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, 2022

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

For the transition period from ______ to ______

Commission File Number 001-16071

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 No.)

19100 Ridgewood Parkway, Suite 1200

San Antonio, Texas 78259  

(Address of principal executive offices)(Zip Code)

(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	OTC Markets

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 Act. Yes ☐ No ☒

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

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

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

Large accelerated filer ☐	Accelerated filer  ☐
Non-accelerated filer   ☒	Smaller reporting company ☒
	Emerging Growth Company ☐

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

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

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

As of June 30, 2022, 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 $15,752,023 based on the closing sale price as reported on the OTCMKTS.

As of March 23, 2023, there were 100,701,430 shares of common stock outstanding.

ABRAXAS PETROLEUM CORPORATION

FORM 10-K

TABLE OF CONTENTS

		Page
Part  I
Item 1.	Business	5
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	16
Item 2.	Properties	16
Item 3.	Legal Proceedings	20
Item 4.	Mine Safety Disclosures	20
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	28
Item 8.	Financial Statements and Supplementary Data	28
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	28
Item 9A.	Controls and Procedures	28
Item 9B.	Other Information	29
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	29
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	30
Item 11.	Executive Compensation	52
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	52
Item 13.	Certain Relationships and Related Transactions, and Director Independence	52
Item 14.	Principal Accountant Fees and Services	52
Part IV
Item 15.	Exhibits and Financial Statement Schedules	35
Item 16.	Form 10-K Summary	37

Information contained in this Annual Report on Form 10-K (“Form 10-K”) 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. Unless otherwise noted, all disclosures are for Continuing Operations. 

Cautionary Statement Regarding Forward-Looking Statements

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;

• our success in development, exploitation and exploration activities;

• declines in our production of oil and gas;

• 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;

• 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;

• 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.

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 equivalent 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.

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“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.

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.

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“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

Item 1. Business

General

We are an independent energy company primarily engaged in the development and production of oil and gas.  At December 31, 2022, our estimated net proved reserves were 7.9 MMBoe, 42% were oil and 92% of which (on a Boe basis) were operated by us.  Our daily net production for the year ended December 31, 2022 was 2,231 Boepd, of which 51%, on a BOE basis, was oil. Abraxas Petroleum Corporation was incorporated in Nevada in 1990. Our address is 19100 Ridgewood Parkway, Suite 1200, San Antonio, Texas 78259 and our phone number is (210) 490-4788.

Our oil and gas assets were located in the Permian/Delaware Basin as of December 31, 2022. 

 Recent Activity

Our business strategy is to extract resources from our core operated basin.  

                         Our primary source of capital is cash flows from operations. As of December 31, 2022, we had no outstanding debt.

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 2022. 

Further Recent Activity 

Pursuant to the Exchange Agreement, dated as of January 3, 2022, between the Company and AG Energy Funding, LLC (“AGEF”) and certain other agreements entered into by the Company on January 3, 2022, we effectuated a restructuring of the Company’s  then-existing indebtedness through a multi-part interdependent deleveraging transaction consisting of: (i) an Asset Purchase and Sale Agreement pursuant to which the Company sold to Lime Rock Resources V-A, L.P. certain oil, gas, and mineral properties in the Williston Basin region of North Dakota and other related assets belonging to the Company and its subsidiaries for $87.2 million in cash ($73.3 million after customary closing adjustments), (the “Sale”), (ii) the pay down of the indebtedness and other obligations of the Company and its subsidiaries under the First Lien Credit Facility; and (iii), a debt for equity exchange of the indebtedness and other obligations of the Company and its subsidiaries under the $100.0 million Second Lien Credit Facility, and all related loan and security documents (the “Exchange” and, together with the transactions referred to in clauses (i) and (ii), the “Restructuring”). 

AGEF was issued 685,505 shares of Series A Preferred Stock of the Company (the "Preferred Shares") in the Exchange.  The Series A Preferred Stock has the terms set forth in the Company’s filed Preferred Stock Certificate of Designation (the “Certificate").  The shares of Series A Preferred Stock vote together as a single class with the Company’s common stock, and each share of Series A Preferred Stock entitles the holder thereof to 69 votes. Accordingly, AGEF’s ownership of the Series A Preferred Stock entitled it to approximately 85% of the voting power of the Company’s then outstanding capital stock.

On September 13, 2022, AGEF and Biglari Holdings Inc, ("Biglari Holdings") entered into the a preferred stock purchase agreement (the "Preferred Purchase Agreement"), and an assignment and assumption agreement pursuant to which AGEF agreed to sell and assign to Biglari Holdings (the "Sales and Assignment Agreement"), and Biglari Holdings agreed to purchase, acquire, and assume from AGEF, the Preferred Shares and all of AGEF’s rights, title, and interests in, and duties and obligations under, the Exchange Agreement. Biglari Holdings’ ownership of the Preferred Shares resulted in its beneficial ownership, both directly and indirectly, of the approximately 85% of the Company’s voting securities that AGEF owned prior to effecting the Sale and Assignment.

In connection with the transactions contemplated by the Preferred Purchase Agreement, the four directors of the Company appointed by AGEF resigned from the Board. Also, in accordance with the terms of the Preferred Purchase Agreement, on September 13, 2022, the Board voted to appoint Messrs. Sardar Biglari, Philip Cooley, and Bruce Lewis as members of the Board to fill three of the vacancies created by the resignations of the AGEF appointed directors. All three newly appointed members of the Board are affiliated with Biglari Holdings.

Subsequent to the Sale and Assignment, Biglari Holdings proposed an exchange of the Preferred Shares for shares of the Company’s common stock pursuant to which the Company would issue Biglari Holdings 90,631,287 shares of the Company’s common stock (the “Stock Consideration”) in exchange for the Preferred Shares (such transaction, the “Second Exchange”).

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To issue the Stock Consideration to Biglari Holdings as contemplated by the Second Exchange, an amendment to the Company’s Articles of Incorporation was needed to increase the number of shares of common stock authorized for issuance from 20,000,000 shares to 150,000,000 shares (the “Amendment”).

On September 23, 2022, the Board approved the Company’s entry into an exchange agreement with Biglari Holdings defining the terms of the Second Exchange (the “Second Exchange Agreement”). The Company and Biglari Holdings entered into the Second Exchange Agreement on September 27, 2022, with the consummation of the Second Exchange subject to the approval of the Company’s stockholders of the Amendment and the acceptance of the Amendment of the Nevada Secretary of State.

On October 24, 2022, the Company’s stockholders approved the Amendment, and the Company caused the Amendment to be filed with the Nevada Secretary of State that same day. The Nevada Secretary of State accepted the Amendment on October 25, 2022, and on October 26, 2022, the Second Exchange Agreement was consummated by the following transactions: (i) the Company caused 90,631,287 shares of common stock to be registered in the name of Biglari Holdings with the Company’s transfer agent in book-entry form, and (ii) Biglari Holdings assigned and transferred the Preferred Shares to the Company, constituting all of the Preferred Shares of the Company then outstanding, by delivering a Stock Power and Assignment to the Company. The Company cancelled the Series A Preferred Stock and the Preferred Stock Certificate of Designation, such that only common stock of the Company remains outstanding. 

As a result of the Sale and Assignment and Second Exchange, the Company is a consolidated subsidiary of Biglari Holdings, which has the power to exert significant control over the Company by controlling both 90% of the voting power of the Company’s outstanding capital stock and a majority of the Company’s Board. 

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 OPEC, domestic regulation, legislation and policies, and the outbreak of a pandemic or contagious diseases, such as the recent COVID-19 outbreak.  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. 

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, 2022, three purchasers of production accounted for approximately 90% of our oil and gas sales. During the year ended December 31, 2021, four purchasers of production accounted for approximately 83% of our oil and gas sales. 

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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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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.

Regulation of Transportation of Oil in the United States

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.

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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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.

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 titles 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 March 18, 2023, we had 18 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. 

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 website that contains annual, quarterly and current reports, proxy statements and other information that issuers (including Abraxas) file electronically with the SEC. The SEC’s website 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 website at www.abraxaspetroleum.com in the Investor Relations section as soon as practicable after such reports are filed.  Information on our website 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 submit with the SEC.

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Item 1A. Risk Factors

Risks Related to Our Business

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 sales of these commodities.  In addition to the impact on the results of operations, future declines in oil and gas prices could cause us to write down the value of our estimated proved reserves. Oil and natural gas prices remain volatile, and as a result, we could 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 improved significantly in 2022, however future deterioration in commodity prices could materially and adversely impact future results.

Market prices and 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 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.

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, 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 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.

10

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.  There is a risk that we will be required to write-down the carrying value of our oil and gas properties as oil and gas prices decrease. 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 December 31, 2022 and 2021, the net capitalized costs of our oil and gas properties did not exceed the present value of estimated future cash flows from our proved reserves.

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.  

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 8.0% of our estimated net proved reserves on a Boe basis at December 31, 2022.  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.

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.

11

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 landowners 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 of 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.

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 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.

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.

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 a 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.

12

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. The severity and duration of the COVID-19 pandemic 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 or similar outbreaks may heighten 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. 
 

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, 2022 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, 2022.  The average realized sales prices used for purposes of such estimates were $94.14 per Bbl of oil and $6.36 per Mcf of gas. 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, 2022 on the twelve-month first-day-of-the-month average oil and gas prices for the year ended December 31, 2022 and costs in effect on December 31, 2022, 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.

13

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.

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. Reports from numerous global and domestic governmental agencies tasked with researching, evaluating, and mitigating the impact of climate change, such as the Sixth Assessment Report of the United Nations Intergovernmental Panel on Climate Change, released in September 2022, and the Fourth National Climate Assessment of the U.S. Global Change Research Program, released in full in November 2018,  have pointed to GHG emissions as the main driver of atmospheric warming 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 levels and local levels, several states and localities, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of GHGs, such as establishing regional GHG “cap-and-trade” programs. Federally, President Joe Biden has made the reduction of GHG emissions one of the Nation’s central ambitions, with the United States rejoining the Paris Agreement in February 2021, under which it pledged to reduce GHG emissions by roughly 25% from 2005 levels by 2025, and then bolstering that commitment in September 2021 when the United States co-launched the Global Methane Pledge with the European Union, pursuant to which it pledged to reduce global methane emissions by at least 30% from 2020 levels by 2030. Various climate change legislative measures have been considered by the U.S. Congress, and the appropriate scope and urgency of regulatory measures to address the impact of GHG emissions will continue to be a broad-spectrum policy issue. Although we are unable to predict the timing, scope and effect of any currently proposed or future legislation, investigations, laws, regulations or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such measures (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 or could reduce the demand for the oil and gas that we produce which could result, in our financial condition and results of operations being adversely affected.

In addition, abnormal weather patterns associated with climate change, including severe rainfall events, volatile storms, flooding, droughts, and wildfires could threaten our production operations and adversely affect our facilities, the scheduling of deliveries, or the cost of supplies needed to run our business.

14

Risks Related to Our Capital Stock

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

We currently anticipate that we will retain all future earnings, if any, to finance the development of our business. We do not intend to pay cash dividends in the foreseeable future.  

Shares eligible for future sale may depress our stock price.

At December 31, 2022, we had 100,701,430 shares of common stock outstanding of which 91,605,101 shares were held by affiliates.

All of the shares of common stock held by affiliates are restricted or are controlled 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 highest tier of the over-the-counter market (the “OTCMKTS”). 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; and

• general trends in the oil and gas industry;

15

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, 2022.

	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		13,931		9,601		10,472		6,357		9,551		2,388		18,346
Rocky Mountain (3)		800		431		2,877		1,652		920		79		2,162
Total		14,731		10,032		13,349		8,009		10,471		2,467		20,508

(1) Fee mineral acreage represents 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.
(3)	All Rocky Mountain properties were sold in January 2022. The remaining Rocky Mountain acreage consist of a retained non-operated position in various depths in the leases sold.

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

	2023		2024		2025		2026		2027
Permian/Delaware Basin		5		-		-		-		-
Total		5		-		-		-		-

Productive Wells

Gross wells represent the number of wells in which we own a working interest and net wells represent the total of our fractional working interest in gross wells. The following table sets forth our gross and net productive wells by region and by crude oil or natural gas completion as of December 31, 2022. One or more completions in the same well bore are counted as one well.

	Productive Wells
	Oil				Gas
	Gross		Net		Gross		Net
Permian/Delaware Basin		36		26		30		21
		36		26		30		21

16

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 for the year ended December 31, 2022 have been estimated by an independent petroleum engineering firm, Netherland Sewell & Associates Inc., of Dallas, Texas, assisted by the engineering and operations departments of the Company. As of December 31, 2021, DeGolyer & MacNaughton, of Dallas, Texas, assisted by the engineering and operations departments of the Company, estimated reserves for our Permian/Delaware Basin comprising approximately 60% of the PV-10 of our proved oil and gas reserves. Proved reserves for the remaining 40% of our properties, primarily our Rocky Mountain properties that were sold in January 2022, 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, or were subsequently sold. 

The technical personnel responsible for preparing the reserve estimates at Netherland Sewell & Associates Inc. 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. Netherland Sewell & Associates Inc. 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 Netherland Sewell & Associates Inc. were developed utilizing their own geological and engineering data, supplemented by data provided by Abraxas.  The report of Netherland Sewell & Associates Inc. dated February10, 2023, which contains further discussions of the reserve estimates and evaluations prepared by Netherland Sewell & Associates Inc. as well as the qualifications of Netherland Sewell & Associates Inc. technical personnel responsible for overseeing such estimates and evaluations is attached as Exhibit 99.1 to this report.

Estimates of reserves at December 31, 2022 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 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 the SEC and the 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, 2022, 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, 2022. All of our reserves are located in the United States. 

Summary of Oil, NGL and Gas Reserves
As of December 31, 2022
Reserve Category	Oil (MBbls)		NGL (MBbls)		Gas (MMcf)		Oil equivalents (MBoe)
Proved
Developed		3,300		1,508		18,847		7,949
Undeveloped		-		-		-		-
Total Proved		3,300		1,508		18,847		7,949

As of December 31, 2022 we did not recognize any proved undeveloped reserves because we seek to partner with third parties to fund drilling operations. 

Our estimates of proved developed reserves at December 31, 2022 and 2021, and estimates of future net cash flows and discounted future net cash flows from proved reserves are presented in the Supplemental Information.

We have not filed information with a federal authority or agency with respect to our estimated total proved reserves at December 31, 2022. 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.

17

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, 2022 report. 

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, 2021 and 2022 the net capitalized costs of oil and gas properties did not exceed the present value of our estimated proved reserves.  

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

The Company did not recognize PUDs in 2021 or 2022 due to the lack of resources to conduct exploration activities. The Company may partner with third parties on undeveloped properties.

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, 2021 and 2022:

	December 31,
	2021		2022
	(In thousands)
Standardized measure of discounted future net cash flows	$	153,275	$	133,878
Present value of future income taxes discounted at 10%		-		-
PV-10	$	153,275	$	133,878

18

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, 2021 and 2022, by our major operating regions:

	Years Ended December 31,
	2021		2022
Oil Production (Bbl)
Permian		498,225		418,625
Rocky Mountain (4)		458,829		-
Total		957,054		418,625
Gas Production (Mcf)
Permian		1,593,725		1,568,873
Rocky Mountain (4)		1,838,495		-
Total		3,432,220		1,568,873
NGL Production (Bbl)
Permian		109,970		134,243
Rocky Mountain (4)		348,874		-
Total		458,844		134,243
Total Production (Boe) (1)		1,150,118		814,347
Average oil sales price per Bbl (2)
Permian	$	65.57	$	94.64
Rocky Mountain (4)	$	62.25	$	-
Composite	$	63.98	$	94.64
Average gas sales price per Mcf
Permian	$	2.81	$	4.23
Rocky Mountain (4)	$	2.27	$	-
Composite	$	2.52	$	4.23
Average NGL sales price per Bbl
Permian	$	19.83	$	25.74
Rocky Mountain (4)	$	17.59	$	-
Composite	$	18.09	$	25.74
Average sales price per Boe (2)	$	38.95	$	61.05
Average cost of production per Boe produced (3)
Permian	$	10.85	$	12.27
Rocky Mountain (4)	$	7.33	$	-
Composite	$	8.85	$	12.27

(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.
(4)	All Rocky Mountain properties were sold January 3, 2022.

19

Within the above major operating regions, the Permian/Delaware region represented more than 15% of our proved reserves as of December 31, 2022. 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 for the two years ended December 31, 2021 and 2022. 

	Years Ended December 31,
	2021		2022
Permian Region
Oil production (Bbls)
Wolfcamp		451,840		416,225
Gas Production (Mcf)
Wolfcamp		438,701		757,613
NGL production (Bbls)
Wolfcamp		62,417		96,566
Average oil sales price per Bbl (1)
Wolfcamp	$	65.70	$	94.67
Average gas sales price of per Mcf
Wolfcamp	$	2.35	$	4.30
Average NGL sales price per Bbl
Wolfcamp	$	18.95	$	24.70
Average cost of production per Boe produced (2)	$	13.26	$	13.33

(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 Company did not drill or complete any wells during the two years ended December 31, 2022.

Office Facilities

Our executive and administrative offices are located at 19100 Ridgewood Parkway, Suite 1200, San Antonio, Texas 78259.

