statements have been prepared on a "going concern" basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business for the twelve-month period following the date of issuance of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amount, or the amount and classification of liabilities that may result should the Company be unable to continue as a "going concern".

In April 2021, we received notice that certain of our hedging agreements were being terminated as a result of events of default under the First Lien Credit Facility, and we voluntarily terminated most of our other  hedging arrangements. As a result of the settlement of the terminated hedges, we have outstanding obligations of $9.9 million. The settlement values of the terminated hedges were determined at various dates between April 15 and April 30, 2021. These obligations will be added to the balance of the First Lien Credit Facility and accrue interest  at the default interest rate, currently 6.7%, until repaid. Our remaining  hedging agreements may also be terminated as a result of such events of default. The settlement of terminated hedging agreements may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. See Note 14 “Subsequent Events” for current information regarding non-compliance with certain covenants.

Rig Accounting [Policy Text Block]

Rig Accounting

In accordance with SEC Regulation S-X, no income is recognized in connection with contractual drilling services performed in connection with properties in which the Company or its affiliates holds an ownership, or other economic interest. Any income not recognized as a result of this limitation is credited to the full cost pool and recognized through lower amortization as reserves are produced. During part of 2019 and all of 2020 the drilling rig was idle, accordingly the cost of the rig was charged to the statement of operations.

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

The consolidated financial statements of the Company have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

The most significant estimates pertain to proved oil, gas and NGL reserves and related cash flow estimates used in impairment tests of oil and gas properties, the fair value of assets and liabilities acquired in business combinations, derivative contracts, the provision for income taxes including uncertain tax positions, stock based compensation, asset retirement obligations, accrued oil and gas revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates.

The process of estimating oil and gas reserves in accordance with SEC requirements is complex and involves decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data.  Accordingly, these estimates are imprecise.  Actual future production, oil and gas prices, differentials, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated.  Any significant variance could materially affect the estimated quantities and present value of our reserves.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, our ability to fund estimated development cost, prevailing oil and gas prices and other factors, many of which are beyond our control.

Reclassification, Comparability Adjustment [Policy Text Block]

Reclassifications

Certain reclassifications have been made to the prior year financial statements to conform to the current period presentation.  These reclassifications were to share and per share data related to the 1 for 20 reverse stock split effective October 19, 2020 and had no effect on our previously reported results of operations.

Concentration Risk, Credit Risk, Policy [Policy Text Block]

Concentration of Credit Risk

Financial instruments which potentially expose the Company to credit risk consist principally of trade receivables and derivative contracts.  Accounts receivable are generally from companies with significant oil and gas marketing or operating activities.  The Company performs ongoing credit evaluations and, generally, requires no collateral from its customers. The counterparties to our derivative contracts are the same financial institutions from which we have outstanding debt; accordingly, we believe our exposure to credit risk to these counterparties is currently mitigated in part by this, as well as the current overall financial condition of the counterparties.

The Company maintains any cash and cash equivalents in excess of federally insured limits in prominent financial institutions considered by the Company to be of high credit quality.

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three months or less.

Accounts Receivable [Policy Text Block]

Accounts Receivable

Accounts receivable are reported net of an allowance for doubtful accounts of approximately $0.1 million at  December 31, 2019 and 2020 . The allowance for doubtful accounts is determined based on the Company's historical losses, as well as a review of certain accounts. Accounts are charged off when collection efforts have failed and the account is deemed uncollectible.

Segment Reporting, Policy [Policy Text Block]

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development and production of oil and gas with all of the Company’s operational activities being  conducted in the U.S. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long lived assets located outside the U.S.

Full Cost Method Using Gross Revenue Method, Policy [Policy Text Block]

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas properties.  Under this method, certain direct costs and indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves.  Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Costs in excess of the present value of estimated future net revenues are charged to proved property impairment expense.  No gain or loss is recognized upon sale or disposition of oil and gas properties for full cost accounting companies with proceeds accounted for as an adjustment of capitalized cost. An exception to this rule occurs when the adjustment to the full cost pool results in a significant alteration of the relationship between capitalized cost and proved reserves. The Company applies the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. The impairment calculations do not consider the impact of our commodity derivative positions as generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges.   As of  December 31, 2019 and 2020, our capitalized cost of oil and gas properties exceeded the future net revenue from our estimated proved reserves resulting in the recognition of an impairment of $51.3 million  and  $187.0  million, respectively.

Property, Plant and Equipment, Policy [Policy Text Block]

Other Property and Equipment

Other property and equipment are recorded at cost.  Depreciation of other property and equipment is provided over the estimated useful lives using the straight-line method.  Major renewals and improvements are recorded as additions to the property and equipment accounts.  Repairs that do not improve or extend the useful lives of assets are expensed.

Estimate of Proved Oil and Gas Reserves Policy [Policy Text Block]

Estimates of Proved Oil and Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

• the quality and quantity of available data;

• the interpretation of that data;

• the accuracy of various mandated economic assumptions; and

• the judgment of the persons preparing the estimate.

Our proved reserve information included in this report was based on studies performed by our independent petroleum engineers assisted by the engineering and operations departments of Abraxas. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may cause material revisions to the estimate.

In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the average of oil and gas prices based on the unweighted average 12 month first-day-of-month pricing. Future prices and costs may be materially higher or lower than these prices and costs which would impact the estimated value of our reserves.

The estimates of proved reserves materially impact depreciation, depletion and amortization, or DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields.

Derivatives, Policy [Policy Text Block]

Derivative Instruments and Hedging Activities

The Company enters into agreements to hedge the risk of future oil and gas price fluctuations.  Such agreements are typically in the form of fixed price commodity and basis swaps, which limit the impact of price fluctuations with respect to the Company’s sale of oil and gas. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions could arise where actual production is less than estimated which could result in over hedged volumes.

All derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The derivative instruments the Company utilizes are based on index prices that may and often do differ from the actual oil and gas prices realized in its operations.  These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for hedge accounting rules as prescribed by Accounting Standards Codification (“ASC”) 815. Accordingly, the Company does not account for its derivative instruments as cash flow hedges for financial reporting purposes.  Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in net gains (losses) on commodity derivative contracts in the Consolidated Statements of Operations.

Fair Value of Financial Instruments, Policy [Policy Text Block]

Fair Value of Financial Instruments

The Company includes fair value information in the notes to consolidated financial statements when the fair value of its financial instruments is materially different from the carrying value.  The carrying value of those financial instruments that are classified as current, except for derivative instruments, approximates fair value because of the short maturity of these instruments.  For noncurrent financial instruments, the Company uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments.

Share-based Payment Arrangement [Policy Text Block]

Share-Based Payments

  Options granted are valued at the date of grant and expense is recognized over the vesting period. The Company currently utilizes a standard option pricing model (Black-Scholes) to measure the fair value of stock options granted to employees and directors. Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such restricted stock is determined using the market price on the grant date and expense is recorded over the vesting period. For the years ended  December 31, 2019  and 2020, stock-based compensation was approximately  $1.9 million and $1.3 million, respectively.

Asset Retirement Obligation and Environmental Cost [Policy Text Block]

Restoration, Removal and Environmental Liabilities

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites.  Environmental expenditures are expensed or capitalized depending on their future economic benefit.  Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.

Liabilities for expenditures of a noncapital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable.

The fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period and the capitalized cost is depreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and we amortize these costs as a component of our depletion expense in the accompanying consolidated financial statements. Each year, the Company reviews, and to the extent necessary, revises its asset retirement obligation estimates.

The following table (in thousands) summarizes changes in the Company’s future site restoration obligations during the two years ended December 31: 

	2019			2020
Beginning future site restoration obligation	$	7,492		$	7,420
New wells placed on production and other		80			43
Deletions related to property disposals		(473	)		(216	)
Deletions related to plugging costs		(890	)		(235	)
Accretion expense and other		436			414
Revisions and other		775			(66	)
Ending future site restoration obligation	$	7,420		$	7,360

Revenue [Policy Text Block]

Revenue Recognition and Major Purchasers

The Company recognizes oil and gas revenue from its interest in producing wells as oil and gas is sold from those wells, net of royalties, control of the product has transferred to the purchaser and collectability  is reasonably assured. The Company had no material gas imbalances at  December 31, 2019 and 2020.

During 2019 two purchasers accounted for 71% of oil and gas revenues. During 2020, four purchasers accounted for 73% of oil and gas revenues.

Deferred Charges, Policy [Policy Text Block]

Deferred Financing Fees

Deferred financing fees are being amortized on the effective yield basis over the term of the related debt.

Income Tax, Policy [Policy Text Block]

Income Taxes

Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to be in effect with respect to taxable income in the years in which those temporary differences are expected to be recovered or settled. Uncertainties exist as to the future utilization of the operating loss carryforwards. Therefore, we have established a valuation allowance of $117.27 million for deferred tax assets at December 31, 2020.

Income Tax Uncertainties, Policy [Policy Text Block]

Accounting for Uncertainty in Income Taxes

Evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.

Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period in which the threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not criteria should be de-recognized in the first subsequent reporting period in which the threshold is no longer met. Penalties and interest are classified as income tax expense. The Company had no uncertain income tax positions as of December 31, 2020.

New Accounting Pronouncements, Policy [Policy Text Block]

Adoption of New Accounting Standards 

Effective January 1, 2020, the Company adopted Accounting Standards Update ("ASU") 2016-13 and its related amendments.  This ASU primarily applies to the Company’s accounts receivable, of which the majority are due within 30 days. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analysis. The Company develops its estimated allowance for credit losses primarily using an aging method and analysis of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.

In November 2019, the FASB issued ASU 2019-12 – Income Taxes (“Topic 740”): Simplifying the Accounting for Income Taxes. The amendments in ASU 2019-12 are part of an initiative to reduce complexity in accounting standards and simplify the accounting for income taxes by removing certain exceptions from Topic 740 and making minor improvements to the codification. ASU 2019-12 and its related amendments will be effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.

In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 840): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (“ASU 2020-04”), which provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates (e.g., London Interbank Offered Rate (“LIBOR”)) that are expected to be discontinued. ASU 2020-04 allows, among other things, certain contract modifications, such as those within the scope of Topic 470 on debt, to be accounted as a continuation of the existing contract. This ASU was effective upon the issuance and its optional relief can be applied through December 31, 2022. The Company will consider this optional guidance prospectively, if applicable.

In May 2020, the SEC adopted final rules that amend the financial statement requirements for significant business acquisitions and dispositions. Among other changes, the final rules modify the significance tests and improve the disclosure requirements for acquired or to be acquired businesses and related pro forma financial information, the periods those financial statements must cover, and the form and content of the pro forma financial information. The final rules do not modify requirements for the acquisition and disposition of significant amounts of assets that do not constitute a business. The final rules are effective January 1, 2021, but earlier compliance is permitted. The Company will consider these final rules and update its disclosures, as applicable.

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Note 1 - Organization and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2020

Notes Tables

Schedule of Change in Asset Retirement Obligation [Table Text Block]

	2019			2020
Beginning future site restoration obligation	$	7,492		$	7,420
New wells placed on production and other		80			43
Deletions related to property disposals		(473	)		(216	)
Deletions related to plugging costs		(890	)		(235	)
Accretion expense and other		436			414
Revisions and other		775			(66	)
Ending future site restoration obligation	$	7,420		$	7,360

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Note 2 - Revenue From Contracts With Customers (Tables)

12 Months Ended

Dec. 31, 2020

Notes Tables

Disaggregation of Revenue [Table Text Block]

	Years Ended December 31,
	2019						2020
	Oil		Gas		NGL		Oil		Gas		NGL
Operating Region
Permian/Delaware Basin	$	52,789	$	494	$	602	$	22,891	$	335	$	163
Rocky Mountain	$	68,555	$	1,480	$	1,305	$	19,078	$	251	$	266
South Texas	$	3,159	$	605	$	3	$	-	$	-	$	-

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Note 4 - Long-term Debt (Tables)

12 Months Ended

Dec. 31, 2020

Notes Tables

Schedule of Long-term Debt Instruments [Table Text Block]

	Years Ended December 31,
	2019			2020
	(In thousands)
First Lien Credit Facility	$	95,778		$	95,000
Second Lien Credit Facility		100,000			112,695
Exit fee - Second Lien Credit Facility		-			10,000
Real estate lien note		3,091			2,810
		198,869			220,505
Less current maturities		(280	)		(202,751	)
		198,589			17,754
Deferred financing fees and debt issuance cost - net		(5,871	)		(15,239	)
Total long-term debt, net of deferred financing fees and debt issuance costs	$	192,718		$	2,515

Contractual Obligation, Fiscal Year Maturity [Table Text Block]

Years ending December 31, (In thousands)
2021	$	217,990
2022		310
2023		2,205
2024		-
2025		-
Thereafter		-
Total	$	220,505

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Note 5 - Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2020

Notes Tables

Property, Plant and Equipment [Table Text Block]

	Estimated		December 31,
	Useful life		2019			2020
	Years		(In thousands)
Oil and gas properties (1)		-	$	1,162,094		$	1,167,333
Equipment and other		3-39		15,187			15,348
Drilling rig		15		24,108			24,108
				1,201,389			1,206,789
Accumulated depreciation, depletion, amortization and impairment				(872,431	)		(1,083,843	)
Net Property and Equipment			$	328,958		$	122,946

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Note 6 - Stock-based Compensation and Option Plans (Tables)

12 Months Ended

Dec. 31, 2020

Notes Tables

Share-based Payment Arrangement, Option, Activity [Table Text Block]

	Options			Weighted average		Weighted average		Intrinsic value
	(000s)			exercise price		remaining life		per share
Options outstanding December 31, 2018		378		$	47.35
Granted		-			-
Exercised		(23	)		19.63
Forfeited/Expired		(58	)		48.02
Options outstanding December 31, 2019		297		$	49.41
Granted		-			-
Exercised		-			-
Forfeited/Expired		(101	)		48.96
Options outstanding December 31, 2020		196			49.69		3.8	$	0.00
Exercisable at end of year		192			49.64		3.9	$	0.00

	2019		2020
Weighted average grant date fair value of stock options granted (per share)	$	-	$	-
Total fair value of options vested (000's)	$	732	$	275
Total intrinsic value of options exercised (000's)	$	141	$	-

Share-based Payment Arrangement, Option, Exercise Price Range [Table Text Block]

	Outstanding Options						Exercisable
			Weighted		Weighted				Weighted		Weighted
			average		average				average		average
	Number		remaining		exercise		Number		remaining		exercise
Range of stock option prices	Outstanding		life		price		Outstanding		life		price
19.40-29.99		66,025		4.9	$	20.02		66,025		4.9	$	20.02
30.00-39.99		5,350		6.4	$	37.47		5,263		6.4	$	34.46
40.00-49.99		19,459		2.2	$	47.73		19,447		2.2	$	47.73
50.00-59.99		13,900		6.0	$	55.81		11,400		5.7	$	56.33
60.00-69.99		52,646		3.8	$	63.14		52,646		3.8	$	63.14
70.00-79.99		19,075		1.8	$	73.22		19,075		1.8	$	73.22
80.00-89.99		3,650		2.9	$	84.15		3,650		2.9	$	84.14
90.00-99.99		12,625		1.8	$	93.38		12,625		1.8	$	93.38
100.00-125.60		2,450		3.3	$	107.97		2,450		3.3	$	17.97
		195,180		3.9	$	49.69		192,581		3.8	$	49.64

Schedule of Nonvested Restricted Stock Units Activity [Table Text Block]

	Number of Shares			Weighted average grant date fair value
Unvested December 31, 2018		42		$	43.07
Granted		66			26.75
Vested/Released		(14	)		42.98
Forfeited/Expired		(5	)		30.71
Unvested December 31, 2019		89		$	31.67
Granted		-			-
Vested/Released		(33	)		32.11
Forfeited/Expired		(15	)		31.52
Unvested December 31, 2020		41		$	31.37

Schedule of Nonvested Performance-based Units Activity [Table Text Block]

	Number of Shares			Weighted average grant date fair value
Unvested December 31, 2018		20			47.40
Granted		40			26.80
Vested/Released		-			-
Forfeited		(3	)		30.38
Unvested December 31, 2019		57		$	33.86
Granted		-			-
Vested/Released		-			-
Forfeited		(13	)		34.29
Unvested December 31, 2020		44		$	33.73

Schedule of Stockholders' Equity Note, Warrants or Rights [Table Text Block]

Issuance Date	Exercisable for	Expiration Date	Exercise Price		Number of Shares
August 11, 2020	Common Stock	August 11, 2025	$	0.20		1,672,290

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Note 7 - Income Taxes (Tables)

12 Months Ended

Dec. 31, 2020

Notes Tables

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

	As of December 31,
	2019			2020
	(In thousands)
Deferred tax liabilities:
Hedge contracts	$	-		$	4,299
Other		3,158			2,137
Total deferred tax liabilities		3,158			6,436
Deferred tax assets:
US full cost pool	$	9,595			35,500
Depletion carryforward		3,722			461
U.S. net operating loss carryforward		68,250			84,927
Alternative minimum tax credit		6			-
Hedge contracts		1,661			-
Interest disallowed		-			2,818
Total deferred tax assets		83,234			123,706
Valuation allowance for deferred tax assets		(80,076	)		(117,270	)
Net deferred tax assets		3,158			6,436
Net deferred tax	$	-		$	-

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

	Years Ended December 31,
	2019		2020
	(In thousands)
Current:
Federal	$	-	$	-
State		-		-
	$	-	$	-
Deferred:
Federal	$	-	$	-
	$	-	$	-

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

	Years Ended December 31,
	2019			2020
	(in thousands)
Tax benefit at U.S. Statutory rates	$	13,651		$	38,749
Change in deferred tax asset valuation allowance		(12,767	)		(37,193	)
Alternative minimum tax expense		(745	)		-
Expired capital loss carryover		(3,966	)		-
Permanent differences		(403	)		(276	)
Return to provision estimated revision		341			(3,069	)
State income taxes, net of federal effect		3,892			1,789
Other		(3	)		-
	$	-		$	-