Other Properties

We own 1.5 acres of land and an office building in Ward County, Texas.   We own 9 vehicles which are used in the field by employees. The Company owned a 2000 HP drilling rig which was sold in February 2023.  The drilling rig was impaired during 2022 resulting in a loss of approximately $8.2 million. In addition, we own an office building in San Antonio, Texas which is under contract and is classified as assets held for sale.

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, 2022, 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.

20

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 OTCMKTS under the symbol “AXAS.” Any over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions. 

On March 23, 2023, we had 100,701,430 shares of common stock outstanding held by approximately 110 stockholders of record.

Dividends

We have not paid any cash dividends on our common stock. 

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. 

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. 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 2023 will impact the amount of cash generated from operating activities, which will in turn impact our financial position. As of March 20, 2023, the NYMEX oil and gas price was $67.64 per Bbl of oil and $2.22 per Mcf of gas.

During 2022, the NYMEX future price for oil averaged $94.32 per barrel as compared to $68.11 per barrel in 2021 and the NYMEX future spot price for gas averaged $6.54 per Mcf compared to $3.73 per Mcf in 2021. Prices closed on December 31, 2022 at $80.26 per Bbl of oil and $4.48 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.

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, 2022, our average annual estimated decline rate for our net proved developed producing reserves is 15%, 12% , 10% , 9%  and 7% for 2023, 2024, 2025, 2026 and 2027, respectively, 7% annually in the following five years, and approximately 7% annually 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. 

Borrowings and Interest.  At December 31, 2022, we had no outstanding debt. 

 Exploration and Development Activity. At December 31, 2022, 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 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. 

21

Results of Operations

	Year Ended December 31,
	(in thousands)
	2021		2022
Operating revenue (1):
Oil sales	$	61,228	$	39,617
Gas sales		8,656		6,642
NGL sales		8,952		3,456
Other income		22		22
Total revenues	$	78,858	$	49,737
Operating income	$	30,484	$	15,677
Oil sales (MBbls)		957		419
Gas sales (MMcf)		3,432		1,569
NGL sales (MBbls)		495		134
Oil equivalents (MBoe)		2,023		814
Average oil sales price (per Bbl)(1)	$	63.98	$	94.64
Average gas sales price (per Mcf)	$	2.52	$	4.23
Average NGL price (per Bbl)	$	18.09	$	25.74
Average oil equivalent sales price (per Boe)	$	38.95	$	61.05

(1) Revenue and average sales prices are before the impact of hedging activities, if applicable.

Comparison of Year Ended December 31, 2022 to Year Ended December 31, 2021

Revenue. During the year ended December 31, 2022, revenue decreased to $49.7 million from $78.9 million in 2021. Higher commodity prices for all products in 2022 contributed $16.5 million to revenue. Lower sales volumes negatively impacted revenue by $45.7 million. The decline in sales volumes was primarily attributable to the sale of our North Dakota properties on January 3, 2022. The North Dakota properties contributed 1,150 MBoe and $39.5 million in revenue in 2021.

Oil sales volumes decreased to 419 MBbls for the year ended December 31, 2022 from 957 MBbls for year ended December 31, 2021. Gas sales volumes decreased to 1,569 MMcf for the year ended December 31, 2022 compared to 3,432 MMcf for the year ended December 31, 2021.  NGL sales decreased to 134 MBbls for the year ended December 31, 2022 compared to 495 MBbls for the year ended December 31, 2021 The decrease in oil sales volumes was primarily due to natural field declines and the sale of the North Dakota properties in January 2022.

Lease Operating Expenses (“LOE”). LOE for the year ended December 31, 2022 decreased to $10.1 million from $17.9 million in 2021.  The decrease in LOE was primarily due to the sale of the North Dakota properties in January 2022.  LOE per Boe for the year ended December 31, 2022 was $12.41 compared to $8.85 for the same period in 2021. The increase in LOE per Boe was attributable to lower sales volumes in 2022 as compared to 2021 as well as higher cost to operate the remaining Permian Basin wells.

22

Production and Ad Valorem Taxes.  Production and ad valorem taxes for the year ended December 31, 2022 decreased to $4.5 million from $6.2 million in 2021. The decrease was primarily due to lower sales volumes as a result of the sale of the North Dakota properties offset by higher sales prices in 2022 as compared to 2021.  Production and ad valorem taxes as a percentage of oil and gas revenue were 9% in 2022 compared to 8% for the same period in  2021. 

General and Administrative (“G&A”) Expense.  G&A expense, including stock-based compensation, increased to $12.6 million for the year ended December 31, 2022 from $8.1 million in 2021.  G&A expense, per Boe was $15.44 for the year ended December 31, 2022 compared to $4.01 for the same period in 2021. The increase in total G&A expense was primarily due to higher legal and professional costs, higher stock-based compensation as well increased salaries related to severance paid to employees terminated.  

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 increased to $3.3 million for the year ended December 31, 2022 compared to $0.9 million for the year ended December 31, 2021. The increase was primarily due to the vesting of restricted stock in connection with the change in control that occurred in January 2022, which resulted in the recognition of all unamortized costs.

Depreciation, Depletion, and Amortization (“DD&A”) Expenses. DD&A expense excluding accretion of future site restoration, decreased to $6.3 million for the year ended December 31, 2022 from $15.3 million in 2021. The decrease was primarily due to lower future development cost included in the December 31, 2022 reserve report, due to the exclusion of the development cost of PUDs. The full cost pool was also reduced by the sale of our North Dakota properties in January 2022. DD&A expense per Boe for the year ended December 31, 2022 was $7.79 compared to $7.57 in the same period in 2021. 

Interest Expense. Interest expense decreased from $35.8 million for 2021 to $0.1 million in 2022. The decrease was due to lower debt levels in 2022 as compared to 2021.  In connection with the restructuring that occurred on January 3, 2022, our First Lien and Second Lien credit facilities were retired. Our real estate lien note on our office building was paid in full in August 2022. 

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, 2022 and 2021.

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 2021.  For the year ended December 31, 2021, we recognized a loss on our derivative contracts of $33.0 million. We did not have any derivative contracts in 2022.

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. For the year ended December 31, 2021 and 2022, the net capitalized cost of our oil and gas properties did not exceed the future net revenues from our estimated proved reserves. 

23

Working Capital (Deficit). At December 31, 2022, our current assets of $11.2 million exceeded our current liabilities of $6.4 million resulting in a working capital surplus of $4.8 million, compared to a working capital deficit of $216.0 million at December 31, 2021. Current assets at December 31, 2022 primarily consisted of cash of $2.9 million, accounts receivable of $5.0 million, assets held for sale of $3.0 million, and other current assets of $0.4 million. Current liabilities at December 31, 2022 primarily consisted of trade payables of $4.2 million, revenues due to third parties of $2.0 million, and accrued expenses of $0.1 million. 

Capital Expenditures. Capital expenditures in 2021 and 2022 were $1.3 million and $1.5 million, respectively.  The table below sets forth the components of these capital expenditures:

	Years Ended December 31,
	2021		2022
	(in thousands)
Expenditure category:
Exploration/Development	$	1,145	$	1,509
Acquisitions		-		-
Facilities and other		180		35
	$	1,325	$	1,544

During 2021 and 2022, capital expenditures were primarily expenditures on 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. We did not have a capital drilling budget for 2022. 

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,
	2021			2022
	(in thousands)
Net cash provided by operating activities	$	32,419		$	20,312
Net cash (used in) provided by investing activities		(518	)		51,298
Net cash used in financing activities		(24,642	)		(78,768	)
	$	7,259		$	(7,158	)

Operating activities for the year ended December 31, 2022 provided $20.3 million in cash compared to $32.4 million in 2021. The decrease was primarily due to lower net income from operations due to lower sales volumes partially offset by higher commodity prices. Investing activities provided $51.3 million in 2022 primarily from the sale of oil and gas properties in 2022. Cash expenditures for the year ended December 31, 2022 included a decrease of $1.8 million in the future site restoration account related to properties sold, and proceeds from sales on non-oil and gas and oil and gas properties of $72.3 million and a decrease in accounts payable related to capital expenditures of $0.1 million resulting in accrual based capital expenditures incurred during the period of $1.6 million. The Company also invested $19.5 million in the Lion Fund II, L.P. in 2022.  

24

Liquidity and Capital Resources. Our principal sources of capital going forward, are cash flows from operations, proceeds from the sale of properties 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. 

Below is a schedule of the future payments that we are obligated to make based on agreements in place as of December 31, 2022:

	Payments due in the twelve-month periods ended:
Contractual Obligations (In thousands)	Total		December 31, 2023		December 31, 2024-2025		December 31, 2026-2027		Thereafter
Lease obligations	$	1	$	1	$	-	$	-	$	-
Total	$	1	$	1	$	-	$	-	$	-

___________________________

We maintain a reserve for costs associated with the retirement of tangible long-lived assets. At December 31, 2022, our reserve for these obligations totaled $3.0 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, 2022, 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, 2022, 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,
	2021			2022
	(In thousands)
First Lien Credit Facility	$	71,400		$	-
Second Lien Credit Facility		134,907			-
Exit fee - Second Lien Credit Facility		10,000			-
Real estate lien note		2,515			-
		218,822			-
Less current maturities		(212,688	)		-
		6,134			-
Deferred financing fees and debt issuance cost - net		(3,929	)		-
Total long-term debt, net of deferred financing fees and debt issuance costs	$	2,205		$	-

25

In connection with the restructuring that was completed on January 3, 2022, our First Lien Credit Facility was retired and our Second Lien Credit Facility was converted to Series A Preferred Stock. Subsequently, on September 13, 2022, AGEF and Biglari Holdings, entered into a preferred stock purchase agreement (the "Preferred Purchase Agreement"), and an assignment and assumption agreement  pursuant to which AGEF agreed to sell and assign to Biglari Holdings (the "Sales And Assignment"), and Biglari Holdings agreed to purchase, acquire, and assume from AGEF, the Preferred Shares and all of AGEF’s rights, title, and interests in, and duties and obligations under, the Exchange Agreement. Following Biglari Holdings’ acquisition of the Preferred Shares, a change in control of the Company occurred. Biglari Holdings’ ownership of the Preferred Shares resulted in its beneficial ownership, both directly and indirectly, of the approximately 85% of the Company’s voting securities that AGEF owned prior to effecting the Sale and Assignment.

Subsequent to the Sale and Assignment, Biglari Holdings proposed an exchange of the Preferred Shares for shares of the Company’s common stock pursuant to which the Company would issue Biglari Holdings 90,631,287 shares of the Company’s common stock in exchange for the Preferred Shares (such transaction, the "Second Exchange").

To issue the Stock Consideration to Biglari Holdings as contemplated by the Second Exchange, an amendment to Articles of Incorporation, as amended, was needed to increase the number of shares of common stock authorized for the Company’s issuance from 20,000,000 shares to 150,000,000 shares.

On September 23, 2022, the Board approved the Company’s entry into the Second Exchange Agreement. The Company and Biglari Holdings entered into the Second Exchange Agreement on September 27, 2022, with the consummation of the Second Exchange subject to the approval by the Company’s stockholders of the Amendment and the acceptance of the Amendment by the Nevada Secretary of State.

On October 24, 2022, the Company’s stockholders approved the Amendment, and the Company caused the Amendment to be filed with the Nevada Secretary of State that same day. The Nevada Secretary of State accepted the Amendment on October 25, 2022, and on October 26, 2022, the Second Exchange Agreement was consummated by the following transactions: (i) the Company caused 90,631,287 shares of common stock to be registered in the name of Biglari Holdings with the Company’s transfer agent in book-entry form, and (ii) Biglari Holdings assigned and transferred the Preferred Shares to the Company, constituting all of the Preferred Shares of the Company then outstanding, by delivering a Stock Power and Assignment to the Company. The Company cancelled the Series A Preferred Stock and the Preferred Stock Certificate of Designation, such that only common stock of the Company remains outstanding. 

As a result of the Sale and Assignment and Second Exchange, the Company is a consolidated subsidiary of Biglari Holdings, and Biglari Holdings has the power to exert significant control over the Company by controlling both 90% of the voting power of the Company’s outstanding capital stock and a majority of the Company’s Board

Real Estate Lien Note

We had 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 accrued interest at a fixed rate of 4.9%. The note was payable in monthly installments of principal and interest in the amount of $35,672.  The maturity date of the note was July 20, 2023. As of December 31, 2021, $2.5 million was outstanding on the note. The note was paid in full in August 2022

Net Operating Loss Carryforwards

At December 31, 2022, we had, subject to the limitation discussed below, $20.0 million of pre-2018 NOLs and a $186.7 million post 2017 NOL for U.S. tax purposes.  Our pre-2018 NOLs will expire in varying amounts 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).

On October 24, 2022 the Company became a consolidated subsidiary of Biglari Holdings, Inc. for tax purposes.

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 $73.7 million for deferred tax assets at December 31, 2022.

Related Party Transactions

During November and December 2022, the Company invested $19,500 in the Lion Fund II, L.P., as a limited partner.  The Lion Fund II, L.P. is an investment partnership affiliated with Sardar Biglari, a director of Abraxas and Biglari Holdings Inc. There were no related party transactions in  2021.

26

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. Prior management chose 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, 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 $187.0 million impairment recorded as of December 31, 2020.  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, Netherland Sewell & Associates Inc. as of December 31, 2022 and by DeGolyer and MacNaughton as of December 31, 2021. 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, 2021 and 2022, 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 2021, 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, 2022, the Company did not have any derivative contracts.

27

Recently Issued Accounting Standards 

None

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, 2022, a 10% decline in oil and gas prices would have reduced our operating revenue and cash flows by approximately $5.0 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.

Interest Rate Risk

None

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

None

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 principal executive officer and 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, our principal executive officer and principal financial officer concluded that the Company’s internal control over financial reporting was not effective as of December 31, 2022, due to the material weakness described below. In light of the material weaknesses, management performed additional analyses and supplementary review procedures and has concluded that the audited consolidated financial statements contained in this Form 10-K fairly present, in all material respects, our financial condition, results of operations and cash flows for the fiscal years presented in conformity with GAAP.

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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 GAAP 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.

This evaluation identified a material weakness in our internal control over financial reporting. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. As a result of this material weaknesses, management has concluded that our internal control over financial reporting was not effective as of December 31, 2022.

The material weakness identified relates to internal controls over the assessment of long-lived assets for impairments.  Biglari Holdings Inc. (“Biglari Holdings”) acquired control of Abraxas on September 14, 2022 and determined that an impairment assessment had not been performed prior to the acquisition for a rig that was held for sale.  After learning of the overstatement of value, Biglari Holdings identified the material weakness.  Biglari Holdings instructed Abraxas to reflect a loss for the asset to be in compliance with the relevant GAAP standards.  New management is committed to maintaining a strong internal control environment and allocating the necessary resources to remediate the material weakness and is currently developing a remediation plan to address the material weakness.

The effectiveness of our internal control over financial reporting as of December 31, 2022, has not been audited.

Changes in Internal Control Over Financial Reporting

Except for the material weakness as discussed above, there were no changes in our internal control over financial reporting during the fourth quarter of 2022 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Board of Directors

 Following the change of control that occurred on September 13, 2022 the Board of Directors of the Company consists of the following individuals:

SARDAR BIGLARI, age 45, has been Chairman and Chief Executive Officer of Biglari Holdings since 2008. In addition, Mr. Biglari has served as Chairman and Chief Executive Officer of Biglari Capital Corp. (“Biglari Capital”) since 2000. Biglari Capital is the general partner of The Lion Fund, L.P., and The Lion Fund II, L.P., which are private investment partnerships. Mr. Biglari is an entrepreneur with managerial and investing experience in a broad range of businesses.

PHILIP L. COOLEY, age 79, has been a director since September 2022.  Mr. Cooley also serves as Vice Chair of Biglari Holdings Inc. Between 1985 and 2012, he was the Prassel Distinguished Professor of Business at Trinity University, San Antonio, Texas. He has also served as an advisory director of Biglari Capital since 2000. Mr. Cooley has broad business and investment experience.

KENNETH R. COOPER, age 78, has been a director since December 2022. He has been an attorney in the private law practice of the Kenneth R. Cooper Law Office since 1974. Mr. Cooper has experience in real estate and business matters.

BRUCE LEWIS, age 58, has been a director since September 2022. Mr. Lewis serves as Controller of Biglari Holdings Inc.

Meetings of Independent Directors

The Audit and Compensation Committees are composed of independent directors of the Company. The Audit Committee held four meetings and the Compensation Committee held one meeting during 2022.  The member of the Audit Committee is Kenneth R. Cooper.  A shareholder or other interested party wishing to contact the independent directors, as applicable, should send a letter to the Secretary of the Corporation at 19100 Ridgewood Parkway, Suite 1200, San Antonio, Texas 78259. The mailing envelope should contain a clear notation that the enclosed letter is to be forwarded to the Corporation’s independent directors.