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Note 9 - Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2020

Notes Tables

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

	Years Ended December 31,
	2019			2020
Numerator:
Net (loss)	$	(65,004	)	$	(184,522	)
Denominator for basic earnings per share - weighted-average common shares outstanding		8,312			8,382
Effect of dilutive securities: Stock options, restricted shares and performance based shares		3			-
Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options, restricted shares and performance based shares		8,315			8,382
Net (loss) per common share - basic	$	(7.82	)	$	(22.01	)
Net (loss) per common share - diluted	$	(7.82	)	$	(22.01	)

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Note 11 - Hedging Program and Derivatives (Tables)

12 Months Ended

Dec. 31, 2020

Notes Tables

Schedule of Fixed Price Derivatives [Table Text Block]

	Oil - WTI
Contract Periods	Daily Volume (Bbl)		Swap Price (per Bbl)
Fixed Swaps
January - December 2021		2,889	$	57.62
January - December 2022		2,412	$	50.60
January - December 2023		1,498	$	50.60
January - December 2024		1,585	$	50.60

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

Fair Value Derivative Contracts as of December 31, 2019
	Asset Derivatives			Liability Derivatives
Derivatives not designated as hedging instruments	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity price derivatives	Derivatives - current	$	83	Derivatives - current	$	10,688
Commodity price derivatives	Derivatives - long-term		4,170	Derivatives - long-term		999
		$	4,253		$	11,687

Fair Value Derivative Contracts as of December 31, 2020
	Asset Derivatives			Liability Derivatives
Derivatives not designated as hedging instruments	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity price derivatives	Derivatives - current	$	9,639	Derivatives - current	$	480
Commodity price derivatives	Derivatives - long-term		10,281	Derivatives - long-term		-
		$	19,920		$	480

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Note 12 - Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2020

Notes Tables

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2019
Assets:
NYMEX fixed price derivative contracts	$	-	$	4,253	$	-	$	4,253
NYMEX basis differential swap		-		-		-		-
Total Assets	$	-	$	4,253	$	-	$	4,253
Liabilities:
NYMEX fixed price derivative contracts	$	-	$	5,583	$	-	$	5,583
NYMEX basis differential swap		-		-		6,104		6,104
Total Liabilities	$	-	$	5,583	$	6,104	$	11,687

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2020
Assets:
NYMEX fixed price derivative contracts	$	-	$	19,920	$	-	$	19,920
Total Assets	$	-	$	19,920	$	-	$	19,920
Liabilities:
NYMEX fixed price derivative contracts	$	-	$	480	$	-	$	480
Total Liabilities	$	-	$	480	$	-	$	480

Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

	(In thousands)
Fair value at January 1, 2020	$	(6,104	)
Changes in market value		4,577
Settlements during the period		1,527
Fair value at December 31, 2020	$	-

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Note 13 - Lease Accounting Standard (Tables)

12 Months Ended

Dec. 31, 2020

Notes Tables

Lease, Cost [Table Text Block]

	For the Year Ended December 31,
	2019		2020
	(in thousands)
Operating lease cost	$	478	$	114
Short-term lease expense (1)		1,992		2,183
Total lease expense	$	2,470	$	2,297
Short-term lease costs (2)	$	4,900	$	973

	For the Year Ended December 31,
	2019			2020
	(in thousands)
Weighted Average Remaining Lease Term (in years)		8.66			10.68
Weighted Average Discount Rate		6	%		6	%

	For the Year Ended December 31,
	2019		2020
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities	$	478	$	114
Right of Use assets added in exchange for lease obligations (since adoption)	$	770	$	125

Schedule of Operating Leased Assets [Table Text Block]

	For the Year Ended December 31,
	2019		2020
	(in thousands)
Operating lease Right of Use asset	$	327	$	228
Operating lease liability - current	$	98	$	53
Operating lease liabilities - long-term	$	203	$	150

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

	Operating Leases
	(in thousands)
2021	$	63
2022		48
2023		41
2024		28
2025		4
Thereafter		98
Total lease payments		282
Less imputed interest		(79	)
Total lease liability	$	203

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Note 15 - Quarterly Results of Operations (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2020

Notes Tables

Quarterly Financial Information [Table Text Block]

	1st			2nd			3rd			4th
	Quarter			Quarter			Quarter			Quarter
	(In thousands, except per share data)
Year Ended December 31, 2019
Net revenue	$	34,514		$	34,820		$	31,536		$	28,276
Operating income (loss)	$	6,708		$	8,935		$	8,053		$	(49,412	)
Net income (loss)	$	(25,455	)	$	11,678		$	17,041		$	(68,268	)
Net income (loss) per common share - basic	$	(3.00	)	$	1.40		$	2.00		$	(8.20	)
Net income (loss) per common share - diluted	$	(3.00	)	$	1.40		$	2.00		$	(8.20	)
Year Ended December 31, 2020
Net revenue	$	15,726		$	1,993		$	12,595		$	12,729
Operating income (loss)	$	(29,781	)	$	(61,474	)	$	(56,661	)	$	(51,502	)
Net income (loss)	$	41,443		$	(83,256	)	$	(73,615	)	$	(69,094	)
Net income (loss) per common share - basic	$	4.80		$	(10.00	)	$	(8.80	)	$	(8.21	)
Net income (loss) per common share - diluted	$	4.80		$	(10.00	)	$	(8.80	)	$	(8.21	)

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2020

Notes Tables

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

	Years Ended December 31,
	(in thousands)
	2019			2020
Proved oil and gas properties	$	1,162,094		$	1,167,333
Unproved properties		-			-
Total		1,162,094			1,167,333
Accumulated depreciation, depletion, amortization and impairment		(851,107	)		(1,060,649	)
Net capitalized costs	$	310,987		$	106,684

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]

	2019		2020
Development costs	$	92,884	$	5,238
Exploration costs		-		-
Property acquisition costs		-		-
	$	92,884	$	5,238

Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]

	2019			2020
Revenues	$	128,992		$	42,984
Production costs		(38,229	)		(21,090	)
Depreciation, depletion and amortization		(51,041	)		(22,679	)
Accretion of future site restoration		(436	)		(414	)
Proved property impairment		(51,293	)		(186,980	)
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$	(12,007	)	$	(188,179	)
Depletion rate per barrel of oil equivalent	$	14.12		$	12.59

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]

										Oil
	Oil			NGL			Gas			Equivalents
	(MBbl)			(MBbl)			(MMcf)			(Mboe)
Change in Proved Reserves
Balance at December 31, 2018		42,237			10,034			89,744			67,228
Revisions of previous estimates		(15,616	)		(2,713	)		(23,178	)		(22,192	)
Extensions and discoveries		13,477			2,285			14,073			18,109
Purchases of minerals in place		-			-			-			-
Sales of minerals in place		(1,431	)		(86	)		(9,898	)		(3,167	)
Production		(2,388	)		(548	)		(4,076	)		(3,616	)
Balance at December 31, 2019		36,279			8,972			66,665			56,362
Revisions of previous estimates		(16,922	)		(3,549	)		(27,921	)		(25,125	)
Extensions and discoveries		-			-			-			-
Removal of PUDs		(8,687	)		(1,922	)		(12,291	)		(12,658	)
Production		(1,132	)		(313	)		(2,135	)		(1,801	)
Balance at December 31, 2020		9,538			3,188			24,318			16,778

	Total
							Oil
	Oil		NGL		Gas		Equivalents
	(MBbl)		(MBbl)		(MMcf)		(Mboe)
Proved Developed Reserves:
December 31, 2019		10,964		2,699		21,439		17,237
December 31, 2020		9,538		3,187		24,318		16,778
Proved Undeveloped Reserves:
December 31, 2019		25,315		6,273		45,226		39,125
December 31, 2020		-		-		-		-

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

	Years Ended December 31,
	(in thousands)
	2019			2020
Future cash inflows	$	1,890,579		$	345,869
Future production costs		(598,714	)		(166,781	)
Future development costs		(544,111	)		(6,291	)
Future income tax expense		-			-
Future net cash flows		747,754			172,797
Discount	$	(440,142	)	$	(66,113	)
Standardized Measure of discounted future net cash relating to proved reserves	$	307,612		$	106,684

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]

	Years Ended December 31,
	(in thousands)
	2019			2020
Standardized Measure, beginning of year	$	651,884		$	307,612
Sales and transfers of oil and gas produced, net of production costs		(90,763	)		(21,894	)
Net change in prices and development and production costs from prior year		(218,092	)		(96,688	)
Extensions, discoveries, and improved recovery, less related costs		98,780			-
Sales of minerals in place		(17,276	)		-
Removal of PUDs		-			(80,416	)
Revisions of previous estimates		(227,477	)		(159,613	)
Change in timing and other		(13,744	)		126,922
Change in future income tax expense		59,112			-
Accretion of discount		65,188			30,761
Standardized Measure, end of year	$	307,612		$	106,684

Oil and Gas Prices Considered in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]