Shareholder Communications with the Board

Shareholders who wish to communicate with the Board or a particular director may send a letter to the Secretary of the Corporation at 19100 Ridgewood Parkway, Suite 1200, San Antonio, Texas 78259. The mailing envelope should contain a clear notation that the enclosed letter is a “Shareholder-Board Communication” or “Shareholder-Director Communication.” All such letters should identify the author as a shareholder and clearly state whether the intended recipients are all members of the Board or just certain specified individual directors. The Secretary will make copies of all such letters and circulate them to the appropriate director or directors.

Corporate Governance Guidelines

The Board has adopted Corporate Governance Guidelines to promote effective governance of the Corporation. The Corporate Governance Guidelines are available on the Corporation’s website at biglariholdings.com. A copy of the Corporate Governance Guidelines may also be obtained at no charge by written request to the attention of the Secretary of the Corporation at 19100 Ridgewood Parkway, Suite 1200, San Antonio, Texas 78259.

Code of Ethics 

In April 2004, the Company’s 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. 

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

Executive Officers

Name	Age	Office
Tod A. Clarke....................................................................................	62	Vice President – Land
Clare E. Villarreal.........................................................................	51	Vice President – Chief Accounting Officer

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.

Clare E. Villarreal. has served as Chief Accounting Officer since 2022. Ms. Villarreal joined Abraxas in 1990 and most recently served as Corporate Controller prior to being appointed Chief Accounting Officer.  Ms. Villarreal received a Bachelor of Business Administration and a Masters of Business degree from the University of Texas at San Antonio in 1998 and 2002 respectively.

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 2022.

.

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Item 11. Executive Compensation

Compensation Discussion & Analysis

We compensate our executive officers through a combination of base salary and annual incentive bonuses.

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. The Committee’s membership is determined by the Board of Directors. The Committee, in its sole discretion, has the authority to delegate any of its responsibilities to subcommittees as it deems appropriate.

The Committee periodically approves and adopts, or makes recommendations to the Board regarding, Abraxas’ executive compensation decisions.

The Committee reviews all components of compensation for our executive officers, including base salary, annual incentive bonuses, and the dollar value to the executive and cost to Abraxas of all benefits and all severance 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 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 Abaxas'

budgetary constraints and commensurate with Abraxas’ salary structure; and

• rewarding outstanding performance.

The compensation currently paid to Abraxas’ executive officers consists of base salary and incentive bonuses.

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 2022. The compensation for our CEO in 2022 was approximately 3.7 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 2022 total cash compensation for all individuals, excluding our CEO, who were employed by us on December 16, 2022, 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 2022. 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.

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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 2022 Summary Compensation Table.

As illustrated in the table below, our 2022 CEO to median employee pay ratio was 3.7:1.

	CEO to Median Employee Pay Ratio
	President and CEO			Median Employee
Base Salary..............................................................................................................................................................	$	374,958		$	105,424
Non-Equity Incentive Plan Compensation.........................................................................................................		—			—
All Other Compensation........................................................................................................................................		13,675	(1)		—
	$	388,633		$	105,424

(1)   This amount represents a $10,675 contribution by Abraxas to Mr. Watson’s 401(k) plan and a $3,000 contribution to Mr. Watson’s health savings accounts for 2022.

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 (8)	2022		374,958		—		—		—		—		13,675		388,633
	2021		381,691		—		—		—		—		13,150		394,841
Steven P. Harris Vice President—Chief Financial Officer (9)	2022		239,904		—		—		—		—		3,000		242,904
	2021		228,119		—		—		—		—		3,000		231,119
Peter A. Bommer Vice President—Engineering	2022		252,996		—		—		—		—		11,956		264,952
	2021		250,931		—		—		—		—		12,052		262,983

(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 2021 or 2022.

(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 2021 or 2022.

(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 2021 or 2022.

(5)   The amounts included in this column for 2021 and 2022 include cash bonuses earned and paid under the Annual Bonus Plan. There were no bonuses paid for 2021 or 2022.

(6)   The amounts in this column represent contributions by Abraxas to the named executive officer’s 401(k) plan and health savings accounts for 2021 and 2022.

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

(8)   Mr. Watsons employment was terminated on February 15, 2023.

(9)   Mr. Harris's employment was terminated on September 30, 2022.

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OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END

There were no outstanding equity awards at December 31, 2022 for our named executive officers.

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 February 28, 2023, the number and percentage of outstanding shares of common stock of Abraxas indicated in the following table.

Name and Address of Beneficial Owner	Number of Shares(1)		Percentage (%)
Peter A. Bommer San Antonio, Texas		195,891	*
Tod A. Clarke San Antonio, Texas		168,778	*
Clare Eastland Villarreal San Antonio, Texas		75,076	*
All Officers and Directors as a Group (7 persons)		439,745	*
Biglari Holdings Inc (2)		90,631,292	90%

*      Less than 1%

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

(2) Information related to this stockholder is based on the stockholder’s Schedule 13-D filed with the Securities and Exchange Commission on October 26, 2022. The Schedule 13-D was filed by: (i) Biglari Holdings Inc. (ii) The Lion Fund L.P., (iii) Biglari Capital Corp. and (iv) Sardar Biglari.

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

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

General

The Board of Directors has 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' 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.

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 Abraxasand the related person following certain procedures designated by the Audit Committee. 

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Related Party Transactions

During November and December 2022, the Company invested $19,500 in the Lion Fund II, L.P., as a limited partner.  The Lion Fund II, L.P. is an investment partnership affiliated with Sardar Biglari, a director of Abraxas and Biglari Holdings Inc.

Item 14. Principal Accountant Fees and Services 

PRINCIPAL AUDITOR FEES AND SERVICES

Audit Fees. The aggregate fees billed by ADKF, P.C. for professional services rendered for the audit of Abraxas’ annual financial statements for the years ended December 31, 2022 and 2021, the reviews of the condensed consolidated financial statements included in Abraxas’ quarterly reports on Form 10-Q for the years ended December 31, 2022 and 2021, and the preparation and delivery of consents, comfort letters and other similar documents, were $255,000 for each year.

Audit-Related Fees. The aggregate fees billed by ADKF, P.C. 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, 2022 and 2021 were $0 for each year.

Tax Fees. The aggregate fees billed by ADKF, P.C. for professional services rendered for tax compliance, tax advice or tax planning for the years ended December 31, 2022 and 2021 were $140,000 for each year.

All Other Fees. The aggregate fees billed by ADKF, P.C. 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 years ended December 31, 2022 and 2021, were $0 for each year.

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.

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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 (PCAOB ID 297)		F-2
Consolidated Balance Sheets at December 31, 2021 and 2022		F-4
Consolidated Statements of Operations for the years ended December 31, 2021 and 2022		F-6
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2021 and 2022		F-7
Consolidated Statements of Cash Flows for the years ended December 31, 2021 and 2022		F-8
Notes to Consolidated Financial Statements		F-9

(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	Certificate of Change Pursuant to NRS 78.209 dated October 19, 2020. (Filed as Exhibit 3.1 to our Current Report on Form 8-K filed on October 16, 2020).
3.10	Certificate of Designation of Series A Preferred Stock dated January 3, 2022. (Filed as Exhibit 3.1 to our Current Report on Form 8-K filed January 3, 2022).
3.11	Amended and Restated Bylaws of Abraxas Petroleum Corporation. (Filed as Exhibit 3.1 to our Current Report on Form 8-K filed December 12, 2022).
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	Certificate of Designation of Series A Preferred Stock dated January 3, 2022. (Filed as Exhibit 4.1 to our Current Report on Form 8-K filed January 3, 2022).
*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).

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*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).
10.12	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.)
10.13	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. (Filed as Exhibit 10.2 to our Current Report on Form 10-Q filed on August 8, 2014).
10.14	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. (Filed as Exhibit 10.3 to our Current Report on Form 10-Q filed on August 8, 2014).
*10.15	Abraxas Petroleum Management Incentive Plan. (Filed as Exhibit 10.1 to our Current Report on Form 8-K filed May 18, 2022).
*10.16	Abraxas Petroleum Management Corporation Management Incentive Plan Bonus Agreement. (Filed as Exhibit 10.2 to our Current Report on Form 8-K filed May 18, 2022).
*10.17	Form of Restricted Stock Award Agreement under the Abraxas Petroleum Corporation Amended and Restated 2005 Long-Term Equity Incentive Plan. (Filed as Exhibit 10.3 to our Current Report on Form 8-K filed May 18, 2022).
*10.18	Form of  Restricted Stock Award Agreement under the Abraxas Petroleum Corporation Amended and Restated 2005 Non-Employee Long- Term Equity Incentive Plan. (Filed as Exhibit 10.1 to our Current Report on Form 8-K filed May 18, 2022).
10.19	Exchange Agreement between the Company and Holdings dated September 27, 2022.(Filed as Exhibit 10.1 to our Current Report on Form 8-K filed October 3, 2022).
10.20	Amended and Restated Partnership Agreement of The Lion Fund II, L.P., as amended on June 3, 2015. (Filed as Exhibit 10.1 to our Current Report on Form 8-K filed December 6, 2022).

36

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 Netherland Sewell & Associates (Filed herewith).
23.3	Consent of DeGolyer and MacNaughton. (Filed herewith).
31.1	Certification – Chief Financial Officer. (Filed herewith).
32.1	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. (Furnished herewith).
99.1	Netherland Sewell & Associates report  with respect to oil and reserves of Abraxas Petroleum. (Filed herewith).
99.2	DeGolyer and MacNaughton's report with respect to oil and gas reserves of Abraxas Petroleum (Filed as Exhibit 99.1 to our Annual Report on Form 10-K filed March 31, 2022).

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.

Item 16. 10-K Summary

None

37

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Abraxas Petroleum Corporation
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements (PCAOB ID 297)	F-2
Consolidated Balance Sheets at December 31, 2021 and 2022	F-4
Consolidated Statements of Operations for the years ended December 31, 2021 and 2022	F-6
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2021 and 2022	F-7
Consolidated Statements of Cash Flows for the years ended December 31, 2021 and 2022	F-8
Notes to Consolidated Financial Statements	F-9

F-1

Report of Independent Registered Public Accounting Firm

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Audit Committee of the Board of Directors

Abraxas Petroleum Corporation

San Antonio, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Abraxas Petroleum Corporation as of December 31, 2022 and 2021, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows, for each of the two years in the period ended December 31, 2022, 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, 2022 and 2021 and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America.

Basis of Opinion

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

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

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

Critical Audit Matters

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

F-2

Depletion, Depreciation, Amortization & Impairment

Description of the Matter

Each quarter, the Company analyses the ending reserves prepared by internal and external reservoir engineers and calculates depletion for the full cost pool. The Company calculates depletion based on ending reserves and production to determine the depletion rate and records an adjustment based on production. Additionally, the Company performs a ceiling test to determine if any impairment occurred. The Company compares the present value of the future cash flows and compares the present value to the net book value of the full cost pool and determines if the full cost pool exceeds the present value. We identified depletion, depreciation, amortization, and impairment as a critical audit matter because of the significant judgments made by management in determine reserves which are used in depletion and impairment calculations.

How We Addressed the Matter in Our Audit

To test the critical audit matter we calculated depletion, depreciation, and amortization independently and compared our calculated amount to the amount recorded by the Company. Additionally, we performed a ceiling test to determine if there was any impairment and evaluated factors outside the normal course of business which might indicate impairment occurred. We performed analysis over the reserve report in determining if the reserve report was reasonable and the metrics were appropriate. We also evaluated whether the key factors considered in the evaluation were consistent with evidence obtained in other areas of the audit.

Asset Retirement Obligation

Description of the Matter

The Company records a liability for future costs related to plugging and restoring wellbores. The Company records a liability based on the estimated plugging costs, the risk-free adjusted credit rate, the inflation factor, and the well life. The Company calculates the present value of these factors and records a liability based on calculated future cost of plugging a well. We identified the asset retirement obligation as a critical audit matter because of the significant judgments made by management in determining plugging costs of wells.

How We Addressed the Matter in Our Audit

Our audit procedures related to determining if plugging costs at inception were reasonable based on available information. Additionally, we tested other inputs such as the risk-free adjusted rate, inflation factor and well life to determine if these inputs in the calculation were reasonable. Lastly, we recalculated accretion and compared the recalculated amounts to the general ledger. We also evaluated whether the key factors considered in the evaluation were consistent with evidence obtained in other areas of the audit.

ADKF, P.C.

San Antonio, Texas

April 17, 2023

PCAOB ID 297

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

F-3

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

ASSETS

	December 31,
	2021			2022
	(In thousands, except per share/share data)
Assets
Current assets:
Cash and cash equivalents	$	10,034		$	2,876
Accounts receivable:
Joint owners, net		1,117			163
Oil and gas production sales		12,280			4,715
Other		150			83
Total accounts receivable		13,547			4,961
Assets held for sale		-			3,019
Other current assets		498			357
Total current assets		24,079			11,213
Property and equipment
Proved oil and gas properties, full cost method		1,165,707			1,122,670
Other property and equipment		39,337			3,386
Total		1,205,044			1,126,056
Less accumulated depreciation, depletion, amortization and impairment		(1,099,075	)		(1,082,069	)
Total property and equipment - net		105,969			43,987
Investment in partnership		-			15,091
Operating lease right-of-use assets		173			1
Other assets		255			255
Total assets	$	130,476		$	70,547

See accompanying notes to consolidated financial statements.

F-4

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS (CONTINUED)

LIABILITIES AND STOCKHOLDERS’ EQUITY

	December 31,
	2021			2022
	(In thousands)
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	4,678		$	4,207
Joint interest oil and gas production payable		13,347			2,025
Accrued interest		477			-
Other accrued liabilities		347			136
Derivative liabilities - short-term		442			-
Termination of derivative contracts		8,022			-
Right of use liability		40			1
Current maturities of long-term debt		212,688			-
Total current liabilities		240,041			6,369
Long-term debt - less current maturities		2,205			-
Right of use liability		110			-
Future site restoration		4,708			3,041
Total liabilities		247,064			9,410
Commitments and contingencies (Note 8)
Stockholders' (Deficit) 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 150,000,000 shares; 8,421,910 and 100,701,430 issued and outstanding at December 31, 2021 and 2022, respectively		84			1,007
Additional paid-in capital		430,422			569,896
Accumulated deficit		(547,094	)		(509,766	)
Total stockholders' (deficit) equity		(116,588	)		61,137
Total liabilities and stockholders' (deficit) equity	$	130,476		$	70,547

See accompanying notes to consolidated financial statements.

F-5

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS 

	Years Ended December 31,
	2021			2022
	(In thousands, except per share data)
Revenues:
Oil	$	61,228		$	39,617
Gas		8,656			6,642
Natural gas liquids		8,952			3,456
Other		22			22
Total Revenue		78,858			49,737
Operating costs and expenses
Lease operating		17,914			10,104
Production and ad valorem taxes		6,223			4,458
Rig expense		478			412
Depreciation, depletion, amortization and accretion		15,643			6,511
General and administrative (including stock-based compensation of $946 and $3,296, respectively)		8,116			12,575
Total operating costs and expenses		48,374			34,060
Operating income		30,484			15,677
Other (income) expense:
Interest income		(15	)		(37	)
Interest expense		35,773			111
Amortization of deferred financing fees		4,804			-
Deferred finance fees and warrant cancelation		4,212			-
Gain on debt extinguishment (PPP loan)		(2,716	)		(6,645	)
Loss on investments		-			4,409
Loss on derivative contracts		33,022			-
Loss on drilling rig		-			8,225
Loss on sale of non-oil and gas assets		(29	)		668
Gain on sale of oil and gas assets		-			(28,982	)
Other		-			600
Total other (income) expense		75,051			(21,651	)
(Loss) income before income tax		(44,567	)		37,328
Income tax (expense) benefit		-			-
Net (loss) income	$	(44,567	)	$	37,328
Net (loss) income per common share - basic	$	(5.30	)	$	1.44
Net (loss) income per common share - diluted	$	(5.30	)	$	1.44
Weighted average shares outstanding
Basic		8,408			25,868
Diluted		8,408			25,868

See accompanying notes to consolidated financial statements.

F-6

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands except number of shares)

											Additional
	Common Stock				Preferred Stock						Paid in			Accumulated
	Shares		Amount		Shares			Amount			Capital			Deficit			Total
Balance at December 31, 2020		8,421,910	$	84		-		$	-		$	429,476		$	(502,527	)	$	(72,967	)
Net loss		-		-		-			-						(44,567	)		(44,567	)
Stock-based compensation		-		-		-			-			946			-			946
Balance at December 31, 2021		8,421,910		84		-			-			430,422			(547,094	)		(116,588	)
Net income		-		-		-			-			-			37,328			37,328
Stock-based compensation		-		-		-			-			3,296			-			3,296
Preferred Stock issued		-		-		685,505			7			137,094			-			137,101
Preferred stock exchanged for common stock		90,631,287		906		(685,505	)		(7	)		(899	)		-			-
Restricted stock issued net of cancellations		1,648,233		17		-			-			(17	)		-			-
Balance at December 31, 2022		100,701,430	$	1,007		-		$	-		$	569,896		$	(509,766	)	$	61,137

See accompanying notes to consolidated financial statements.

F-7

ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended December 31,
	2021			2022
Operating Activities:
Net (loss) income	$	(44,567	)	$	37,328
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Loss (gain) on sale of non-oil and gas assets		(29	)		668
Loss on drilling rig		-			8,225
Gain on sale of oil and gas properties		-			(28,982	)
Net loss on derivative contracts		33,022			-
Net cash settlements paid on derivative contracts		(3,197	)		-
Depreciation, depletion and amortization		15,312			6,341
Amortization of deferred financing fees and issuance discount		8,781			-
Non-cash financing fees and warrant cancellation		194			-
Accretion of future site restoration		330			170
Loss on investment		-			4,409
Debt forgiveness of PPP loan		(2,716	)		(6,645	)
Plugging cost		(342	)		-
Non-cash interest		24,705			-
Non-cash hedge termination		9,943			(401	)
Stock-based compensation		946			3,296
Changes in operating assets and liabilities:
Accounts receivable		(3,498	)		8,586
Assets held for sale		-			3,019
Other assets		(8,851	)		(3,297	)
Accounts payable		3,151			(11,717	)
Accrued expenses and other		(765	)		(688	)
Net cash provided by operating activities		32,419			20,312
Investing Activities
Capital expenditures, including purchase and development of properties		(887	)		(1,544	)
Investment		-			(19,500	)
Proceeds from the sale of oil and gas properties		141			71,696
Proceeds from the sale of non-oil and gas assets		228			646
Net cash (used in) provided by investing activities		(518	)		51,298
Financing Activities
Proceeds from PPP loan		1,332			-
Payments of long-term borrowings		(25,816	)		(77,966	)
Deferred financing fees		(158	)		(802	)
Net cash used in financing activities		(24,642	)		(78,768	)
Increase in cash and cash equivalents		7,259			(7,158	)
Cash and cash equivalents at beginning of period		2,775			10,034
Cash and cash equivalents at end of period	$	10,034		$	2,876
Supplemental disclosure of cash flow information:
Interest paid	$	6,463		$	70
Income tax paid	$	-		$	-
Non-cash investing and financing activities
Non-cash issuance of stock	$	-		$	137,101
Change in asset retirement obligation cost and liabilities	$	204		$	-
Asset retirement obligations associated with dispositions	$	(2,845	)	$	(1,837	)
Debt Forgiveness	$	-		$	(6,645	)
Change in capital expenditures included in accounts payable	$	5		$	(76	)

See accompanying notes to consolidated financial statements.

F-8

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.

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 2021 and 2022, the drilling rig was idle. Accordingly, the cost of maintaining the rig was charged to the statement of operations. The drilling rig was sold in February 2023.

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, 2021 and 2022. 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- 9

 

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 the 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, 2021 and 2022, our capitalized cost of oil and gas properties did not exceed the future net revenue from our estimated proved reserves.

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

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- 10

 

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, 2021 and 2022, stock-based compensation was approximately $0.9 million and $3.3 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: 

	2021			2022
Beginning future site restoration obligation	$	7,360		$	4,708
New wells placed on production and other		1			-
Deletions related to property disposals		(2,845	)		(1,837	)
Deletions related to plugging costs		(342	)		-
Accretion expense and other		330			170
Revisions and other		204			-
Ending future site restoration obligation	$	4,708		$	3,041

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.

During 2021, four purchasers accounted for 83% of oil and gas revenues. During 2022, three purchasers accounted for 90% 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- 11

 

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 $73.7 million for deferred tax assets at December 31, 2022.

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, 2022.

Adoption of New Accounting Standards 

None

F- 12

 

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 are 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, 2021 and 2022. 

Disaggregation of Revenue

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

	Years Ended December 31,
	2021						2022
	Oil		Gas		NGL		Oil		Gas		NGL
Operating Region
Permian/Delaware Basin	$	32,666	$	4,474	$	2,181	$	39,617	$	6,642	$	3,456
Rocky Mountain (1)	$	28,562	$	4,182	$	6,771	$	-	$	-	$	-

(1)  All Rocky Mountain assets were sold  January 3, 2022.

F- 13

 

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, 2021 and December 31, 2022, our receivables from contracts with customers were $12.3 million and $4.7 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, 2022, 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 was 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 did 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.

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.

F- 14

4. Long-Term Debt

The following is a description of the Company’s debt as of  December 31, 2021 and 2022:

	Years ended December 31,
	2021			2022
	(In thousands)
First Lien Credit Facility	$	71,400		$	-
Second Lien Credit Facility		134,907			-
Exit fee - Second Lien Credit Facility		10,000			-
Real estate lien note		2,515			-
		218,822			-
Less current maturities		(212,688	)		-
		6,134			-
Deferred financing fees and debt issuance cost - net		(3,929	)		-
Total long-term debt, net of deferred financing fees and debt issuance costs	$	2,205		$	-

Restructuring

Pursuant to the Exchange Agreement, dated as of January 3, 2022, between Abraxas and AGEF (the “Exchange Agreement”) and certain other agreements entered into by Abraxas on January 3, 2022, we effectuated a restructuring of our then-existing indebtedness through a multi-part interdependent deleveraging transaction consisting of: (i) an Asset Purchase and Sale Agreement  pursuant to which Abraxas sold to Lime Rock Resources V-A, L.P. certain oil, gas, and mineral properties in the Williston Basin region of North Dakota and other related assets belonging to the Company and its subsidiaries for $87.2 million in cash less customary closing adjustments, (ii) the pay down of the indebtedness and other obligations of Abraxas and its subsidiaries under the First Lien Credit Facility and (iii), a debt for equity exchange of the indebtedness and other obligations of Abraxas and its subsidiaries under the $100.0 million Second Lien Credit Facility (the “Exchange” and, together with the transactions referred to in clauses (i) and (ii), the “Restructuring”). AGEF was issued 685,505 shares of Series A Preferred Stock of the Company (the "Preferred Shares") in the Exchange, which entitled AGEF to approximately 85% of the voting power of the Company’s then outstanding capital stock.

The Restructuring also involved a change in a majority of the Board’s directors. Pursuant to the Exchange Agreement, immediately prior to the closing of the Restructuring, two former Board members resigned. Immediately after the consummation of the Restructuring, the existing Board members resolved to increase the size of the Board by one member from four to five directors and to appoint three employees of AGEF as members of the Board, one of whom became Chairman of the Board.

Real Estate Lien Note

We had a real estate lien note secured by a first lien deed of trust on the property and improvements. The note was paid in full in August 2022.

F- 15

 

5. Property and Equipment

The major components of property and equipment, at cost, are as follows:

	Estimated		December 31,
	Useful life		2021			2022
	Years		(In thousands)
Oil and gas properties (1)		-	$	1,165,707		$	1,122,670
Equipment and other		3-39		15,257			3,386
Drilling rig (1) (2)		15		24,080			-
				1,205,044			1,126,056
Accumulated depreciation, depletion, amortization and impairment				(1,099,075	)		(1,082,069	)
Net property and equipment			$	105,969		$	43,987

(1) Oil and gas properties are amortized utilizing the units of production method.

(2) The Company owned a 2000 HP drilling rig which was sold in February 2023. The drilling rig was impaired during 2022 resulting in a loss of $8,225.

6.  Stock-Based Compensation and Option Plans

The Company’s Amended and Restated 2005 Employee Long-Term Equity Incentive Plan reserves 1,683,639 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 2021 or 2022

The following table is a summary of the Company’s stock option activity for the two years ended December 31:

	Options			Weighted average		Weighted average		Intrinsic value
	(000s)			exercise price		remaining life		per share
Options outstanding December 31, 2020		196		$	49.69
Forfeited/Expired		(141	)		48.11
Options outstanding December 31, 2021		55		$	53.79
Forfeited/Expired		(55	)		53.79
Options outstanding December 31, 2022		-		$	-		-	$	-
Exercisable at end of year		-		$	-		-	$	-

F- 16

 

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. 

The following table is a summary of the Company’s restricted stock activity for the two years ended December 31, 2022:

	Number of Shares			Weighted average grant date fair value
Unvested December 31, 2020		41		$	31.37
Granted		(24	)		33.23
Vested/Released		(3	)		32.07
Unvested December 31, 2021		14		$	27.97
Granted		1,650			1.25
Vested/Released		(1,664	)		2.10
Unvested December 31, 2022		-		$	-

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 vested over a three-year period upon the achievement of performance goals based on the Company’s Total Shareholder Return (“TSR”) as compared to a peer group of companies.   No shares were vested under this plan due to not achieving the performance goals.

F- 17

 

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, 2020		44		$	33.73
Granted		-			-
Vested/Released		-			-
Forfeited		(16	)		45.73
Unvested December 31, 2021		28		$	26.80
Granted		-			-
Vested/Released		-			-
Forfeited		(28	)		26.80
Unvested December 31, 2022		-		$	-

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.

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. There were no awards under this plan in 2021 or 2022.

At December 31, 2022, the Company had approximately 418,000 shares reserved, under its Employee and Directors plans, for future issuance for conversion of its stock options, and incentive plans for the Company’s directors, employees and consultants.

All shares reserved under the Employee and Directors plans were cancelled in January 2023.

F- 18

 

7. Income Taxes

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,
	2021			2022
	(In thousands)
Deferred tax liabilities:
Hedge contracts	$	-		$	-
Other		2,855			-
Total deferred tax liabilities		2,855			-
Deferred tax assets:
US full cost pool	$	24,464		$	17,533
Depletion		470			452
U.S. net operating loss carryforward		96,120			50,103
Alternative minimum tax credit		-			-
Unrealized losses		100			956
Interest disallowed		5,781			4,367
Other		-			239
Total deferred tax assets		126,935			73,650
Valuation allowance for deferred tax assets		(124,080	)		(73,650	)
Net deferred tax assets		2,855			-
Net deferred tax	$	-		$	-

At December 31, 2022, the Company had, $20.0 million of pre-2018 NOLs for U.S. tax purposes and $186.7 million of post-2017 NOLs for U.S. tax purposes.  Our pre-2018 NOLs will expire in varying amounts 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).

On October 24, 2022, the Company became a consolidated subsidiary of Biglari Holdings Inc. for tax purposes.

Our NOL was reduced as a result of the ownership change that occurred in 2022. The use of our NOLs will be further limited if there is an additional “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. Given historical losses, uncertainties exist as to the future utilization of the NOL carryforwards, therefore, the Company has established a valuation allowance of $124.1  million at  December 31, 2021 and $73.7 million at December 31, 2022.

F- 19

 

The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is:

	Years Ended December 31,
	2021			2022
	(in thousands)
Tax benefit at U.S. Statutory rates	$	9,359		$	(7,839	)
Change in deferred tax asset valuation allowance		(7,007	)		50,431
Alternative minimum tax expense		-			-
Adjustment to deferred tax assets		(3,421	)		(307	)
Permanent differences		368			692
Reduction to NOL due to ownership change limitation		-			(41,160	)
Return to provision estimated revision		-			(2,070	)
State income taxes, net of federal effect		688			253
Other		13			-
	$	-		$	-

As of   December 31, 2021 and 2022, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years 2015 through 2022 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 and 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. 

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, 2022, 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,
	2021			2022
Numerator:
Net (loss) income	$	(44,567	)	$	37,328
Denominator for basic earnings per share - weighted-average common shares outstanding		8,408			25,868
Effect of dilutive securities: Stock options, restricted shares and performance based shares		-			-
Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options, restricted shares and performance based shares		8,408			25,868
Net (loss) income per common share - basic	$	(5.30	)	$	1.44
Net (loss) income per common share - diluted	$	(5.30	)	$	1.44

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.   

F- 20

 

10. Benefit Plans

The Company had a defined contribution plan (401(k) plan) covering all eligible employees. For  2021, in accordance with the safe harbor provisions of the Plan, the Company contributed $125,276. The Company contributed $85,516 to the plan for 2022, and contributed an additional $29,541 in 2023 for 2022. 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 2021 was $19,500 for employees under the age of 50 and $26,000 for employees 50 years of age or older. For 2022 the employee contribution limit was $20,500 for employees under the age of 50 and $27,000 for employees 50 years of age or older. 

11. Hedging Program and Derivatives and Financial Instruments

As of December 31, 2022 the Company is not party to any hedge agreements. The liability as of December 31, 2021 relates to the December 2021 contract settlement paid in January 2022.

The following table illustrates the impact of derivative contracts on the Company’s balance sheet:

Fair Value Financial Instruments as of December 31, 2021
	Asset			Liability
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity price derivatives	Derivatives - current	$	-	Derivatives - current	$	442
		$	-		$	442

Fair Value of Investments as of December 31, 2022
	Asset
	Balance Sheet Location	Fair Value
Financial instruments	Investments - long term	$	15,091
		$	15,091

F- 21

 

12. Financial Instruments and Investment in Partnership.

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, 2021 and 2022, 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, 2021
Liabilities:
NYMEX fixed price derivative contracts	$	-	$	442	$	-	$	442
Total Liabilities	$	-	$	442	$	-	$	442

The Company’s derivative contracts for the year ended  December 31, 2021 consisted of a NYMEX-based fixed price commodity swap.  The NYMEX-based fixed price derivative contracts were 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.

During  November and December 2022, the Company invested $19,500 in the Lion Fund II, L.P. as a limited partner.  The Lion Fund II, L.P. is an investment partnership affiliated with Sardar Biglari, a director of Abraxas and Biglari Holdings Inc.

The fair value of the Company’s investment in the Lion Fund II, L.P. at, December 31, 2022, was $15,091 Fair value has been determined utilizing the net asset value as a practical expedient pursuant to US GAAP. 

A Limited Partner may withdraw all or any portion of its capital account attributable to a particular capital contribution as of the March 31 of the fifth year after the year in which such Limited Partner made such contribution, and every March 31 occurring every five years thereafter. 

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 rented a residence in North Dakota from a third party for living accommodations for certain field employees. Our real estate lease was 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. The North Dakota residential lease was assigned to a third-party on January 3, 2022. See Note 14  “Subsequent Events.”

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. 

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, 2021 and  December 31, 2022, the majority of which is included in lease operating expense, are as follows:

	For the Year Ended December 31,
	2021		2022
	(in thousands)
Operating lease cost	$	65	$	11
Short-term lease expense (1)		1,913		578
Total lease expense	$	1,978	$	589
Short-term lease costs (2)	$	-	$	-

(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,
	2021		2022
	(in thousands)
Operating lease Right of Use asset	$	173	$	1
Operating lease liability - current	$	40	$	1
Operating lease liabilities - long-term	$	110	$	-

Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows:

	For the Year Ended December 31,
	2021			2022
	(in thousands)
Weighted Average Remaining Lease Term (in years)		12.46			0.08
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)
2023		1
2024		-
2025		-
2026		-
2027		-
Thereafter		-
Total lease payments		1
Less imputed interest		-
Total lease liability	$	1

Supplemental cash flow information related to our operating leases is included in the table below:

	For the Year Ended December 31,
	2021		2022
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities	$	65	$	11
Right of Use assets added in exchange for lease obligations (since adoption)	$	-	$	-

F- 24

 

14. Restructuring

Pursuant to the Exchange Agreement, dated as of January 3, 2022, between the Company and AG Energy Funding, LLC (“AGEF”) and certain other agreements entered into by the Company on January 3, 2022, the Company effectuated a restructuring of the Company’s  then-existing indebtedness through a multi-part interdependent deleveraging transaction consisting of: (i) an Asset Purchase and Sale Agreement pursuant to which the Company sold to Lime Rock Resources V-A, L.P. certain oil, gas, and mineral properties in the Williston Basin region of North Dakota and other related assets belonging to the Company and its subsidiaries for $87.2 million in cash ($73.3 million after customary closing adjustments), (the “Sale”), (ii) the pay down of the indebtedness and other obligations of the Company and its subsidiaries under the First Lien Credit Facility; and (iii), a debt for equity exchange of the indebtedness and other obligations of the Company  and its subsidiaries under the $100.0 million Second Lien Credit Facility, and all related loan and security documents (the “Exchange” and, together with the transactions referred to in clauses (i) and (ii), the “Restructuring”). 

AGEF was issued 685,505 shares of Series A Preferred Stock of the Company (the "Preferred Shares") in the Exchange.  The Series A Preferred Stock has the terms set forth in the Company’s filed Preferred Stock Certificate of Designation (the “Certificate).  The shares of Series A Preferred Stock vote together as a single class with the Company’s common stock, and each share of Series A Preferred Stock entitles the holder thereof to 69 votes. Accordingly, AGEF’s ownership of the Series A Preferred Stock entitled it to approximately 85% of the voting power of the Company’s then-outstanding capital stock.

On September 13, 2022, AGEF and Biglari Holdings Inc. ("Biglari Holdings") entered into a preferred stock purchase agreement (the "Preferred Purchase Agreement") and an assignment and assumption agreement pursuant to which AGEF agreed to sell and assign to Biglari Holdings (the "Sales and Assignment Agreement"), and Biglari Holdings agreed to purchase, acquire, and assume from AGEF, the Preferred Shares and all of AGEF’s rights, title, and interests in, and duties and obligations under, the Exchange Agreement. Following Biglari Holdings’ acquisition of the Preferred Shares, a change in control of the Company occurred. Biglari Holdings’ ownership of the Preferred Shares resulted in its beneficial ownership, both directly and indirectly, of the approximately 85% of the Company’s voting securities.