	Years Ended December 31,
	2019		2020
Oil (per Bbl) (1)	$	55.73	$	39.54
Gas (per Mmbtu) (2)	$	2.54	$	2.03
Oil (per Bbl) (3)	$	52.14	$	37.05
Gas (per Mmbtu) (4)	$	0.63	$	0.27
NGL's (per Bbl) (5)	$	3.48	$	1.37

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Note 1 - Organization and Significant Accounting Policies (Details Textual) $ in Thousands		12 Months Ended
	Oct. 19, 2020	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Apr. 30, 2021 USD ($)	Apr. 14, 2021 USD ($)
Long-term Debt, Gross		$ 220,505	$ 198,869
Line of Credit, Exit Fee		10,000
Accounts Receivable, Allowance for Credit Loss, Ending Balance		$ 100	100
Discount Rate Used in Future Net Cash Flows Relating to Proved Oil and Gas Reserves		10.00%
Impairment of Oil and Gas Properties		$ 186,980	51,293
Share-based Payment Arrangement, Noncash Expense, Total		1,312	1,911
Deferred Tax Assets, Valuation Allowance, Total		$ 117,270	$ 80,076
Revenue Benchmark [Member] | Customer Concentration Risk [Member]
Entity Wide Revenue Number of Major Purchasers of Oil and Gas		4	2
Revenue Benchmark [Member] | Customer Concentration Risk [Member] | Two Purchasers [Member]
Concentration Risk, Percentage			71.00%
Revenue Benchmark [Member] | Customer Concentration Risk [Member] | Four Purchasers [Member]
Concentration Risk, Percentage		73.00%
Reverse Stock Split [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	20
Subsequent Event [Member]
Long-term Debt, Gross					$ 219,400
First Lien Credit Facility [Member]
Long-term Debt, Gross		$ 95,000
First Lien Credit Facility [Member] | Subsequent Event [Member]
Long-term Debt, Gross					89,500
First Lien Credit Facility [Member] | Subsequent Event [Member] | Obligations from Terminated Hedging Arrangements [Member]
Termination Value of Hedge Contracts				$ 9,900
Debt Instrument, Interest Rate, Stated Percentage				6.70%
Second Lien Credit Facility [Member]
Long-term Debt, Gross		$ 112,700
Second Lien Credit Facility [Member] | Subsequent Event [Member]
Long-term Debt, Gross					127,200
Line of Credit, Exit Fee					$ 10,000

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Note 1 - Organization and Significant Accounting Policies - Future Site Restoration Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Beginning future site restoration obligation	$ 7,420	$ 7,492
New wells placed on production and other	43	80
Deletions related to property disposals	(216)	(473)
Deletions related to plugging costs	(235)	(890)
Accretion expense and other	414	436
Revisions and other	(66)	775
Ending future site restoration obligation	$ 7,360	$ 7,420

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Note 2 - Revenue From Contracts With Customers (Details Textual) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Contract with Customer, Asset, after Allowance for Credit Loss, Total	$ 8.8	$ 17.0

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Note 2 - Revenue From Contracts With Customers - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Oil Revenues [Member]
Revenue	$ 41,969	$ 124,503
Gas Revenues [Member]
Revenue	586	2,579
Natural Gas Liquids Revenues [Member]
Revenue	429	1,910
Permian / Delaware Basin [Member] | Oil Revenues [Member]
Revenue	22,891	52,789
Permian / Delaware Basin [Member] | Gas Revenues [Member]
Revenue	335	494
Permian / Delaware Basin [Member] | Natural Gas Liquids Revenues [Member]
Revenue	163	602
Rocky Mountain [Member] | Oil Revenues [Member]
Revenue	19,078	68,555
Rocky Mountain [Member] | Gas Revenues [Member]
Revenue	251	1,480
Rocky Mountain [Member] | Natural Gas Liquids Revenues [Member]
Revenue	266	1,305
South Texas [Member] | Oil Revenues [Member]
Revenue	0	3,159
South Texas [Member] | Gas Revenues [Member]
Revenue	0	605
South Texas [Member] | Natural Gas Liquids Revenues [Member]
Revenue	$ 0	$ 3

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Note 3 - Reverse Stock Split (Details Textual) $ / shares in Units, $ in Millions		3 Months Ended	12 Months Ended
	Oct. 19, 2020 $ / shares shares	Sep. 30, 2020 USD ($)	Dec. 31, 2019 USD ($) $ / shares shares	Dec. 31, 2020 $ / shares shares	Oct. 18, 2020 shares
Common Stock, Par or Stated Value Per Share (in dollars per share) | $ / shares			$ 0.01	$ 0.01
Common Stock, Shares Authorized (in shares)			20,000,000	20,000,000
Common Stock, Shares, Outstanding, Ending Balance (in shares)			8,436,498	8,421,910
Reverse Stock Split [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	20
Common Stock, Par or Stated Value Per Share (in dollars per share) | $ / shares	$ 0.01
Common Stock, Shares Authorized (in shares)	20,000,000				400,000,000
Common Stock, Shares, Outstanding, Ending Balance (in shares)	8,453,466				168,069,305
Adjustments to Additional Paid in Capital, Stock Split | $		$ 1.6	$ 1.6

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Note 4 - Long-term Debt (Details Textual)					12 Months Ended
	Oct. 19, 2020 USD ($) $ / shares shares	Jun. 25, 2020 USD ($)	Nov. 13, 2019 USD ($)	Jun. 20, 2018 USD ($)	Dec. 31, 2020 USD ($) $ / shares shares	Dec. 31, 2019 USD ($)	Aug. 11, 2020 $ / shares shares
Line of Credit, Exit Fee					$ 10,000,000.0
Gain (Loss) on Extinguishment of Debt, Total					(4,108,000)	$ (0)
Long-term Debt, Total					$ 2,515,000	192,718,000
Reverse Stock Split [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	20
Warrant Issued to Lender [Member]
Class of Warrant or Right, Number of Securities Called by Warrants or Rights (in shares) | shares	1,672,290				1,672,290		33,445,792
Class of Warrant or Right, Exercise Price of Warrants or Rights (in dollars per share) | $ / shares	$ 0.20				$ 0.20		$ 0.01
Warrants and Rights Outstanding, Term (Year)	5 years
Line of Credit [Member] | First Lien Credit Facility [Member]
Long-term Line of Credit, Total					$ 95,000,000.0
Debt Instrument, Spread on Elected Variable Rate					0.50%
Debt Instrument, Debt Default, Basis Spread on Variable Rate					3.00%
Line of Credit Facility, Interest Rate at Period End					3.60%
Debt Instrument, Collateral Eligible, Minimum Percent of PV-9 of Proven Reserves Required					90.00%
Debt Instrument, Collateral Eligible, Minimum Percent of PV-9 of PDP Reserves Required					95.00%
Debt Instrument, Covenant, Working Capital Reserve		$ 3,000,000.0
Debt Instrument, Covenant, Maximum Capital Expenditures		$ 3,000,000.0
Debt Instrument, Covenant, Minimum Asset Coverage Ratio for Capital Expenditures		1.60
Debt Instrument, Covenant, Maximum Line of Credit Outstanding for Capital Expenditures		$ 50,000,000.0
Debt Instrument, Covenant, Maximum Outstanding and Undisputed Accounts Payable		7,500,000
Debt Instrument, Covenant, Maximum Undisputed Accounts Payable Outstanding with 60 to 90 Days		2,000,000.0
Debt Instrument, Covenant, Maximum Undisputed Accounts Payable Outstanding with Over 90 Days		1,000,000.0
Debt Instrument, Covenant, Maximum Legal and Professional Fees Excluded from General and Administrative Expense Limitations		1,000,000.0
Debt Instrument, Covenant, Maximum Additional Subordinated Debt Allowed to Finance Capital Expenditures		25,000,000.0
Line of Credit Facility, Current Borrowing Capacity		102,000,000.0
Line of Credit [Member] | First Lien Credit Facility [Member] | General and Administrative Expenses for Quarter Ending June 30, 2020 [Member]
Debt Instrument, Covenant, Maximum Quarterly General and Administrative Expenses		9,000,000.0
Line of Credit [Member] | First Lien Credit Facility [Member] | General and Administrative Expenses for Quarter Ending September 30, 2020 [Member]
Debt Instrument, Covenant, Maximum Quarterly General and Administrative Expenses		8,250,000
Line of Credit [Member] | First Lien Credit Facility [Member] | General and Administrative Expenses for Quarter Ending December 31, 2020 [Member]
Debt Instrument, Covenant, Maximum Quarterly General and Administrative Expenses		6,900,000
Line of Credit [Member] | First Lien Credit Facility [Member] | General and Administrative Expenses for Year End December 31, 2021 [Member]
Debt Instrument, Covenant, Maximum Yearly General and Administrative Expenses		6,500,000
Line of Credit [Member] | First Lien Credit Facility [Member] | General and Administrative Expenses After Year End December 31, 2021 [Member]
Debt Instrument, Covenant, Maximum Yearly General and Administrative Expenses		$ 5,000,000.0
Line of Credit [Member] | First Lien Credit Facility [Member] | Minimum [Member]
Debt Instrument, Spread on Elected Variable Rate					2.50%
Debt Instrument, Basis Spread on Variable Rate					1.50%
Line of Credit [Member] | First Lien Credit Facility [Member] | Maximum [Member]
Debt Instrument, Spread on Elected Variable Rate					3.50%
Debt Instrument, Basis Spread on Variable Rate					2.50%
Debt Instrument, Covenant, Total Debt to EBITDAX Ratio		2.75
Debt Instrument, Covenant, Asset Coverage Ratio, Current		1.15
Debt Instrument, Covenant, Asset Coverage Ratio, Noncurrent		1.25
Line of Credit [Member] | Second Lien Credit Facility [Member]
Long-term Line of Credit, Total					$ 122,700,000
Debt Instrument, Covenant, Maximum Outstanding and Undisputed Accounts Payable		$ 7,500,000
Debt Instrument, Covenant, Maximum Undisputed Accounts Payable Outstanding with 60 to 90 Days		2,000,000.0
Debt Instrument, Covenant, Maximum Undisputed Accounts Payable Outstanding with Over 90 Days		1,000,000.0
Line of Credit Facility, Maximum Borrowing Capacity			$ 100,000,000.0
Proceeds from Lines of Credit, Total			$ 95,000,000.0
Line of Credit, Exit Fee					10,000,000	0
Debt Instrument, Collateral Eligible, Minimum Percent of PV-9 Proven Reserves			90.00%
Debt Instrument, Collateral Eligible, Minimum Percent of PV-9 Required PDP Reserves			95.00%
Gain (Loss) on Extinguishment of Debt, Total	$ (4,100,000)
Line of Credit [Member] | Second Lien Credit Facility [Member] | General and Administrative Expenses for Quarter Ending June 30, 2020 [Member]
Debt Instrument, Covenant, Maximum Quarterly General and Administrative Expenses		9,000,000.0
Line of Credit [Member] | Second Lien Credit Facility [Member] | General and Administrative Expenses for Quarter Ending September 30, 2020 [Member]
Debt Instrument, Covenant, Maximum Quarterly General and Administrative Expenses		8,250,000
Line of Credit [Member] | Second Lien Credit Facility [Member] | General and Administrative Expenses for Year End December 31, 2021 [Member]
Debt Instrument, Covenant, Maximum Yearly General and Administrative Expenses		6,500,000
Line of Credit [Member] | Second Lien Credit Facility [Member] | General and Administrative Expenses After Year End December 31, 2021 [Member]
Debt Instrument, Covenant, Maximum Yearly General and Administrative Expenses		$ 5,000,000.0
Line of Credit [Member] | Second Lien Credit Facility [Member] | Maximum [Member]
Debt Instrument, Covenant, Asset Coverage Ratio, Noncurrent, Year Two		1.45
Debt Instrument, Covenant, Asset Coverage Ratio, Noncurrent, after Year Two		1.55
Construction Loans [Member]
Debt Instrument, Interest Rate, Stated Percentage				4.90%
Debt Instrument, Periodic Payment, Total				$ 35,672
Long-term Debt, Total					$ 2,800,000	$ 3,100,000

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Note 4 - Long-term Debt - Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Long-term debt	$ 220,505	$ 198,869
Exit fee - Second Lien Credit Facility	10,000
Less current maturities	(202,751)	(280)
Long-term Debt, Noncurrent, Gross	17,754	198,589
Deferred financing fees and debt issuance cost - net	(15,239)	(5,871)
Total long-term debt, net of deferred financing fees and debt issuance costs	2,515	192,718
First Lien Credit Facility [Member]
Long-term debt	95,000
Second Lien Credit Facility [Member]
Long-term debt	112,700
Line of Credit [Member] | First Lien Credit Facility [Member]
Long-term debt	95,000	95,778
Line of Credit [Member] | Second Lien Credit Facility [Member]
Long-term debt	112,695	100,000
Exit fee - Second Lien Credit Facility	10,000	0
Mortgages [Member]
Long-term debt	$ 2,810	$ 3,091

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Note 4 - Long-term Debt - Maturities of Long-term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
2021	$ 217,990
2022	310
2023	2,205
2024	0
2025	0
Thereafter	0
Total	$ 220,505	$ 198,869

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Note 5 - Property and Equipment - Property and Equipment (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Oil and gas properties (1)		$ 1,206,789	$ 1,201,389
Accumulated depreciation, depletion, amortization and impairment		(1,083,843)	(872,431)
Net Property and Equipment		122,946	328,958
Oil and Gas Properties [Member]
Oil and gas properties (1)	[1]	1,167,333	1,162,094
Equipment and Other [Member]
Oil and gas properties (1)		$ 15,348	15,187
Equipment and Other [Member] | Minimum [Member]
Estimated Useful Life (Year)		3 years
Equipment and Other [Member] | Maximum [Member]
Estimated Useful Life (Year)		39 years
Drilling Rig [Member]
Oil and gas properties (1)		$ 24,108	$ 24,108
Estimated Useful Life (Year)		15 years

[1] Oil and gas properties are amortized utilizing the units of production method.

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Note 6 - Stock-based Compensation and Option Plans (Details Textual)			12 Months Ended
	Oct. 19, 2020 $ / shares shares	Apr. 01, 2018	Dec. 31, 2020 USD ($) $ / shares shares	Dec. 31, 2019 USD ($) shares	Aug. 11, 2020 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross (in shares) | shares			0	0
Share-based Payment Arrangement, Noncash Expense, Total			$ 1,312,000	$ 1,911,000
Common Stock, Capital Shares Reserved for Future Issuance (in shares) | shares			450,000
Reverse Stock Split [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	20
Warrant Issued to Lender [Member]
Class of Warrant or Right, Number of Securities Called by Warrants or Rights (in shares) | shares	1,672,290		1,672,290		33,445,792
Class of Warrant or Right, Exercise Price of Warrants or Rights (in dollars per share) | $ / shares	$ 0.20		$ 0.20		$ 0.01
Warrants and Rights Outstanding, Term (Year)	5 years
Directors Plan 2005 [Member]
Common Stock, Capital Shares Reserved for Future Issuance (in shares) | shares			70,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares Per Employee (in shares) | shares			1,250
Percentage of Exercise Price Awarded			100.00%
Share-based Payment Arrangement, Option [Member]
Deferred Compensation Arrangement with Individual, Common Stock Reserved for Future Issuance (in shares) | shares			600,000
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period (Year)			10 years
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total			$ 60,000.00
Share-based Payment Arrangement, Noncash Expense, Total			100,000	400,000
Restricted Stock [Member]
Share-based Payment Arrangement, Noncash Expense, Total			900,000	1,000,000.0
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount			1,400,000
Restricted Stock [Member] | Directors Plan 2005 [Member] | Share-based Payment Arrangement, Nonemployee [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Amount Approved for Issuance Per Participant			12,000
Performance Shares [Member]
Share-based Payment Arrangement, Noncash Expense, Total			300,000	$ 500,000
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount			$ 400,000
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period (Year)		3 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Target Payout Rate		100.00%
Performance Shares [Member] | Minimum [Member]
Share-based Compensation Awards, Vesting, Requirement, TSR, Percentage		0.00%
Performance Shares [Member] | Maximum [Member]
Share-based Compensation Awards, Vesting, Requirement, TSR, Percentage		200.00%

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Note 6 - Stock-based Compensation and Option Plans - Stock Option Activity (Details) - Share-based Payment Arrangement, Option [Member] - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Balance (in shares)	297	378
Balance, weighted average exercise price (in dollars per share)	$ 49.69	$ 49.41	$ 47.35
Granted (in shares)	0	0
Granted, weighted average exercise price (in dollars per share)		$ 0	0
Exercised (in shares)	0	(23)
Exercised, weighted average exercise price (in dollars per share)		$ 0	19.63
Forfeited/Expired (in shares)	(101)	(58)
Forfeited/Expired, weighted average exercise price (in dollars per share)		$ 48.96	$ 48.02
Balance (in shares)	196	297	378
Balance, weighted average exercise price (in dollars per share)		$ 49.69	$ 49.41
Options outstanding, weighted average remaining life (Year)	3 years 9 months 18 days
Options outstanding, intrinsic value per share (in dollars per share)	$ 0.00
Exercisable at end of year (in shares)	192
Exercisable, weighted average exercise price (in dollars per share)	$ 49.64
Exercisable, weighted average remaining life (Year)	3 years 10 months 24 days
Exercisable, intrinsic value per share (in dollars per share)	$ 0.00
Weighted average grant date fair value of stock options granted (per share) (in dollars per share)	$ 0	$ 0
Total fair value of options vested (000's)	$ 275	$ 732
Total intrinsic value of options exercised (000's)	$ 0	$ 141