In connection with the transactions contemplated by the Preferred Purchase Agreement, the four directors of the Company appointed by AGEF resigned from the Board. Also, in accordance with the terms of the Preferred Purchase Agreement, on September 13, 2022, the Board voted to appoint Messrs. Sardar Biglari, Philip Cooley, and Bruce Lewis as members of the Board to fill three of the vacancies created by the resignations of the AGEF appointed directors. All three newly appointed members of the Board are affiliated with Biglari Holdings.

Subsequent to the Sale and Assignment, Biglari Holdings proposed an exchange of the Preferred Shares for shares of the Company’s common stock pursuant to which the Company would issue Biglari Holdings 90,631,287 shares of the Company’s common stock (the “Stock Consideration”) in exchange for the Preferred Shares (such transaction, the “Second Exchange”).

To issue the Stock Consideration to Biglari Holdings as contemplated by the Second Exchange, an amendment to  Articles of Incorporation, as amended, was needed to increase the number of shares of common stock authorized for issuance from 20,000,000 shares to 150,000,000 shares (the “Amendment”).

On September 23, 2022, the Board approved the Company’s entry into an exchange agreement with Biglari Holdings that defines the terms of the Second Exchange (the “Second Exchange Agreement”). The Company and Biglari Holdings entered into the Second Exchange Agreement on September 27, 2022, with the consummation of the Second Exchange subject to the approval by the Company’s stockholders of the Amendment and the acceptance of the Amendment by the Nevada Secretary of State.

On October 24, 2022, the Company’s stockholders approved the Amendment, and the Company caused the Amendment to be filed with the Nevada Secretary of State that same day. The Nevada Secretary of State accepted the Amendment on October 25, 2022, and on October 26, 2022, the Second Exchange Agreement was consummated by the following transactions: (i) the Company caused 90,631,287 shares of common stock to be registered in the name of Biglari Holdings with the Company’s transfer agent in book-entry form, and (ii) Biglari Holdings assigned and transferred  the Preferred Shares to the Company, constituting all of the Preferred Shares of the Company then outstanding, by delivering a Stock Power and Assignment to the Company. The Company cancelled the Series A Preferred Stock and the Preferred Stock Certificate of Designation, such that only common stock of the Company remains outstanding. The foregoing description of the Second Exchange and the Second Exchange Agreement is a summary only, does not purport to be complete, and is qualified in its entirety by reference to the complete text of the Second Exchange Agreement, which is filed as Exhibit 10.1 on Form 8-K filed on October 3, 2022, and is incorporated by reference herein. 

As a result of the Sale and Assignment and Second Exchange, the Company is a consolidated subsidiary of Biglari Holdings, and Biglari Holdings has the power to exert significant control over the Company by controlling both 90% of the voting power of the Company’s outstanding capital stock and a majority of the Company’s Board. 

F- 25

 

15.  Subsequent Events

On February 1, 2023, the Company filed Form 15 with the Securities and Exchange Commission. The purpose of this filing is to give notice of termination of registration under Section 12(g) of the Securities and Exchange Act of 1934, as amend (the "Exchange Act" and suspension of duty to file reports under Sections 13 and 15(d) of the  Exchange Act  The Form 15 does not become effective until 90 days after its filing (unless the SEC allows it to become effective earlier).

Robert L.G.Watson, the Company's President and Principal Executive Officer, resigned from his position effective March 1, 2023.

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, 2021 and 2022:

	Years Ended December 31,
	(in thousands)
	2021			2022
Proved oil and gas properties	$	1,165,707		$	1,122,670
Unproved properties		-			-
Total		1,165,707			1,122,670
Accumulated depreciation, depletion, amortization and impairment		(1,074,144	)		(1,078,865	)
Net capitalized costs	$	91,563		$	43,805

Cost incurred in oil and gas property acquisition and development activities were as follows for the years ended December 31, 2021 and 2022 (in thousands):

	2021		2022
Development costs	$	1,145	$	1,509
Exploration costs		-		-
Property acquisition costs		-		-
	$	1,145	$	1,509

F- 26

 

Results of operations from oil and gas producing activities were as follows for the years ended December 31, 2021 and 2022:

	2021			2022
Revenues	$	78,836		$	49,715
Production costs		(24,137	)		(14,562	)
Depreciation, depletion and amortization		(13,495	)		(4,720	)
Accretion of future site restoration		(330	)		(170	)
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$	40,874		$	30,263
Depletion rate per barrel of oil equivalent	$	6.67		$	5.80

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.

F- 27

 

The following table presents the Company’s estimate of its net proved developed and undeveloped oil and gas reserves as of December 31, 2021 and 2022:

	Total
							Oil
	Oil		NGL		Gas		Equivalents
	(MBbl)		(MBbl)		(MMcf)		(Mboe)
Proved Developed Reserves:
December 31, 2021		6,883		2,914		30,158		14,823
December 31, 2022		3,300		1,508		18,847		7,949
Proved Undeveloped Reserves:
December 31, 2021		-		-		-		-
December 31, 2022		-		-		-		-

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, Netherland Sewell & Associates Inc., assisted by the engineering and operations departments of the Company as of   December 31, 2022 and by DeGolyer & MacNaughton, assisted by the engineering and operations departments of the Company, as of December 31, 2021. 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 2021, and 2022, 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 Netherland Sewell & Associates Inc. 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. Netherland Sewell & Associates Inc. 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 Netherland Sewell & Associates Inc. were developed utilizing studies performed by Netherland Sewell & Associates Inc. and assisted by the Engineering and Operations departments of Abraxas. Reserves are estimated by independent petroleum engineers.  The report of Netherland Sewell & Associates Inc. dated February 10, 2023, contains further discussions of the reserve estimates and evaluations prepared by Netherland Sewell & Associates Inc. as well as the qualifications of Netherland Sewell & Associates Inc's. technical personnel responsible for overseeing such estimates and evaluations is attached as Exhibit 99.1 to this report.

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 4, 2022, 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 was filed as Exhibit 99.2 to this report.

Estimates of proved reserves at  December 31, 2021 and 2022 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 43 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.

F- 28

 

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, 2021  and 2022 :

	Years Ended December 31,
	(in thousands)
	2021			2022
Future cash inflows	$	485,982		$	431,728
Future production costs		(222,309	)		(192,611	)
Future development costs		(5,623	)		(4,728	)
Future income tax expense		-			-
Future net cash flows		258,050			234,389
Discount	$	(104,775	)	$	(100,511	)
Standardized Measure of discounted future net cash relating to proved reserves	$	153,275		$	133,878

F-29

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/ Clare E.Villarreal
	Chief Accounting Officer, Principal Executive Officer, Principal Financial Officer and Principal Accounting Officer

DATED:  April 17, 2023

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/ Clare E. Villarreal Clare E.Villarreal	Chief Accounting Officer (Principal Executive Officer, Principal Financial Officer and Principal Accounting Officer)	April 17, 2023
/s/ Sardar Biglari Sardar Biglari	Chairman of the Board, Director	April 17, 2023
/s/ Philip I. Cooley Philip I. Cooley	Director	April 17, 2023
/s/ Kenneth R. Cooper Kenneth R. Cooper	Director	April 17, 2023
/s/ Bruce Lewis Bruce Lewis	Director	April 17, 2023

F-30

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

Abraxas Petroleum Corporation

San Antonio, Texas

We consent to the incorporation by reference in the registration statements on Form S-8 (No. 333-206521, No. 333-221184, No. 333-231645 and 333-264973) of our report dated March 31, 2023, with respect to the consolidated financial statements of Abraxas Petroleum Corporation included in the Annual Report (Form 10-K) for the year ended December 31, 2022.

/s/ ADKF, P.C.

San Antonio, Texas

April 17, 2023

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the inclusion in this Annual Report on Form 10-K of Abraxas Petroleum Corporation for the year ended December 31, 2022, of our report dated February 10, 2023, with respect to estimates of reserves and future net revenue of Abraxas Petroleum Corporation, as of December 31, 2022, and to all references to our firm included in this Annual Report.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ C.H. (Scott) Rees III
	C.H. (Scott) Rees III, P.E.
	Executive Chairman

Dallas, Texas

March 24, 2023

EX-23.3

Exhibit 23.3

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

March 31, 2023

Abraxas Petroleum Corporation

18803 Meisner Drive

San Antonio, Texas, 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 report entitled “Report as of December 31, 2021 on Reserves and Revenue of Certain Properties with interests attributable to Abraxas Petroleum Corporation” (the Report) 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, 2022. We also consent to the inclusion of our report of third party dated February 4, 2022, in the Annual Report on Form 10-K of Abraxas Petroleum Corporation as Exhibit 99.2.

Very truly yours,

                                                                                      /s/DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Clare E. Villarreal, certify that:    

1. I have reviewed this annual report on Form 10-K of Abraxas Petroleum Corporation.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report,

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report,

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal 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 most recent fiscal quarter (the fourth fiscal quarter in the case of an annual report)  that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 17, 2023

/s/Clare E. Villarreal

Clare E. Villareal

Chief Accounting Officer, Principal Executive Officer 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, 2022 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Clare E. Villarreal, Chief Accounting Officer, principal executive officer and principal 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/Clare E. Villarreal

Clare E. Villarreal

Chief Accounting Officer Principal Executive Officer

and Principal Financial Officer

April 17, 2023

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

February 10, 2023

Mr. Robert L. G. Watson

Abraxas Petroleum Corporation

18803 Meisner Drive

San Antonio, Texas 78258

Dear Mr. Watson:

In accordance with your request, we have estimated the proved developed producing reserves and future revenue, as of December 31, 2022, to the Abraxas Petroleum Corporation (Abraxas) interest in certain oil and gas properties located in Texas. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Abraxas. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Abraxas' use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Abraxas interest in these properties, as of December 31, 2022, to be:

	Net Reserves			Future Net Revenue (M$)
	Oil	NGL	Gas		Present Worth
Category	(MBBL)	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	3,299.2	1,508.0	18,847.5	234,394.0	133,898.7

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Our study indicates that as of December 31, 2022, there are no proved developed non-producing or proved undeveloped reserves for these properties. No study was made to determine whether probable or possible reserves might be established for these properties. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage.

Gross revenue is Abraxas's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Abraxas's share of production taxes, ad valorem taxes, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2022. For oil and NGL volumes, the average West Texas Intermediate spot price of $94.14 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $6.357 per MMBTU is adjusted for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $93.75 per barrel of oil, $27.99 per barrel of NGL, and $4.254 per MCF of gas.

Operating costs used in this report are based on operating expense records of Abraxas. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Abraxas are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

Abandonment costs used in this report are Abraxas' estimates of the costs to abandon the wells and production facilities, net of any salvage value. Abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Abraxas interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Abraxas receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Abraxas, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Abraxas, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical person primarily responsible for preparing the estimates presented herein meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Michael B. Begland, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1993 and has over 8 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

/s/ C.H. (Scott) Rees III

By:                  

C.H. (Scott) Rees III, P.E.

Executive Chairman

/s/ Michael B. Begland

By:                  

Michael B. Begland, P.E. 104898

Vice President

Date Signed: February 10, 2023

MBB:LEE

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) 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.

Supplemental definitions from the 2018 Petroleum Resources Management System:

Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

Definitions - Page 1 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

Definitions - Page 2 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

Definitions - Page 3 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) 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.

Definitions - Page 4 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(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.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas: 932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
a.	Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b.	Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
a.	Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b.	Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c.	Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
d.	Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
e.	Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f.	Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

Definitions - Page 5 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) 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.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule. Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
●	The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
●	The company's historical record at completing development of comparable long-term projects;
●	The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
●	The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
●	The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 6 of 6

XML

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2022	Mar. 23, 2023	Jun. 30, 2022
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	2022
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
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	19100 Ridgewood Parkway, Suite 1200
Entity Address, City or Town	San Antonio
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	78259
City Area Code	210
Local Phone Number	490-4788
Title of 12(b) Security	Common Stock, par value $.01 per share
Trading Symbol	AXAS
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
ICFR Auditor Attestation Flag	false
Entity Shell Company	false
Entity Public Float			$ 15,752,023
Entity Common Stock, Shares Outstanding		100,701,430
Auditor Firm ID	297
Auditor Name	ADKF, P.C.
Auditor Location	San Antonio, Texas

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 2,876	$ 10,034
Accounts receivable:
Joint owners, net	163	1,117
Oil and gas production sales	4,715	12,280
Other	83	150
Total accounts receivable	4,961	13,547
Assets held for sale	3,019	0
Other current assets	357	498
Total current assets	11,213	24,079
Property and equipment
Proved oil and gas properties, full cost method	1,122,670	1,165,707
Other property and equipment	3,386	39,337
Total	1,126,056	1,205,044
Less accumulated depreciation, depletion, amortization and impairment	(1,082,069)	(1,099,075)
Total property and equipment - net	43,987	105,969
Investment in partnership	15,091	0
Operating lease right-of-use assets	1	173
Other assets	255	255
Total assets	70,547	130,476
Current liabilities:
Accounts payable	4,207	4,678
Joint interest oil and gas production payable	2,025	13,347
Accrued interest	0	477
Other accrued liabilities	136	347
Derivative liability, current	0	442
Termination of derivative contracts	0	8,022
Right of use liability	1	40
Current maturities of long-term debt	0	212,688
Total current liabilities	6,369	240,041
Right of use liability	0	110
Future site restoration	3,041	4,708
Total liabilities	9,410	247,064
Commitments and contingencies (Note 8)
Stockholders' (Deficit) 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 150,000,000 shares; 8,421,910 and 100,701,430 issued and outstanding at December 31, 2021 and 2022, respectively	1,007	84
Additional paid-in capital	569,896	430,422
Accumulated deficit	(509,766)	(547,094)
Total stockholders' (deficit) equity	61,137	(116,588)
Total liabilities and stockholders' (deficit) equity	70,547	130,476
Debt Instruments Excluding PPP Loan [Member]
Current liabilities:
Long-term debt - less current maturities	$ 0	$ 2,205

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Consolidated Balance Sheets (Parentheticals) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
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)	150,000,000	150,000,000
Common stock, issued (in shares)	100,701,430	8,421,910
Common stock, outstanding (in shares)	100,701,430	8,421,910

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Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Revenues:
Other	$ 22	$ 22
Total Revenue	49,737	78,858
Operating costs and expenses
Lease operating	10,104	17,914
Production and ad valorem taxes	4,458	6,223
Rig expense	412	478
Depreciation, depletion, amortization and accretion	6,511	15,643
General and administrative (including stock-based compensation of $946 and $3,296, respectively)	12,575	8,116
Total operating costs and expenses	34,060	48,374
Operating income	15,677	30,484
Other (income) expense:
Interest income	(37)	(15)
Interest expense	111	35,773
Amortization of deferred financing fees	0	4,804
Deferred finance fees and warrant cancelation	0	4,212
Gain (loss) on debt extinguishment	6,645	0
Loss on investments	4,409	0
Loss on derivative contracts	0	33,022
Loss on drilling rig	8,225	0
Loss on sale of non-oil and gas assets	668	(29)
Gain on sale of oil and gas assets	(28,982)	0
Other	600	0
Total other (income) expense	(21,651)	75,051
(Loss) income before income tax	37,328	(44,567)
Income tax (expense) benefit	0	0
Net (loss) income	$ 37,328	$ (44,567)
Net (loss) income per common share - basic (in dollars per share)	$ 1.44	$ (5.30)
Net (loss) income per common share - diluted (in dollars per share)	$ 1.44	$ (5.30)
Weighted average shares outstanding
Basic (in shares)	25,868	8,408
Diluted (in shares)	25,868	8,408
Paycheck Protection Program, CARES Act [Member]
Other (income) expense:
Gain (loss) on debt extinguishment	$ (6,645)	$ (2,716)
Oil Revenues [Member]
Revenues:
Revenues	39,617	61,228
Gas Revenues [Member]
Revenues:
Revenues	6,642	8,656
Natural Gas Liquids Revenues [Member]
Revenues:
Revenues	$ 3,456	$ 8,952

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Consolidated Statements of Operations (Parentheticals) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Stock-based compensation	$ 3,296	$ 946

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Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Exchange Preferred Shares For Common Stock [Member] Common Stock [Member]	Exchange Preferred Shares For Common Stock [Member] Preferred Stock [Member]	Exchange Preferred Shares For Common Stock [Member] Additional Paid-in Capital [Member]	Exchange Preferred Shares For Common Stock [Member] Retained Earnings [Member]	Exchange Preferred Shares For Common Stock [Member]	Common Stock [Member]	Preferred Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Total
Balance (in shares) at Dec. 31, 2020						8,421,910	0
Balance at Dec. 31, 2020						$ 84	$ 0	$ 429,476	$ (502,527)	$ (72,967)
Net income (loss)						0	0		(44,567)	(44,567)
Stock-based compensation						$ 0	$ 0	946	0	946
Balance (in shares) at Dec. 31, 2021						8,421,910	0
Balance at Dec. 31, 2021						$ 84	$ 0	430,422	(547,094)	(116,588)
Net income (loss)						0	0	0	37,328	37,328
Stock-based compensation						$ 0	$ 0	3,296	0	3,296
Preferred Stock issued (in shares)						0	685,505
Preferred Stock issued						$ 0	$ 7	137,094	0	137,101
Preferred stock exchanged for common stock (in shares)	90,631,287
Preferred stock exchanged for common stock	$ 906		$ (899)	$ 0	$ 0
Preferred stock exchanged for common stock (in shares)		(685,505)
Preferred stock exchanged for common stock		$ (7)
Restricted stock issued net of cancellations (in shares)						1,648,233	0
Restricted stock issued net of cancellations						$ 17	$ 0	(17)	0	0
Balance (in shares) at Dec. 31, 2022						100,701,430	0
Balance at Dec. 31, 2022						$ 1,007	$ 0	$ 569,896	$ (509,766)	$ 61,137

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Operating Activities:
Net (loss) income	$ 37,328	$ (44,567)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Loss on sale of non-oil and gas assets	668	(29)
Loss on drilling rig	8,225	0
Gain on sale of oil and gas properties	(28,982)	0
Net loss on derivative contracts	0	33,022
Net cash settlements paid on derivative contracts	0	(3,197)
Depreciation, depletion and amortization	6,341	15,312
Amortization of deferred financing fees and issuance discount	0	8,781
Non-cash financing fees and warrant cancellation	0	194
Accretion of future site restoration	170	330
Loss on investments	4,409	0
Gain (loss) on debt extinguishment	6,645	0
Plugging cost	0	(342)
Non-cash interest	0	24,705
Non-cash hedge termination	(401)	9,943
Stock-based compensation	3,296	946
Changes in operating assets and liabilities:
Accounts receivable	8,586	(3,498)
Assets held for sale	3,019	0
Other assets	(3,297)	(8,851)
Accounts payable	(11,717)	3,151
Accrued expenses and other	(688)	(765)
Net cash provided by operating activities	20,312	32,419
Investing Activities
Capital expenditures, including purchase and development of properties	(1,544)	(887)
Investment	(19,500)	0
Proceeds from the sale of oil and gas properties	71,696	141
Proceeds from the sale of non-oil and gas assets	646	228
Net cash (used in) provided by investing activities	51,298	(518)
Financing Activities
Proceeds from PPP loan	0	1,332
Payments of long-term borrowings	(77,966)	(25,816)
Deferred financing fees	(802)	(158)
Net cash used in financing activities	(78,768)	(24,642)
Increase in cash and cash equivalents	(7,158)	7,259
Cash and cash equivalents at beginning of period	10,034	2,775
Cash and cash equivalents at end of period	2,876	10,034
Supplemental disclosure of cash flow information:
Interest paid	70	6,463
Income tax paid	0	0
Non-cash investing and financing activities
Non-cash issuance of stock	137,101	0
Change in asset retirement obligation cost and liabilities	0	204
Asset retirement obligations associated with dispositions	(1,837)	(2,845)
Debt Forgiveness	(6,645)	0
Change in capital expenditures included in accounts payable	(76)	5
Paycheck Protection Program, CARES Act [Member]
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Gain (loss) on debt extinguishment	(6,645)	(2,716)
Non-cash investing and financing activities
Debt Forgiveness	$ 6,645	$ 2,716

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Note 1 - Organization and Significant Accounting Policies

12 Months Ended

Dec. 31, 2022

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.

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 2021 and 2022, the drilling rig was idle. Accordingly, the cost of maintaining the rig was charged to the statement of operations. The drilling rig was sold in February 2023.

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, 2021 and 2022. 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 the 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, 2021 and 2022, our capitalized cost of oil and gas properties did not exceed the future net revenue from our estimated proved reserves.

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

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, 2021 and 2022, stock-based compensation was approximately $0.9 million and $3.3 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: 

	2021			2022
Beginning future site restoration obligation	$	7,360		$	4,708
New wells placed on production and other		1			-
Deletions related to property disposals		(2,845	)		(1,837	)
Deletions related to plugging costs		(342	)		-
Accretion expense and other		330			170
Revisions and other		204			-
Ending future site restoration obligation	$	4,708		$	3,041

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.

During 2021, four purchasers accounted for 83% of oil and gas revenues. During 2022, three purchasers accounted for 90% 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 $73.7 million for deferred tax assets at December 31, 2022.

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, 2022.

Adoption of New Accounting Standards 

None

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Note 2 - Revenue from Contracts with Customers

12 Months Ended

Dec. 31, 2022

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 are 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, 2021 and 2022. 

Disaggregation of Revenue

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

	Years Ended December 31,
	2021						2022
	Oil		Gas		NGL		Oil		Gas		NGL
Operating Region
Permian/Delaware Basin	$	32,666	$	4,474	$	2,181	$	39,617	$	6,642	$	3,456
Rocky Mountain (1)	$	28,562	$	4,182	$	6,771	$	-	$	-	$	-

(1)  All Rocky Mountain assets were sold  January 3, 2022.

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, 2021 and December 31, 2022, our receivables from contracts with customers were $12.3 million and $4.7 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, 2022, 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, 2022

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 was 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 did 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.

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, 2022

Notes to Financial Statements

Long-Term Debt [Text Block]

4. Long-Term Debt

The following is a description of the Company’s debt as of  December 31, 2021 and 2022:

	Years ended December 31,
	2021			2022
	(In thousands)
First Lien Credit Facility	$	71,400		$	-
Second Lien Credit Facility		134,907			-
Exit fee - Second Lien Credit Facility		10,000			-
Real estate lien note		2,515			-
		218,822			-
Less current maturities		(212,688	)		-
		6,134			-
Deferred financing fees and debt issuance cost - net		(3,929	)		-
Total long-term debt, net of deferred financing fees and debt issuance costs	$	2,205		$	-

Restructuring

Pursuant to the Exchange Agreement, dated as of January 3, 2022, between Abraxas and AGEF (the “Exchange Agreement”) and certain other agreements entered into by Abraxas on January 3, 2022, we effectuated a restructuring of our then-existing indebtedness through a multi-part interdependent deleveraging transaction consisting of: (i) an Asset Purchase and Sale Agreement  pursuant to which Abraxas sold to Lime Rock Resources V-A, L.P. certain oil, gas, and mineral properties in the Williston Basin region of North Dakota and other related assets belonging to the Company and its subsidiaries for $87.2 million in cash less customary closing adjustments, (ii) the pay down of the indebtedness and other obligations of Abraxas and its subsidiaries under the First Lien Credit Facility and (iii), a debt for equity exchange of the indebtedness and other obligations of Abraxas and its subsidiaries under the $100.0 million Second Lien Credit Facility (the “Exchange” and, together with the transactions referred to in clauses (i) and (ii), the “Restructuring”). AGEF was issued 685,505 shares of Series A Preferred Stock of the Company (the "Preferred Shares") in the Exchange, which entitled AGEF to approximately 85% of the voting power of the Company’s then outstanding capital stock.

The Restructuring also involved a change in a majority of the Board’s directors. Pursuant to the Exchange Agreement, immediately prior to the closing of the Restructuring, two former Board members resigned. Immediately after the consummation of the Restructuring, the existing Board members resolved to increase the size of the Board by one member from four to five directors and to appoint three employees of AGEF as members of the Board, one of whom became Chairman of the Board.

Real Estate Lien Note

We had a real estate lien note secured by a first lien deed of trust on the property and improvements. The note was paid in full in August 2022.

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Note 5 - Property and Equipment

12 Months Ended

Dec. 31, 2022

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		2021			2022
	Years		(In thousands)
Oil and gas properties (1)		-	$	1,165,707		$	1,122,670
Equipment and other		3-39		15,257			3,386
Drilling rig (1) (2)		15		24,080			-
				1,205,044			1,126,056
Accumulated depreciation, depletion, amortization and impairment				(1,099,075	)		(1,082,069	)
Net property and equipment			$	105,969		$	43,987

(1) Oil and gas properties are amortized utilizing the units of production method.

(2) The Company owned a 2000 HP drilling rig which was sold in February 2023. The drilling rig was impaired during 2022 resulting in a loss of $8,225.

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Note 6 - Stock-based Compensation and Option Plans

12 Months Ended

Dec. 31, 2022

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 1,683,639 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 2021 or 2022

The following table is a summary of the Company’s stock option activity for the two years ended December 31:

	Options			Weighted average		Weighted average		Intrinsic value
	(000s)			exercise price		remaining life		per share
Options outstanding December 31, 2020		196		$	49.69
Forfeited/Expired		(141	)		48.11
Options outstanding December 31, 2021		55		$	53.79
Forfeited/Expired		(55	)		53.79
Options outstanding December 31, 2022		-		$	-		-	$	-
Exercisable at end of year		-		$	-		-	$	-

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. 

The following table is a summary of the Company’s restricted stock activity for the two years ended December 31, 2022:

	Number of Shares			Weighted average grant date fair value
Unvested December 31, 2020		41		$	31.37
Granted		(24	)		33.23
Vested/Released		(3	)		32.07
Unvested December 31, 2021		14		$	27.97
Granted		1,650			1.25
Vested/Released		(1,664	)		2.10
Unvested December 31, 2022		-		$	-

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 vested over a three-year period upon the achievement of performance goals based on the Company’s Total Shareholder Return (“TSR”) as compared to a peer group of companies.   No shares were vested under this plan due to not achieving the performance goals.

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, 2020		44		$	33.73
Granted		-			-
Vested/Released		-			-
Forfeited		(16	)		45.73
Unvested December 31, 2021		28		$	26.80
Granted		-			-
Vested/Released		-			-
Forfeited		(28	)		26.80
Unvested December 31, 2022		-		$	-

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.

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. There were no awards under this plan in 2021 or 2022.

At December 31, 2022, the Company had approximately 418,000 shares reserved, under its Employee and Directors plans, for future issuance for conversion of its stock options, and incentive plans for the Company’s directors, employees and consultants.

All shares reserved under the Employee and Directors plans were cancelled in January 2023.

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Note 7 - Income Taxes

12 Months Ended

Dec. 31, 2022

Notes to Financial Statements

Income Tax Disclosure [Text Block]

7. Income Taxes

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,
	2021			2022
	(In thousands)
Deferred tax liabilities:
Hedge contracts	$	-		$	-
Other		2,855			-
Total deferred tax liabilities		2,855			-
Deferred tax assets:
US full cost pool	$	24,464		$	17,533
Depletion		470			452
U.S. net operating loss carryforward		96,120			50,103
Alternative minimum tax credit		-			-
Unrealized losses		100			956
Interest disallowed		5,781			4,367
Other		-			239
Total deferred tax assets		126,935			73,650
Valuation allowance for deferred tax assets		(124,080	)		(73,650	)
Net deferred tax assets		2,855			-
Net deferred tax	$	-		$	-

At December 31, 2022, the Company had, $20.0 million of pre-2018 NOLs for U.S. tax purposes and $186.7 million of post-2017 NOLs for U.S. tax purposes.  Our pre-2018 NOLs will expire in varying amounts 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).

On October 24, 2022, the Company became a consolidated subsidiary of Biglari Holdings Inc. for tax purposes.

Our NOL was reduced as a result of the ownership change that occurred in 2022. The use of our NOLs will be further limited if there is an additional “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. Given historical losses, uncertainties exist as to the future utilization of the NOL carryforwards, therefore, the Company has established a valuation allowance of $124.1  million at  December 31, 2021 and $73.7 million at December 31, 2022.

The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is:

	Years Ended December 31,
	2021			2022
	(in thousands)
Tax benefit at U.S. Statutory rates	$	9,359		$	(7,839	)
Change in deferred tax asset valuation allowance		(7,007	)		50,431
Alternative minimum tax expense		-			-
Adjustment to deferred tax assets		(3,421	)		(307	)
Permanent differences		368			692
Reduction to NOL due to ownership change limitation		-			(41,160	)
Return to provision estimated revision		-			(2,070	)
State income taxes, net of federal effect		688			253
Other		13			-
	$	-		$	-

As of   December 31, 2021 and 2022, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years 2015 through 2022 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 and 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, 2022

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, 2022, 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, 2022

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,
	2021			2022
Numerator:
Net (loss) income	$	(44,567	)	$	37,328
Denominator for basic earnings per share - weighted-average common shares outstanding		8,408			25,868
Effect of dilutive securities: Stock options, restricted shares and performance based shares		-			-
Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options, restricted shares and performance based shares		8,408			25,868
Net (loss) income per common share - basic	$	(5.30	)	$	1.44
Net (loss) income per common share - diluted	$	(5.30	)	$	1.44

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.   

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Note 10 - Benefit Plans

12 Months Ended

Dec. 31, 2022

Notes to Financial Statements

Compensation and Employee Benefit Plans [Text Block]

10. Benefit Plans

The Company had a defined contribution plan (401(k) plan) covering all eligible employees. For  2021, in accordance with the safe harbor provisions of the Plan, the Company contributed $125,276. The Company contributed $85,516 to the plan for 2022, and contributed an additional $29,541 in 2023 for 2022. 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 2021 was $19,500 for employees under the age of 50 and $26,000 for employees 50 years of age or older. For 2022 the employee contribution limit was $20,500 for employees under the age of 50 and $27,000 for employees 50 years of age or older. 

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Note 11 - Hedging Program and Derivatives

12 Months Ended

Dec. 31, 2022

Notes to Financial Statements

Derivative Instruments and Hedging Activities Disclosure [Text Block]

11. Hedging Program and Derivatives and Financial Instruments

As of December 31, 2022 the Company is not party to any hedge agreements. The liability as of December 31, 2021 relates to the December 2021 contract settlement paid in January 2022.

The following table illustrates the impact of derivative contracts on the Company’s balance sheet:

Fair Value Financial Instruments as of December 31, 2021
	Asset			Liability
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity price derivatives	Derivatives - current	$	-	Derivatives - current	$	442
		$	-		$	442

Fair Value of Investments as of December 31, 2022
	Asset
	Balance Sheet Location	Fair Value
Financial instruments	Investments - long term	$	15,091
		$	15,091

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Note 12 - Financial Instruments and Investment in Partnership

12 Months Ended

Dec. 31, 2022

Notes to Financial Statements

Fair Value Disclosures [Text Block]

12. Financial Instruments and Investment in Partnership.

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, 2021 and 2022, 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, 2021
Liabilities:
NYMEX fixed price derivative contracts	$	-	$	442	$	-	$	442
Total Liabilities	$	-	$	442	$	-	$	442

The Company’s derivative contracts for the year ended  December 31, 2021 consisted of a NYMEX-based fixed price commodity swap.  The NYMEX-based fixed price derivative contracts were 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.

During  November and December 2022, the Company invested $19,500 in the Lion Fund II, L.P. as a limited partner.  The Lion Fund II, L.P. is an investment partnership affiliated with Sardar Biglari, a director of Abraxas and Biglari Holdings Inc.

The fair value of the Company’s investment in the Lion Fund II, L.P. at, December 31, 2022, was $15,091 Fair value has been determined utilizing the net asset value as a practical expedient pursuant to US GAAP. 

A Limited Partner may withdraw all or any portion of its capital account attributable to a particular capital contribution as of the March 31 of the fifth year after the year in which such Limited Partner made such contribution, and every March 31 occurring every five years thereafter. 

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, 2022

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 rented a residence in North Dakota from a third party for living accommodations for certain field employees. Our real estate lease was 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. The North Dakota residential lease was assigned to a third-party on January 3, 2022. See Note 14  “Subsequent Events.”

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. 

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, 2021 and  December 31, 2022, the majority of which is included in lease operating expense, are as follows:

	For the Year Ended December 31,
	2021		2022
	(in thousands)
Operating lease cost	$	65	$	11
Short-term lease expense (1)		1,913		578
Total lease expense	$	1,978	$	589
Short-term lease costs (2)	$	-	$	-

(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,
	2021		2022
	(in thousands)
Operating lease Right of Use asset	$	173	$	1
Operating lease liability - current	$	40	$	1
Operating lease liabilities - long-term	$	110	$	-

Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows:

	For the Year Ended December 31,
	2021			2022
	(in thousands)
Weighted Average Remaining Lease Term (in years)		12.46			0.08
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)
2023		1
2024		-
2025		-
2026		-
2027		-
Thereafter		-
Total lease payments		1
Less imputed interest		-
Total lease liability	$	1

Supplemental cash flow information related to our operating leases is included in the table below:

	For the Year Ended December 31,
	2021		2022
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities	$	65	$	11
Right of Use assets added in exchange for lease obligations (since adoption)	$	-	$	-

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Note 14 - Restructuring

12 Months Ended

Dec. 31, 2022

Notes to Financial Statements

Restructuring, Impairment, and Other Activities Disclosure [Text Block]

14. Restructuring

Pursuant to the Exchange Agreement, dated as of January 3, 2022, between the Company and AG Energy Funding, LLC (“AGEF”) and certain other agreements entered into by the Company on January 3, 2022, the Company effectuated a restructuring of the Company’s  then-existing indebtedness through a multi-part interdependent deleveraging transaction consisting of: (i) an Asset Purchase and Sale Agreement pursuant to which the Company sold to Lime Rock Resources V-A, L.P. certain oil, gas, and mineral properties in the Williston Basin region of North Dakota and other related assets belonging to the Company and its subsidiaries for $87.2 million in cash ($73.3 million after customary closing adjustments), (the “Sale”), (ii) the pay down of the indebtedness and other obligations of the Company and its subsidiaries under the First Lien Credit Facility; and (iii), a debt for equity exchange of the indebtedness and other obligations of the Company  and its subsidiaries under the $100.0 million Second Lien Credit Facility, and all related loan and security documents (the “Exchange” and, together with the transactions referred to in clauses (i) and (ii), the “Restructuring”). 