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Note 6 - Stock-based Compensation and Option Plans - Stock Options Outstanding (Details)	12 Months Ended
	Dec. 31, 2020 $ / shares shares
Outstanding options, number outstanding (in shares) | shares	195,180
Outstanding options, weighted average remaining life (Year)	3 years 10 months 24 days
Outstanding options, weighted average exercise price (in dollars per share)	$ 49.69
Exercisable, number outstanding (in shares) | shares	192,581
Exercisable, weighted average remaining life (Year)	3 years 9 months 18 days
Exercisable, weighted average exercise price (in dollars per share)	$ 49.64
Range One [Member]
Exercise price range, lower limit (in dollars per share)	19.40
Exercise price range, upper limit (in dollars per share)	$ 29.99
Outstanding options, number outstanding (in shares) | shares	66,025
Outstanding options, weighted average remaining life (Year)	4 years 10 months 24 days
Outstanding options, weighted average exercise price (in dollars per share)	$ 20.02
Exercisable, number outstanding (in shares) | shares	66,025
Exercisable, weighted average remaining life (Year)	4 years 10 months 24 days
Exercisable, weighted average exercise price (in dollars per share)	$ 20.02
Range Two [Member]
Exercise price range, lower limit (in dollars per share)	30.00
Exercise price range, upper limit (in dollars per share)	$ 39.99
Outstanding options, number outstanding (in shares) | shares	5,350
Outstanding options, weighted average remaining life (Year)	6 years 4 months 24 days
Outstanding options, weighted average exercise price (in dollars per share)	$ 37.47
Exercisable, number outstanding (in shares) | shares	5,263
Exercisable, weighted average remaining life (Year)	6 years 4 months 24 days
Exercisable, weighted average exercise price (in dollars per share)	$ 34.46
Range Three [Member]
Exercise price range, lower limit (in dollars per share)	40.00
Exercise price range, upper limit (in dollars per share)	$ 49.99
Outstanding options, number outstanding (in shares) | shares	19,459
Outstanding options, weighted average remaining life (Year)	2 years 2 months 12 days
Outstanding options, weighted average exercise price (in dollars per share)	$ 47.73
Exercisable, number outstanding (in shares) | shares	19,447
Exercisable, weighted average remaining life (Year)	2 years 2 months 12 days
Exercisable, weighted average exercise price (in dollars per share)	$ 47.73
Range Four [Member]
Exercise price range, lower limit (in dollars per share)	50.00
Exercise price range, upper limit (in dollars per share)	$ 59.99
Outstanding options, number outstanding (in shares) | shares	13,900
Outstanding options, weighted average remaining life (Year)	6 years
Outstanding options, weighted average exercise price (in dollars per share)	$ 55.81
Exercisable, number outstanding (in shares) | shares	11,400
Exercisable, weighted average remaining life (Year)	5 years 8 months 12 days
Exercisable, weighted average exercise price (in dollars per share)	$ 56.33
Range Five [Member]
Exercise price range, lower limit (in dollars per share)	60.00
Exercise price range, upper limit (in dollars per share)	$ 69.99
Outstanding options, number outstanding (in shares) | shares	52,646
Outstanding options, weighted average remaining life (Year)	3 years 9 months 18 days
Outstanding options, weighted average exercise price (in dollars per share)	$ 63.14
Exercisable, number outstanding (in shares) | shares	52,646
Exercisable, weighted average remaining life (Year)	3 years 9 months 18 days
Exercisable, weighted average exercise price (in dollars per share)	$ 63.14
Range Six [Member]
Exercise price range, lower limit (in dollars per share)	70.00
Exercise price range, upper limit (in dollars per share)	$ 79.99
Outstanding options, number outstanding (in shares) | shares	19,075
Outstanding options, weighted average remaining life (Year)	1 year 9 months 18 days
Outstanding options, weighted average exercise price (in dollars per share)	$ 73.22
Exercisable, number outstanding (in shares) | shares	19,075
Exercisable, weighted average remaining life (Year)	1 year 9 months 18 days
Exercisable, weighted average exercise price (in dollars per share)	$ 73.22
Range Seven [Member]
Exercise price range, lower limit (in dollars per share)	80.00
Exercise price range, upper limit (in dollars per share)	$ 89.99
Outstanding options, number outstanding (in shares) | shares	3,650
Outstanding options, weighted average remaining life (Year)	2 years 10 months 24 days
Outstanding options, weighted average exercise price (in dollars per share)	$ 84.15
Exercisable, number outstanding (in shares) | shares	3,650
Exercisable, weighted average remaining life (Year)	2 years 10 months 24 days
Exercisable, weighted average exercise price (in dollars per share)	$ 84.14
Range Eight [Member]
Exercise price range, lower limit (in dollars per share)	90.00
Exercise price range, upper limit (in dollars per share)	$ 99.99
Outstanding options, number outstanding (in shares) | shares	12,625
Outstanding options, weighted average remaining life (Year)	1 year 9 months 18 days
Outstanding options, weighted average exercise price (in dollars per share)	$ 93.38
Exercisable, number outstanding (in shares) | shares	12,625
Exercisable, weighted average remaining life (Year)	1 year 9 months 18 days
Exercisable, weighted average exercise price (in dollars per share)	$ 93.38
Range Nine [Member]
Exercise price range, lower limit (in dollars per share)	100.00
Exercise price range, upper limit (in dollars per share)	$ 125.60
Outstanding options, number outstanding (in shares) | shares	2,450
Outstanding options, weighted average remaining life (Year)	3 years 3 months 18 days
Outstanding options, weighted average exercise price (in dollars per share)	$ 107.97
Exercisable, number outstanding (in shares) | shares	2,450
Exercisable, weighted average remaining life (Year)	3 years 3 months 18 days
Exercisable, weighted average exercise price (in dollars per share)	$ 17.97

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Note 6 - Stock-based Compensation and Option Plans - Restricted Stock Activity (Details) - Restricted Stock [Member] - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Unvested (in shares)	89	42
Unvested, weighted average grant date fair value (in dollars per share)	$ 31.67	$ 43.07
Granted (in shares)	0	66
Granted, weighted average grant date fair value (in dollars per share)	$ 0	$ 26.75
Vested/Released (in shares)	(33)	(14)
Vested/Released, weighted average grant date fair value (in dollars per share)	$ 32.11	$ 42.98
Forfeited/Expired (in shares)	(15)	(5)
Forfeited/Expired, weighted average grant date fair value (in dollars per share)	$ 31.52	$ 30.71
Unvested (in shares)	41	89
Unvested, weighted average grant date fair value (in dollars per share)	$ 31.37	$ 31.67

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Note 6 - Stock-based Compensation and Option Plans - Performance Based Restricted Stock Awards (Details) - Performance Shares [Member] - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Unvested (in shares)	57	20
Unvested, weighted average grant date fair value (in dollars per share)	$ 33.86	$ 47.40
Granted (in shares)	0	40
Granted, weighted average grant date fair value (in dollars per share)	$ 0	$ 26.80
Vested/Released (in shares)	0	0
Vested/Released, weighted average grant date fair value (in dollars per share)	$ 0	$ 0
Forfeited/Expired (in shares)	(13)	(3)
Forfeited/Expired, weighted average grant date fair value (in dollars per share)	$ 34.29	$ 30.38
Unvested (in shares)	44	57
Unvested, weighted average grant date fair value (in dollars per share)	$ 33.73	$ 33.86

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Note 6 - Stock-based Compensation and Option Plans - Warrants (Details) - Warrant Issued to Lender [Member] - $ / shares	Dec. 31, 2020	Oct. 19, 2020	Aug. 11, 2020
Exercise Price (in dollars per share)	$ 0.20	$ 0.20	$ 0.01
Number of Shares (in shares)	1,672,290	1,672,290	33,445,792

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Note 7 - Income Taxes (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Deferred Tax Assets, Valuation Allowance, Total	$ 117,270	$ 80,076
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued, Total	$ 0	$ 0
Open Tax Year	2014 2015 2016 2017 2018 2019 2020
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%
Post 2018 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards, Total	$ 140,000
Earliest Tax Year [Member]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2022
Latest Tax Year [Member]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2037
Pre 2018 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards, Total	$ 245,200

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Note 7 - Income Taxes - Deferred Tax Liabilities and Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Hedge contracts	$ 4,299	$ 0
Other	2,137	3,158
Total deferred tax liabilities	6,436	3,158
US full cost pool	35,500	9,595
Depletion carryforward	461	3,722
U.S. net operating loss carryforward	84,927	68,250
Alternative minimum tax credit	0	6
Hedge contracts	0	1,661
Interest disallowed	2,818	0
Total deferred tax assets	123,706	83,234
Valuation allowance for deferred tax assets	(117,270)	(80,076)
Net deferred tax assets	6,436	3,158
Net deferred tax	$ 0	$ 0

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Note 7 - Income Taxes - Provision (Benefit) for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Federal	$ 0	$ 0
State	0	0
Federal	$ 0	$ 0

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Note 7 - Income Taxes - Reconciliation of Income Tax (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Tax benefit at U.S. Statutory rates	$ 38,749	$ 13,651
Change in deferred tax asset valuation allowance	(37,193)	(12,767)
Alternative minimum tax expense	0	(745)
Expired capital loss carryover	0	(3,966)
Permanent differences	(276)	(403)
Return to provision estimated revision	(3,069)	341
State income taxes, net of federal effect	1,789	3,892
Other	$ 0	$ (3)