AGEF was issued 685,505 shares of Series A Preferred Stock of the Company (the "Preferred Shares") in the Exchange.  The Series A Preferred Stock has the terms set forth in the Company’s filed Preferred Stock Certificate of Designation (the “Certificate).  The shares of Series A Preferred Stock vote together as a single class with the Company’s common stock, and each share of Series A Preferred Stock entitles the holder thereof to 69 votes. Accordingly, AGEF’s ownership of the Series A Preferred Stock entitled it to approximately 85% of the voting power of the Company’s then-outstanding capital stock.

On September 13, 2022, AGEF and Biglari Holdings Inc. ("Biglari Holdings") entered into a preferred stock purchase agreement (the "Preferred Purchase Agreement") and an assignment and assumption agreement pursuant to which AGEF agreed to sell and assign to Biglari Holdings (the "Sales and Assignment Agreement"), and Biglari Holdings agreed to purchase, acquire, and assume from AGEF, the Preferred Shares and all of AGEF’s rights, title, and interests in, and duties and obligations under, the Exchange Agreement. Following Biglari Holdings’ acquisition of the Preferred Shares, a change in control of the Company occurred. Biglari Holdings’ ownership of the Preferred Shares resulted in its beneficial ownership, both directly and indirectly, of the approximately 85% of the Company’s voting securities.

In connection with the transactions contemplated by the Preferred Purchase Agreement, the four directors of the Company appointed by AGEF resigned from the Board. Also, in accordance with the terms of the Preferred Purchase Agreement, on September 13, 2022, the Board voted to appoint Messrs. Sardar Biglari, Philip Cooley, and Bruce Lewis as members of the Board to fill three of the vacancies created by the resignations of the AGEF appointed directors. All three newly appointed members of the Board are affiliated with Biglari Holdings.

Subsequent to the Sale and Assignment, Biglari Holdings proposed an exchange of the Preferred Shares for shares of the Company’s common stock pursuant to which the Company would issue Biglari Holdings 90,631,287 shares of the Company’s common stock (the “Stock Consideration”) in exchange for the Preferred Shares (such transaction, the “Second Exchange”).

To issue the Stock Consideration to Biglari Holdings as contemplated by the Second Exchange, an amendment to  Articles of Incorporation, as amended, was needed to increase the number of shares of common stock authorized for issuance from 20,000,000 shares to 150,000,000 shares (the “Amendment”).

On September 23, 2022, the Board approved the Company’s entry into an exchange agreement with Biglari Holdings that defines the terms of the Second Exchange (the “Second Exchange Agreement”). The Company and Biglari Holdings entered into the Second Exchange Agreement on September 27, 2022, with the consummation of the Second Exchange subject to the approval by the Company’s stockholders of the Amendment and the acceptance of the Amendment by the Nevada Secretary of State.

On October 24, 2022, the Company’s stockholders approved the Amendment, and the Company caused the Amendment to be filed with the Nevada Secretary of State that same day. The Nevada Secretary of State accepted the Amendment on October 25, 2022, and on October 26, 2022, the Second Exchange Agreement was consummated by the following transactions: (i) the Company caused 90,631,287 shares of common stock to be registered in the name of Biglari Holdings with the Company’s transfer agent in book-entry form, and (ii) Biglari Holdings assigned and transferred  the Preferred Shares to the Company, constituting all of the Preferred Shares of the Company then outstanding, by delivering a Stock Power and Assignment to the Company. The Company cancelled the Series A Preferred Stock and the Preferred Stock Certificate of Designation, such that only common stock of the Company remains outstanding. The foregoing description of the Second Exchange and the Second Exchange Agreement is a summary only, does not purport to be complete, and is qualified in its entirety by reference to the complete text of the Second Exchange Agreement, which is filed as Exhibit 10.1 on Form 8-K filed on October 3, 2022, and is incorporated by reference herein. 

As a result of the Sale and Assignment and Second Exchange, the Company is a consolidated subsidiary of Biglari Holdings, and Biglari Holdings has the power to exert significant control over the Company by controlling both 90% of the voting power of the Company’s outstanding capital stock and a majority of the Company’s Board. 

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Note 15 - Subsequent Events

12 Months Ended

Dec. 31, 2022

Notes to Financial Statements

Subsequent Events [Text Block]

15.  Subsequent Events

On February 1, 2023, the Company filed Form 15 with the Securities and Exchange Commission. The purpose of this filing is to give notice of termination of registration under Section 12(g) of the Securities and Exchange Act of 1934, as amend (the "Exchange Act" and suspension of duty to file reports under Sections 13 and 15(d) of the  Exchange Act  The Form 15 does not become effective until 90 days after its filing (unless the SEC allows it to become effective earlier).

Robert L.G.Watson, the Company's President and Principal Executive Officer, resigned from his position effective March 1, 2023.

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2022

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, 2021 and 2022:

	Years Ended December 31,
	(in thousands)
	2021			2022
Proved oil and gas properties	$	1,165,707		$	1,122,670
Unproved properties		-			-
Total		1,165,707			1,122,670
Accumulated depreciation, depletion, amortization and impairment		(1,074,144	)		(1,078,865	)
Net capitalized costs	$	91,563		$	43,805

Cost incurred in oil and gas property acquisition and development activities were as follows for the years ended December 31, 2021 and 2022 (in thousands):

	2021		2022
Development costs	$	1,145	$	1,509
Exploration costs		-		-
Property acquisition costs		-		-
	$	1,145	$	1,509

Results of operations from oil and gas producing activities were as follows for the years ended December 31, 2021 and 2022:

	2021			2022
Revenues	$	78,836		$	49,715
Production costs		(24,137	)		(14,562	)
Depreciation, depletion and amortization		(13,495	)		(4,720	)
Accretion of future site restoration		(330	)		(170	)
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$	40,874		$	30,263
Depletion rate per barrel of oil equivalent	$	6.67		$	5.80

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 table presents the Company’s estimate of its net proved developed and undeveloped oil and gas reserves as of December 31, 2021 and 2022:

	Total
							Oil
	Oil		NGL		Gas		Equivalents
	(MBbl)		(MBbl)		(MMcf)		(Mboe)
Proved Developed Reserves:
December 31, 2021		6,883		2,914		30,158		14,823
December 31, 2022		3,300		1,508		18,847		7,949
Proved Undeveloped Reserves:
December 31, 2021		-		-		-		-
December 31, 2022		-		-		-		-

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, Netherland Sewell & Associates Inc., assisted by the engineering and operations departments of the Company as of   December 31, 2022 and by DeGolyer & MacNaughton, assisted by the engineering and operations departments of the Company, as of December 31, 2021. 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 2021, and 2022, 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 Netherland Sewell & Associates Inc. 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. Netherland Sewell & Associates Inc. 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 Netherland Sewell & Associates Inc. were developed utilizing studies performed by Netherland Sewell & Associates Inc. and assisted by the Engineering and Operations departments of Abraxas. Reserves are estimated by independent petroleum engineers.  The report of Netherland Sewell & Associates Inc. dated February 10, 2023, contains further discussions of the reserve estimates and evaluations prepared by Netherland Sewell & Associates Inc. as well as the qualifications of Netherland Sewell & Associates Inc's. technical personnel responsible for overseeing such estimates and evaluations is attached as Exhibit 99.1 to this report.

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 4, 2022, 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 was filed as Exhibit 99.2 to this report.

Estimates of proved reserves at  December 31, 2021 and 2022 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 43 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, 2021  and 2022 :

	Years Ended December 31,
	(in thousands)
	2021			2022
Future cash inflows	$	485,982		$	431,728
Future production costs		(222,309	)		(192,611	)
Future development costs		(5,623	)		(4,728	)
Future income tax expense		-			-
Future net cash flows		258,050			234,389
Discount	$	(104,775	)	$	(100,511	)
Standardized Measure of discounted future net cash relating to proved reserves	$	153,275		$	133,878

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2022

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.

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 2021 and 2022, the drilling rig was idle. Accordingly, the cost of maintaining the rig was charged to the statement of operations. The drilling rig was sold in February 2023.

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, 2021 and 2022. 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 the 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, 2021 and 2022, our capitalized cost of oil and gas properties did not exceed the future net revenue from our estimated proved reserves.

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

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, 2021 and 2022, stock-based compensation was approximately $0.9 million and $3.3 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: 

	2021			2022
Beginning future site restoration obligation	$	7,360		$	4,708
New wells placed on production and other		1			-
Deletions related to property disposals		(2,845	)		(1,837	)
Deletions related to plugging costs		(342	)		-
Accretion expense and other		330			170
Revisions and other		204			-
Ending future site restoration obligation	$	4,708		$	3,041

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.

During 2021, four purchasers accounted for 83% of oil and gas revenues. During 2022, three purchasers accounted for 90% 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 $73.7 million for deferred tax assets at December 31, 2022.

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, 2022.

New Accounting Pronouncements, Policy [Policy Text Block]

Adoption of New Accounting Standards 

None

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Note 1 - Organization and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2022

Notes Tables

Schedule of Change in Asset Retirement Obligation [Table Text Block]

	2021			2022
Beginning future site restoration obligation	$	7,360		$	4,708
New wells placed on production and other		1			-
Deletions related to property disposals		(2,845	)		(1,837	)
Deletions related to plugging costs		(342	)		-
Accretion expense and other		330			170
Revisions and other		204			-
Ending future site restoration obligation	$	4,708		$	3,041

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Note 2 - Revenue from Contracts with Customers (Tables)

12 Months Ended

Dec. 31, 2022

Notes Tables

Disaggregation of Revenue [Table Text Block]

	Years Ended December 31,
	2021						2022
	Oil		Gas		NGL		Oil		Gas		NGL
Operating Region
Permian/Delaware Basin	$	32,666	$	4,474	$	2,181	$	39,617	$	6,642	$	3,456
Rocky Mountain (1)	$	28,562	$	4,182	$	6,771	$	-	$	-	$	-

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Note 4 - Long-term Debt (Tables)

12 Months Ended

Dec. 31, 2022

Notes Tables

Schedule of Long-Term Debt Instruments [Table Text Block]

	Years ended December 31,
	2021			2022
	(In thousands)
First Lien Credit Facility	$	71,400		$	-
Second Lien Credit Facility		134,907			-
Exit fee - Second Lien Credit Facility		10,000			-
Real estate lien note		2,515			-
		218,822			-
Less current maturities		(212,688	)		-
		6,134			-
Deferred financing fees and debt issuance cost - net		(3,929	)		-
Total long-term debt, net of deferred financing fees and debt issuance costs	$	2,205		$	-

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Note 5 - Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2022

Notes Tables

Property, Plant and Equipment [Table Text Block]

	Estimated		December 31,
	Useful life		2021			2022
	Years		(In thousands)
Oil and gas properties (1)		-	$	1,165,707		$	1,122,670
Equipment and other		3-39		15,257			3,386
Drilling rig (1) (2)		15		24,080			-
				1,205,044			1,126,056
Accumulated depreciation, depletion, amortization and impairment				(1,099,075	)		(1,082,069	)
Net property and equipment			$	105,969		$	43,987

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Note 6 - Stock-based Compensation and Option Plans (Tables)

12 Months Ended

Dec. 31, 2022

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, 2020		196		$	49.69
Forfeited/Expired		(141	)		48.11
Options outstanding December 31, 2021		55		$	53.79
Forfeited/Expired		(55	)		53.79
Options outstanding December 31, 2022		-		$	-		-	$	-
Exercisable at end of year		-		$	-		-	$	-

Schedule of Nonvested Restricted Stock Units Activity [Table Text Block]

	Number of Shares			Weighted average grant date fair value
Unvested December 31, 2020		41		$	31.37
Granted		(24	)		33.23
Vested/Released		(3	)		32.07
Unvested December 31, 2021		14		$	27.97
Granted		1,650			1.25
Vested/Released		(1,664	)		2.10
Unvested December 31, 2022		-		$	-

Schedule of Nonvested Performance-Based Units Activity [Table Text Block]

	Number of Shares			Weighted average grant date fair value
Unvested December 31, 2020		44		$	33.73
Granted		-			-
Vested/Released		-			-
Forfeited		(16	)		45.73
Unvested December 31, 2021		28		$	26.80
Granted		-			-
Vested/Released		-			-
Forfeited		(28	)		26.80
Unvested December 31, 2022		-		$	-

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Note 7 - Income Taxes (Tables)

12 Months Ended

Dec. 31, 2022

Notes Tables

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

	As of December 31,
	2021			2022
	(In thousands)
Deferred tax liabilities:
Hedge contracts	$	-		$	-
Other		2,855			-
Total deferred tax liabilities		2,855			-
Deferred tax assets:
US full cost pool	$	24,464		$	17,533
Depletion		470			452
U.S. net operating loss carryforward		96,120			50,103
Alternative minimum tax credit		-			-
Unrealized losses		100			956
Interest disallowed		5,781			4,367
Other		-			239
Total deferred tax assets		126,935			73,650
Valuation allowance for deferred tax assets		(124,080	)		(73,650	)
Net deferred tax assets		2,855			-
Net deferred tax	$	-		$	-

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

	Years Ended December 31,
	2021			2022
	(in thousands)
Tax benefit at U.S. Statutory rates	$	9,359		$	(7,839	)
Change in deferred tax asset valuation allowance		(7,007	)		50,431
Alternative minimum tax expense		-			-
Adjustment to deferred tax assets		(3,421	)		(307	)
Permanent differences		368			692
Reduction to NOL due to ownership change limitation		-			(41,160	)
Return to provision estimated revision		-			(2,070	)
State income taxes, net of federal effect		688			253
Other		13			-
	$	-		$	-

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Note 9 - Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2022

Notes Tables

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

	Years Ended December 31,
	2021			2022
Numerator:
Net (loss) income	$	(44,567	)	$	37,328
Denominator for basic earnings per share - weighted-average common shares outstanding		8,408			25,868
Effect of dilutive securities: Stock options, restricted shares and performance based shares		-			-
Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options, restricted shares and performance based shares		8,408			25,868
Net (loss) income per common share - basic	$	(5.30	)	$	1.44
Net (loss) income per common share - diluted	$	(5.30	)	$	1.44

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Note 11 - Hedging Program and Derivatives (Tables)

12 Months Ended

Dec. 31, 2022

Notes Tables

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

Fair Value Financial Instruments as of December 31, 2021
	Asset			Liability
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity price derivatives	Derivatives - current	$	-	Derivatives - current	$	442
		$	-		$	442

Fair Value of Investments as of December 31, 2022
	Asset
	Balance Sheet Location	Fair Value
Financial instruments	Investments - long term	$	15,091
		$	15,091

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Note 12 - Financial Instruments and Investment in Partnership (Tables)

12 Months Ended

Dec. 31, 2022

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, 2021
Liabilities:
NYMEX fixed price derivative contracts	$	-	$	442	$	-	$	442
Total Liabilities	$	-	$	442	$	-	$	442

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Note 13 - Lease Accounting Standard (Tables)

12 Months Ended

Dec. 31, 2022

Notes Tables

Lease, Cost [Table Text Block]

	For the Year Ended December 31,
	2021		2022
	(in thousands)
Operating lease cost	$	65	$	11
Short-term lease expense (1)		1,913		578
Total lease expense	$	1,978	$	589
Short-term lease costs (2)	$	-	$	-

	For the Year Ended December 31,
	2021			2022
	(in thousands)
Weighted Average Remaining Lease Term (in years)		12.46			0.08
Weighted Average Discount Rate		6	%		6	%

	For the Year Ended December 31,
	2021		2022
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities	$	65	$	11
Right of Use assets added in exchange for lease obligations (since adoption)	$	-	$	-

Schedule of Operating Leased Assets [Table Text Block]

	For the Year Ended December 31,
	2021		2022
	(in thousands)
Operating lease Right of Use asset	$	173	$	1
Operating lease liability - current	$	40	$	1
Operating lease liabilities - long-term	$	110	$	-

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

	Operating Leases
	(in thousands)
2023		1
2024		-
2025		-
2026		-
2027		-
Thereafter		-
Total lease payments		1
Less imputed interest		-
Total lease liability	$	1

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2022

Notes Tables

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

	Years Ended December 31,
	(in thousands)
	2021			2022
Proved oil and gas properties	$	1,165,707		$	1,122,670
Unproved properties		-			-
Total		1,165,707			1,122,670
Accumulated depreciation, depletion, amortization and impairment		(1,074,144	)		(1,078,865	)
Net capitalized costs	$	91,563		$	43,805

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]

	2021		2022
Development costs	$	1,145	$	1,509
Exploration costs		-		-
Property acquisition costs		-		-
	$	1,145	$	1,509

Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]

	2021			2022
Revenues	$	78,836		$	49,715
Production costs		(24,137	)		(14,562	)
Depreciation, depletion and amortization		(13,495	)		(4,720	)
Accretion of future site restoration		(330	)		(170	)
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$	40,874		$	30,263
Depletion rate per barrel of oil equivalent	$	6.67		$	5.80

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]

	Total
							Oil
	Oil		NGL		Gas		Equivalents
	(MBbl)		(MBbl)		(MMcf)		(Mboe)
Proved Developed Reserves:
December 31, 2021		6,883		2,914		30,158		14,823
December 31, 2022		3,300		1,508		18,847		7,949
Proved Undeveloped Reserves:
December 31, 2021		-		-		-		-
December 31, 2022		-		-		-		-

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

	Years Ended December 31,
	(in thousands)
	2021			2022
Future cash inflows	$	485,982		$	431,728
Future production costs		(222,309	)		(192,611	)
Future development costs		(5,623	)		(4,728	)
Future income tax expense		-			-
Future net cash flows		258,050			234,389
Discount	$	(104,775	)	$	(100,511	)
Standardized Measure of discounted future net cash relating to proved reserves	$	153,275		$	133,878

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Note 1 - Organization and Significant Accounting Policies (Details Textual) $ in Thousands			12 Months Ended
	Dec. 31, 2022 USD ($)	Oct. 19, 2020	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Accounts Receivable, Allowance for Credit Loss, Ending Balance	$ 100		$ 100	$ 100
Number of Operating Segments			1
Discount Rate Used in Future Net Cash Flows Relating to Proved Oil and Gas Reserves	10.00%
Impairment of Oil and Gas Properties			$ 0
Share-Based Payment Arrangement, Noncash Expense, Total			3,296	946
Deferred Tax Assets, Valuation Allowance	$ 73,650		73,650	$ 124,080
Unrecognized Tax Benefits, Ending Balance	0		$ 0
Revenue Benchmark [Member] | Customer Concentration Risk [Member]
Entity Wide Revenue Number of Major Purchasers of Oil and Gas			3	4
Revenue Benchmark [Member] | Customer Concentration Risk [Member] | Four Purchasers [Member]
Concentration Risk, Percentage				83.00%
Revenue Benchmark [Member] | Customer Concentration Risk [Member] | Three Purchasers [Member]
Concentration Risk, Percentage			90.00%
Non-US [Member]
Long-Lived Assets	$ 0		$ 0
Reverse Stock Split [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio		20

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Note 1 - Organization and Significant Accounting Policies - Future Site Restoration Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Beginning future site restoration obligation	$ 4,708	$ 7,360
New wells placed on production and other	0	1
Deletions related to property disposals	(1,837)	(2,845)
Deletions related to plugging costs	0	(342)
Accretion expense and other	170	330
Revisions and other	0	204
Ending future site restoration obligation	$ 3,041	$ 4,708

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Note 2 - Revenue from Contracts with Customers (Details Textual) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Gas Balancing Asset (Liability)	$ 0	$ 0
Contract with Customer, Asset, after Allowance for Credit Loss, Total	$ 4,700	$ 12,300

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Note 2 - Revenue from Contracts with Customers - Disaggregation of Revenue (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Oil Revenues [Member]
Revenue		$ 39,617	$ 61,228
Gas Revenues [Member]
Revenue		6,642	8,656
Natural Gas Liquids Revenues [Member]
Revenue		3,456	8,952
Permian / Delaware Basin [Member] | Oil Revenues [Member]
Revenue		39,617	32,666
Permian / Delaware Basin [Member] | Gas Revenues [Member]
Revenue		6,642	4,474
Permian / Delaware Basin [Member] | Natural Gas Liquids Revenues [Member]
Revenue		3,456	2,181
Rocky Mountain [Member] | Oil Revenues [Member]
Revenue	[1]	0	28,562
Rocky Mountain [Member] | Gas Revenues [Member]
Revenue	[1]	0	4,182
Rocky Mountain [Member] | Natural Gas Liquids Revenues [Member]
Revenue	[1]	$ 0	$ 6,771

[1] All Rocky Mountain assest sold January 3, 2022.

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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 ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2022 $ / shares shares	Oct. 23, 2022 shares	Dec. 31, 2021 $ / 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)				150,000,000	20,000,000	150,000,000
Common Stock, Shares, Outstanding, Ending Balance (in shares)				100,701,430		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) $ in Millions	Jan. 03, 2022 USD ($) shares
Series A Preferred Stock [Member]
Maximum Aggregate Proceeds Received Allowed, Tier One Preference Amount	$ 100.0
Stock Issued During Period, Shares, New Issues (in shares) | shares	685,505
Preferred Stock, Voting Power, Percent	85.00%
Lime Rock Resources V-A, L.P. [Member]
Proceeds from Sale of Property, Plant, and Equipment, Total	$ 87.2

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Note 4 - Long-term Debt - Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Long-term debt	$ 0	$ 218,822
Less current maturities	0	(212,688)
Long-term Debt, Noncurrent, Gross	0	6,134
Deferred financing fees and debt issuance cost - net	0	(3,929)
Total long-term debt, net of deferred financing fees and debt issuance costs	0	2,205
Line of Credit [Member] | First Lien Credit Facility [Member]
Long-term debt	0	71,400
Line of Credit [Member] | Second Lien Credit Facility [Member]
Long-term debt	0	134,907
Exit fee - Second Lien Credit Facility	0	10,000
Mortgages [Member]
Long-term debt	$ 0	$ 2,515

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Note 5 - Property and Equipment (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Loss on Disposal of Drilling Rig	$ 8,225	$ 0

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Note 5 - Property and Equipment - Property and Equipment (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Oil and gas properties (1)		$ 1,126,056	$ 1,205,044
Accumulated depreciation, depletion, amortization and impairment		(1,082,069)	(1,099,075)
Net property and equipment		43,987	105,969
Oil and Gas Properties [Member]
Oil and gas properties (1)	[1]	1,122,670	1,165,707
Equipment and Other [Member]
Oil and gas properties (1)		$ 3,386	15,257
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)	[1],[2]	$ 0	$ 24,080
Estimated Useful Life (Year)	[1],[2]	15 years

[1] Oil and gas properties are amortized utilizing the units of production method.

[2] The Company owned a 2000 HP drilling rig which was sold in February 2023. The drilling rig was impaired during 2022 resulting in a loss of $8.2 million.

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Note 6 - Stock-based Compensation and Option Plans (Details Textual) - USD ($)		12 Months Ended
	Apr. 01, 2018	Dec. 31, 2022	Dec. 31, 2021
Common Stock, Capital Shares Reserved for Future Issuance (in shares)		418,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross (in shares)		0	0
Directors Plan 2005 [Member]
Common Stock, Capital Shares Reserved for Future Issuance (in shares)		70,000,000
Share-Based Payment Arrangement, Option [Member]
Common Stock, Capital Shares Reserved for Future Issuance (in shares)		1,683,639
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period (Year)		10 years
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period (Year)	3 years
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Vested in Period (in shares)		(0)	(0)
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Target Payout Rate		100.00%
Restricted Stock [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Vested in Period (in shares)		1,664	3
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

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Note 6 - Stock-based Compensation and Option Plans - Stock Option Activity (Details) - Share-Based Payment Arrangement, Option [Member] - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Balance (in shares)	55	196
Balance, weighted average exercise price (in dollars per share)	$ 53.79	$ 49.69
Forfeited/Expired (in shares)	(55)	(141)
Forfeited/Expired, weighted average exercise price (in dollars per share)	$ 53.79	$ 48.11
Balance (in shares)	0	55
Balance, weighted average exercise price (in dollars per share)	$ 0	$ 53.79
Options outstanding, intrinsic value per share (in dollars per share)	$ 0
Exercisable at end of year (in shares)	0
Exercisable, weighted average exercise price (in dollars per share)	$ 0
Exercisable, intrinsic value per share (in dollars per share)	$ 0

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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, 2022	Dec. 31, 2021
Unvested (in shares)	14	41
Unvested, weighted average grant date fair value (in dollars per share)	$ 27.97	$ 31.37
Granted (in shares)	1,650	24
Granted, weighted average grant date fair value (in dollars per share)	$ 1.25	$ 33.23
Vested/Released (in shares)	(1,664)	(3)
Vested/Released, weighted average grant date fair value (in dollars per share)	$ 2.10	$ 32.07
Unvested (in shares)	0	14
Unvested, weighted average grant date fair value (in dollars per share)	$ 0	$ 27.97

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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, 2022	Dec. 31, 2021
Unvested (in shares)	28	44
Unvested, weighted average grant date fair value (in dollars per share)	$ 26.80	$ 33.73
Granted (in shares)	0	0
Granted, weighted average grant date fair value (in dollars per share)	$ 0	$ 0
Vested/Released (in shares)	0	0
Vested/Released, weighted average grant date fair value (in dollars per share)	$ 0	$ 0
Forfeited (in shares)	(28)	(16)
Forfeited, weighted average grant date fair value (in dollars per share)	$ 26.80	$ 45.73
Unvested (in shares)	0	28
Unvested, weighted average grant date fair value (in dollars per share)	$ 0	$ 26.80

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Note 7 - Income Taxes (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Deferred Tax Assets, Valuation Allowance	$ 73,650	$ 124,080
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued, Total	$ 0	$ 0
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%
Pre 2018 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards	$ 20,000
Post 2018 [Member] | Domestic Tax Authority [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards	$ 186,700
Latest Tax Year [Member]
Operating Loss Carryforwards, Expiration Date		Dec. 31, 2037

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Note 7 - Income Taxes - Deferred Tax Liabilities and Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Hedge contracts	$ 0	$ 0
Other	0	2,855
Total deferred tax liabilities	0	2,855
US full cost pool	17,533	24,464
Depletion	452	470
U.S. net operating loss carryforward	50,103	96,120
Alternative minimum tax credit	0	0
Unrealized losses	956	100
Interest disallowed	4,367	5,781
Other	239	0
Total deferred tax assets	73,650	126,935
Valuation allowance for deferred tax assets	(73,650)	(124,080)
Net deferred tax assets	0	2,855
Net deferred tax	$ 0	$ 0

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Note 7 - Income Taxes - Reconciliation of Income Tax (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Tax benefit at U.S. Statutory rates	$ (7,839)	$ 9,359
Change in deferred tax asset valuation allowance	50,431	(7,007)
Alternative minimum tax expense	0	0
Adjustment to deferred tax assets	(307)	(3,421)
Permanent differences	692	368
Reduction to NOL due to ownership change limitation	(41,160)	0
Return to provision estimated revision	(2,070)	0
State income taxes, net of federal effect	253	688
Other	$ 0	$ 13

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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	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Net income (loss)	$ 37,328	$ (44,567)
Basic (in shares)	25,868	8,408
Effect of dilutive securities: Stock options, restricted shares and performance based shares (in shares)	0	0
Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options, restricted shares and performance based shares (in shares)	25,868	8,408
Net (loss) income per common share - basic (in dollars per share)	$ 1.44	$ (5.30)
Net (loss) income per common share - diluted (in dollars per share)	$ 1.44	$ (5.30)

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Note 10 - Benefit Plans (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Deferred Compensation Arrangement with Individual, Contributions by Employer		$ 85,516	$ 125,276
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		$ 20,500	19,500
Defined Contribution Plan Employee Contribution Limit 50 Years of Age or Older		$ 27,000	$ 26,000
Forecast [Member]
Deferred Compensation Arrangement with Individual, Contributions by Employer	$ 29,541

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Note 11 - Hedging Program and Derivatives - Impact of Derivative Contracts on Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Derivative asset, current		$ 0
Derivative liability, current	$ 0	442
Derivative asset, current		0
Derivative liability, current	0	442
Commodity Contract [Member] | Financial Instruments Long Term [Member]
Derivative asset	$ 15,091
Commodity Contract [Member] | Derivative Assets Current [Member]
Derivative asset, current		0
Derivative asset, current		0
Commodity Contract [Member] | Derivative Liabilities Current [Member]
Derivative liability, current		442
Derivative liability, current		$ 442

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Note 12 - Financial Instruments and Investment in Partnership (Details Textual) - USD ($) $ in Thousands	2 Months Ended	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2022	Dec. 31, 2021
Payments to Acquire Investments, Total		$ 19,500	$ (0)
Lion Fund II, L.P. [Member]
Payments to Acquire Investments, Total	$ 19,500
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	$ 15,091	$ 15,091

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Note 12 - Financial Instruments - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - Fair Value, Recurring [Member] $ in Thousands	Dec. 31, 2021 USD ($)
Derivative liabilities	$ 442
Fixed Price Derivative Contracts [Member]
Derivative assets	442
Fair Value, Inputs, Level 1 [Member]
Derivative liabilities	0
Fair Value, Inputs, Level 1 [Member] | Fixed Price Derivative Contracts [Member]
Derivative assets	0
Fair Value, Inputs, Level 2 [Member]
Derivative liabilities	442
Fair Value, Inputs, Level 2 [Member] | Fixed Price Derivative Contracts [Member]
Derivative assets	442
Fair Value, Inputs, Level 3 [Member]
Derivative liabilities	0
Fair Value, Inputs, Level 3 [Member] | Fixed Price Derivative Contracts [Member]
Derivative assets	$ 0

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Note 13 - Lease Accounting Standard (Details Textual)	Dec. 31, 2022
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, 2022	Dec. 31, 2021
Operating lease cost		$ 11	$ 65
Short-term lease expense	[1]	578	1,913
Total lease expense		$ 589	$ 1,978
Weighted Average Remaining Lease Term (Year)		29 days	12 years 5 months 15 days
Weighted Average Discount Rate		6.00%	6.00%
Cash paid for amounts included in the measurement of lease liabilities		$ 11	$ 65
Right of Use assets added in exchange for lease obligations (since adoption)		0	0
Drilling Rig [Member]
Short-term lease expense	[2]	$ 0	$ 0

[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, 2022	Dec. 31, 2021
Operating lease Right of Use asset	$ 1	$ 173
Operating lease liability - current	1	40
Operating lease liabilities - long-term	$ 0	$ 110

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Note 13 - Lease Accounting Standard - Lease Liabilities Maturity (Details) $ in Thousands	Dec. 31, 2022 USD ($)
2023	$ 1
2024	0
2025	0
2026	0
2027	0
Thereafter	0
Total lease payments	1
Less imputed interest	0
Total lease liability	$ 1

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Note 14 - Restructuring (Details Textual) - USD ($) $ in Millions	Oct. 24, 2022	Jan. 03, 2022	Dec. 31, 2022	Oct. 23, 2022	Dec. 31, 2021
Common Stock, Shares Authorized (in shares)			150,000,000	20,000,000	150,000,000
Series A Preferred Stock [Member]
Maximum Aggregate Proceeds Received Allowed, Tier One Preference Amount		$ 100.0
Stock Issued During Period, Shares, New Issues (in shares)		685,505
Number of Votes Each Share Entitled		69
Preferred Stock, Voting Power, Percent		85.00%
Lime Rock Resources V-A, L.P. [Member]
Proceeds from Sale of Property, Plant, and Equipment, Total		$ 87.2
Proceeds from Sale of Property Plant and Equipment, after Customary Closing Adjustments		$ 73.3
Biglari Holdings [Member]
Capital Stock, Voting Power, Percent	90.00%
Biglari Holdings [Member] | Second Exchange Agreement [Member]
Stock Issuable During Period, Shares, Conversion of Convertible Securities (in shares)	90,631,287

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Proved oil and gas properties	$ 1,122,670	$ 1,165,707
Unproved properties	0	0
Total	1,122,670	1,165,707
Accumulated depreciation, depletion, amortization and impairment	(1,078,865)	(1,074,144)
Net capitalized costs	$ 43,805	$ 91,563

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Cost Incurred (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Development costs	$ 1,509	$ 1,145
Exploration costs	0	0
Property acquisition costs	0	0
Costs Incurred, Acquisition of Oil and Gas Properties, Total	$ 1,509	$ 1,145

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Results of Operations (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) $ / bbl	Dec. 31, 2021 USD ($) $ / bbl
Revenues	$ 49,715	$ 78,836
Production costs	(14,562)	(24,137)
Depreciation, depletion and amortization	(4,720)	(13,495)
Accretion of future site restoration	(170)	(330)
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$ 30,263	$ 40,874
Depletion rate per barrel of oil equivalent (in USD per Barrel of Oil) | $ / bbl	5.80	6.67

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Proved Developed and Undeveloped Reserves (Details) - bbl bbl in Thousands	Dec. 31, 2022	Dec. 31, 2021
Oil [Member]
Proved developed reserves (Barrel of Oil)	3,300	6,883
Proved undeveloped reserves (Barrel of Oil)	0	0
Natural Gas Liquids [Member]
Proved developed reserves (Barrel of Oil)	1,508	2,914
Proved undeveloped reserves (Barrel of Oil)	0	0
Natural Gas [Member]
Proved developed reserves (Barrel of Oil)	18,847	30,158
Proved undeveloped reserves (Barrel of Oil)	0	0
Oil Equivalents [Member]
Proved developed reserves (Barrel of Oil)	7,949	14,823
Proved undeveloped reserves (Barrel of Oil)	0	0

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Note 16 - Supplemental Oil and Gas Disclosures (Unaudited) - Future Net Cash Inflows (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Future cash inflows	$ 431,728	$ 485,982
Future production costs	(192,611)	(222,309)
Future development costs	(4,728)	(5,623)
Future income tax expense	0	0
Future net cash flows	234,389	258,050
Discount	(100,511)	(104,775)
Standardized Measure of discounted future net cash relating to proved reserves	$ 133,878	$ 153,275