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Note 9 - Earnings Per Share (Details Textual) shares in Millions	12 Months Ended
	Dec. 31, 2020 shares
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in shares)	4

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Note 9 - Earnings Per Share - Computation of Basic and Diluted Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Net loss	$ (69,094)	$ (73,615)	$ (83,256)	$ 41,443	$ (68,268)	$ 17,041	$ 11,678	$ (25,455)	$ (184,522)	$ (65,004)
Basic (in shares)									8,382	8,312
Effect of dilutive securities: Stock options, restricted shares and performance based shares (in shares)									0	3
Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options, restricted shares and performance based shares (in shares)									8,382	8,315
Net (loss) income per common share - basic (in dollars per share)	$ (8.21)	$ (8.80)	$ (10.00)	$ 4.80	$ (8.20)	$ 2.00	$ 1.40	$ (3.00)	$ (22.01)	$ (7.82)
Net (loss) income per common share - diluted (in dollars per share)	$ (8.21)	$ (8.80)	$ (10.00)	$ 4.80	$ (8.20)	$ 2.00	$ 1.40	$ (3.00)	$ (22.01)	$ (7.82)

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Note 10 - Benefit Plans (Details Textual)	12 Months Ended
	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Deferred Compensation Arrangement with Individual, Contributions by Employer	$ 142,820	$ 284,905
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay		1.00%
Defined Contribution Plan, Employer Matching Contribution, Amount of Cents Per Dollar Increase for Each Additional Percentage Point	50
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	5.00%
Defined Contribution Plan Employee Contribution Limit Below 50 Years of Age	$ 19,500	$ 19,000
Defined Contribution Plan Employee Contribution Limit 50 Years of Age or Older	$ 26,000	$ 25,000

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Note 11 - Hedging Program and Derivatives (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Derivative Asset, Total	$ 19,920	$ 4,253
Commodity Contract [Member]
Derivative Asset, Total	19,400
Commodity Contract [Member] | (Gain) Loss on Derivative Contracts [Member]
Gain (Loss) on Sale of Derivatives	42,900	(26,800)
Commodity Closed Contracts [Member] | (Gain) Loss on Derivative Contracts [Member]
Gain (Loss) on Sale of Derivatives	17,500	(6,000)
Commodity Open Contracts [Member] | (Gain) Loss on Derivative Contracts [Member]
Gain (Loss) on Sale of Derivatives	$ 25,400	$ (20,800)

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Note 11 - Hedging Program and Derivatives - Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2020 $ / bbl
Fixed Swap 2021 [Member]
Daily volume	2,889
Swap price (in USD per Barrel of Oil)	57.62
Fixed Swap 2022 [Member]
Daily volume	2,412
Swap price (in USD per Barrel of Oil)	50.60
Fixed Swap 2023 [Member]
Daily volume	1,498
Swap price (in USD per Barrel of Oil)	50.60
Fixed Swap 2024 [Member]
Daily volume	1,585
Swap price (in USD per Barrel of Oil)	50.60

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Note 11 - Hedging Program and Derivatives - Impact of Derivative Contracts on Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Derivative asset, current	$ 9,639	$ 83
Derivative liability, current	480	10,688
Derivative asset, long-term	10,281	4,170
Derivative liability, long-term	0	999
Derivative Asset, Total	19,920	4,253
Derivative liability	480	11,687
Commodity Contract [Member]
Derivative Asset, Total	19,400
Commodity Contract [Member] | Derivative Assets Current [Member]
Derivative asset, current	9,639	83
Commodity Contract [Member] | Derivative Liabilities Current [Member]
Derivative liability, current	480	10,688
Commodity Contract [Member] | Derivative Assets Noncurrent [Member]
Derivative asset, long-term	10,281	4,170
Commodity Contract [Member] | Derivative Liabilities Noncurrent [Member]
Derivative liability, long-term	$ 0	$ 999

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Note 12 - Financial Instruments - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Derivative assets	$ 19,920	$ 4,253
Derivative liabilities	480	11,687
Fair Value, Recurring [Member]
Derivative assets	19,920	4,253
Derivative liabilities	480	11,687
Fair Value, Recurring [Member] | Fixed Price Derivative Contracts [Member]
Derivative assets	19,920	4,253
Derivative liabilities	480	5,583
Fair Value, Recurring [Member] | Basis Swap [Member]
Derivative assets		0
Derivative liabilities		6,104
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Derivative assets	0	0
Derivative liabilities	0	0
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Price Derivative Contracts [Member]
Derivative assets	0	0
Derivative liabilities	0	0
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Basis Swap [Member]
Derivative assets		0
Derivative liabilities		0
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Derivative assets	19,920	4,253
Derivative liabilities	480	5,583
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Price Derivative Contracts [Member]
Derivative assets	19,920	4,253
Derivative liabilities	480	5,583
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Basis Swap [Member]
Derivative assets		0
Derivative liabilities		0
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Derivative assets	0	0
Derivative liabilities	0	6,104
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed Price Derivative Contracts [Member]
Derivative assets	0	0
Derivative liabilities	$ 0	0
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Basis Swap [Member]
Derivative assets		0
Derivative liabilities		$ 6,104

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Note 12 - Financial Instruments - Recurring Fair Value Measurements Using Significant Unobservable Inputs (Details) - Fair Value, Inputs, Level 3 [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2020 USD ($)
Fair value	$ (6,104)
Changes in market value	4,577
Settlements during the period	1,527
Fair value	$ 0

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Note 13 - Lease Accounting Standard (Details Textual)	Dec. 31, 2020
Lease for Residence in North Dakota [Member]
Lessee, Operating Lease, Term of Contract (Year)	5 years

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Note 13 - Lease Accounting Standard - Total Lease Expense (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Operating lease cost		$ 114	$ 478
Short-term lease expense	[1]	2,183	1,992
Total lease expense		$ 2,297	$ 2,470
Weighted Average Remaining Lease Term (in years) (Year)		10 years 8 months 4 days	8 years 7 months 28 days
Weighted Average Discount Rate		6.00%	6.00%
Cash paid for amounts included in the measurement of lease liabilities		$ 114	$ 478
Right of Use assets added in exchange for lease obligations (since adoption)		125	770
Drilling Rig [Member]
Short-term lease expense	[2]	$ 973	$ 4,900

[1] Short-term lease expense represents expense related to leases with a contract term of 12 months or less.

[2] These short-term lease costs are related to leases with a contract term of 12 months or less which are related to drilling rigs and are capitalized as part of natural gas and oil properties on our balance sheet.

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Note 13 - Lease Accounting Standard - Balance Sheet Information (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Operating lease Right of Use asset	$ 228	$ 327
Operating lease liability - current	53	98
Operating lease liabilities - long-term	$ 150	$ 203

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Note 13 - Lease Accounting Standard - Lease Liabilities Maturity (Details) $ in Thousands	Dec. 31, 2020 USD ($)
2021	$ 63
2022	48
2023	41
2024	28
2025	4
Thereafter	98
Total lease payments	282
Less imputed interest	(79)
Total lease liability	$ 203

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Note 14 - Subsequent Events (Details Textual) - USD ($) $ in Thousands		3 Months Ended	12 Months Ended
	May 04, 2020	Mar. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Apr. 30, 2021	Apr. 16, 2021	Apr. 12, 2021
Gain (Loss) on Extinguishment of Debt, Total			$ (4,108)	$ (0)
Subsequent Event [Member] | Morgan Stanley [Member]
Termination Value of Hedge Contracts							$ 9,100
Paycheck Protection Program, CARES Act [Member]
Proceeds from Issuance of Long-term Debt, Total	$ 1,400		$ 1,384	$ 0
Paycheck Protection Program, CARES Act [Member] | Subsequent Event [Member]
Gain (Loss) on Extinguishment of Debt, Total		$ 1,400
Second Lien Credit Facility [Member] | Subsequent Event [Member]
Debt Instrument, Interest Rate, Additional Default Interest						3.00%
First Lien Credit Facility [Member] | Subsequent Event [Member] | Obligations from Terminated Hedging Arrangements [Member]
Termination Value of Hedge Contracts					$ 9,900
Debt Instrument, Interest Rate, Stated Percentage					6.70%
First Lien Credit Facility [Member] | Subsequent Event [Member] | Morgan Stanley [Member]
Percentage of Outstanding Obligations							3.70%
First Lien Credit Facility [Member] | Subsequent Event [Member] | Morgan Stanley [Member] | Obligations from Terminated Hedging Arrangements [Member]
Termination Value of Hedge Contracts					$ 9,100

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Note 15 - Quarterly Results of Operations (Unaudited) - Results of Operations for Fiscal Quarters (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Net revenue	$ 12,729	$ 12,595	$ 1,993	$ 15,726	$ 28,276	$ 31,536	$ 34,820	$ 34,514	$ 43,043	$ 129,146
Operating income (loss)	(51,502)	(56,661)	(61,474)	(29,781)	(49,412)	8,053	8,935	6,708	(199,418)	(25,716)
Net (loss)	$ (69,094)	$ (73,615)	$ (83,256)	$ 41,443	$ (68,268)	$ 17,041	$ 11,678	$ (25,455)	$ (184,522)	$ (65,004)
Net income (loss) per common share - basic (in dollars per share)	$ (8.21)	$ (8.80)	$ (10.00)	$ 4.80	$ (8.20)	$ 2.00	$ 1.40	$ (3.00)	$ (22.01)	$ (7.82)
Net income (loss) per common share - diluted (in dollars per share)	$ (8.21)	$ (8.80)	$ (10.00)	$ 4.80	$ (8.20)	$ 2.00	$ 1.40	$ (3.00)	$ (22.01)	$ (7.82)

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) (Details Textual) bbl in Thousands, Boe in Thousands	12 Months Ended
	Dec. 31, 2020 Boe bbl	Dec. 31, 2019 Boe bbl
Proved Developed and Undeveloped Reserves Production, Energy (Barrel of Oil Equivalent)	1,801	3,616
Other Miscellaneous Asset [Member]
Proved Developed and Undeveloped Reserves Sales of Minerals in Place, Energy (Barrel of Oil Equivalent)		18
Change in Projections [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates (Barrel of Oil) | bbl	(56)	(8,790)
Conversion of Proved Undeveloped Locations to Probable Undeveloped Reserves [Member] | Wolfcamp A1 and Bone Spring Locations in Ward County, Texas [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates (Barrel of Oil) | bbl	(17,616)
Conversion of Proved Undeveloped Locations to Probable Undeveloped Reserves [Member] | McKenzie County, ND [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates (Barrel of Oil) | bbl	(5,153)
Conversion of Proved Undeveloped Locations to Probable Undeveloped Reserves [Member] | Delaware Locations in Ward County, TX [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates (Barrel of Oil) | bbl	(2,300)
Conversion of Proved Undeveloped Locations to Probable Undeveloped Reserves [Member] | Ward County, Texas [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates (Barrel of Oil) | bbl		(13,402)
Addition of Proved Undeveloped Non-operated Locations [Member]
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Location		2
Proved Developed and Undeveloped Reserves Revisions of Previous Estimates, Energy (Barrel of Oil Equivalent)		3,776
Three Forks Location in McKenzie County, North Dakota [Member]
Proved Developed and Undeveloped Reserves Extensions Discoveries and Additions, Energy (Barrel of Oil Equivalent)		14,333
Gulf Coast Area Holdings [Member]
Proved Developed and Undeveloped Reserves Sales of Minerals in Place, Energy (Barrel of Oil Equivalent)		1,839
Permian Locations in Marion, Pecos, and Reeves Counties, Texas [Member]
Proved Developed and Undeveloped Reserves Sales of Minerals in Place, Energy (Barrel of Oil Equivalent)		42
Number of Non-operated Holdings Sold		14
Bakken Area Holdings [Member]
Proved Developed and Undeveloped Reserves Sales of Minerals in Place, Energy (Barrel of Oil Equivalent)		1,268

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Proved oil and gas properties	$ 1,167,333	$ 1,162,094
Unproved properties	0	0
Total	1,167,333	1,162,094
Accumulated depreciation, depletion, amortization and impairment	(1,060,649)	(851,107)
Net capitalized costs	$ 106,684	$ 310,987

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Cost Incurred (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Development costs	$ 5,238	$ 92,884
Exploration costs	0	0
Property acquisition costs	0	0
Costs Incurred, Acquisition of Oil and Gas Properties, Total	$ 5,238	$ 92,884

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Results of Operations (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020 USD ($) $ / bbl	Dec. 31, 2019 USD ($) $ / bbl
Revenues	$ 42,984	$ 128,992
Production costs	(21,090)	(38,229)
Depreciation, depletion and amortization	(22,679)	(51,041)
Accretion of future site restoration	(414)	(436)
Proved property impairment	(186,980)	(51,293)
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$ (188,179)	$ (12,007)
Depletion rate per barrel of oil equivalent (in USD per Barrel of Oil) | $ / bbl	12.59	14.12

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Proved Developed and Undeveloped Reserves (Details) - bbl bbl in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Oil [Member]
Balance (Barrel of Oil)	36,279	42,237
Revisions of previous estimates (Barrel of Oil)	(16,922)	(15,616)
Extensions and discoveries (Barrel of Oil)	0	13,477
Purchases of minerals in place (Barrel of Oil)		0
Sales of minerals in place (Barrel of Oil)		(1,431)
Production (Barrel of Oil)	(1,132)	(2,388)
Removal of PUDs (Barrel of Oil)	(8,687)
Balance (Barrel of Oil)	9,538	36,279
Proved developed reserves (Barrel of Oil)	9,538	10,964
Proved undeveloped reserves (Barrel of Oil)	0	25,315
Natural Gas Liquids [Member]
Balance (Barrel of Oil)	8,972	10,034
Revisions of previous estimates (Barrel of Oil)	(3,549)	(2,713)
Extensions and discoveries (Barrel of Oil)	0	2,285
Purchases of minerals in place (Barrel of Oil)		0
Sales of minerals in place (Barrel of Oil)		(86)
Production (Barrel of Oil)	(313)	(548)
Removal of PUDs (Barrel of Oil)	(1,922)
Balance (Barrel of Oil)	3,188	8,972
Proved developed reserves (Barrel of Oil)	3,187	2,699
Proved undeveloped reserves (Barrel of Oil)	0	6,273
Natural Gas [Member]
Balance (Barrel of Oil)	66,665	89,744
Revisions of previous estimates (Barrel of Oil)	(27,921)	(23,178)
Extensions and discoveries (Barrel of Oil)	0	14,073
Purchases of minerals in place (Barrel of Oil)		0
Sales of minerals in place (Barrel of Oil)		(9,898)
Production (Barrel of Oil)	(2,135)	(4,076)
Removal of PUDs (Barrel of Oil)	(12,291)
Balance (Barrel of Oil)	24,318	66,665
Proved developed reserves (Barrel of Oil)	24,318	21,439
Proved undeveloped reserves (Barrel of Oil)	0	45,226
Oil Equivalents [Member]
Balance (Barrel of Oil)	56,362	67,228
Revisions of previous estimates (Barrel of Oil)	(25,125)	(22,192)
Extensions and discoveries (Barrel of Oil)	0	18,109
Purchases of minerals in place (Barrel of Oil)		0
Sales of minerals in place (Barrel of Oil)		(3,167)
Production (Barrel of Oil)	(1,801)	(3,616)
Removal of PUDs (Barrel of Oil)	(12,658)
Balance (Barrel of Oil)	16,778	56,362
Proved developed reserves (Barrel of Oil)	16,778	17,237
Proved undeveloped reserves (Barrel of Oil)	0	39,125

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Future Net Cash Inflows (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Future cash inflows	$ 345,869	$ 1,890,579
Future production costs	(166,781)	(598,714)
Future development costs	(6,291)	(544,111)
Future income tax expense	0	0
Future net cash flows	172,797	747,754
Discount	(66,113)	(440,142)
Standardized Measure of discounted future net cash relating to proved reserves	$ 106,684	$ 307,612	$ 651,884

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Changes in the Standardized Measure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Standardized Measure, beginning of year	$ 307,612	$ 651,884
Sales and transfers of oil and gas produced, net of production costs	(21,894)	(90,763)
Net change in prices and development and production costs from prior year	(96,688)	(218,092)
Extensions, discoveries, and improved recovery, less related costs	0	98,780
Sales of minerals in place	0	(17,276)
Removal of PUDs	(80,416)	0
Revisions of previous estimates	(159,613)	(227,477)
Change in timing and other	126,922	(13,744)
Change in future income tax expense	0	59,112
Accretion of discount	30,761	65,188
Standardized Measure, end of year	$ 106,684	$ 307,612

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Oil and Gas Prices (Details)		12 Months Ended
		Dec. 31, 2020 $ / bbl $ / BTU	Dec. 31, 2019 $ / bbl $ / BTU
Oil (per Bbl) (1) (in USD per Barrel of Oil)	[1]	39.54	55.73
Gas (per Mmbtu) (2) (in USD per British Thermal Unit) | $ / BTU	[2]	2.03	2.54
Oil (per Bbl) (3) (in USD per Barrel of Oil)	[3]	37.05	52.14
Gas (per Mmbtu) (4) (in USD per British Thermal Unit) | $ / BTU	[4]	0.27	0.63
NGL's (per Bbl) (5) (in USD per Barrel of Oil)	[5]	1.37	3.48

[1] The quoted oil price for the year ended December 31 of each year, 2019 and 2020 is the 12-month unweighted average first-day-of-the-month West Texas Intermediate spot price for each month of 2019 and 2020.

[2] The quoted gas price for the year ended December 31, 2019 and 2020 is the 12-month unweighted average first-day-of-the-month Henry Hub spot price for each month of 2019 and 2020.

[3] The oil price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.

[4] The gas price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.

[5] The NGL price is the realized price as of December 31 of each year after the appropriate differentials have been applied.