EDGAR 10-K Filing

Company CIK: 867665
Filing Year: 2023
Filename: 867665_10-K_2023_0001437749-23-010447.json

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ITEM 1. BUSINESS
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”).
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.
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:
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the location of wells;
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the method of drilling and casing wells;
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the flaring of gas;
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the method of completing and fracture stimulating wells;
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the surface use and restoration of properties upon which wells are drilled;
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the plugging and abandoning of wells; and
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the notice to surface owners and other third parties.
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:
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require the acquisition of a permit or other authorization before construction or drilling commences;
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impose design, construction and permitting requirements on facilities in conjunction with oil and gas operations, including the construction of pollution control devices;
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require protective measures to prevent certain fluids from coming into contact with ground water;
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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;
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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;
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require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells;
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require disclosure of chemicals injected into wells in conjunction with hydraulic fracturing operations;
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restrict injection of liquids into subsurface strata that may contaminate groundwater or increase seismic activity;
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restrict the availability of water necessary for hydraulic fracturing operations;
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impose substantial penalties for violations of environmental rules or pollution resulting from our operations;
• curtail production in association with permit limits; and
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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.
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
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:
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the level of demand;
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domestic and global supplies of oil, NGL and gas;
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the price and quantity of imported and exported oil, NGL and gas;
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the actions of other oil exporting nations;
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weather conditions and changes in weather patterns;
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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;
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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;
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the price and availability of, and demand for, competing energy sources, including alternative energy sources;
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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;
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the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others, and;
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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.
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:
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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;
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abnormally pressured formations;
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mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
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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;
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fires and explosions;
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personal injuries and death;
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regulatory investigations and penalties; and
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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.
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:
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changes in foreign and domestic supply and demand for oil and gas;
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political stability and economic conditions in oil producing countries, particularly in the Middle East, including Saudi Arabia and Russia;
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weather conditions;
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global or national health concerns, including the outbreak of a pandemic or contagious disease;
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price and level of foreign imports;
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terrorist activity;
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availability of pipeline and other secondary capacity;
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general economic conditions;
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domestic and foreign governmental regulation; and
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the price and availability of alternative fuel sources.
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:
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supply of and demand for our oil and gas;
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actual prices we receive for our oil and gas;
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our actual operating costs;
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the amount and timing of our capital expenditures;
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the amount and timing of our actual production; and
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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.
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.
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;
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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES
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)
2,877
1,652
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:
Permian/Delaware Basin
-
-
-
-
Total
-
-
-
-
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
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.
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,
(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
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,
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.
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,
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.

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ITEM 3. LEGAL PROCEEDINGS
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.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
Part II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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.

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ITEM 6. SELECTED FINANCIAL DATA

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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.
Results of Operations
Year Ended December 31,
(in thousands)
Operating revenue (1):
Oil sales
$ 61,228
$ 39,617
Gas sales
8,656
6,642
NGL sales
8,952
3,456
Other income
Total revenues
$ 78,858
$ 49,737
Operating income
$ 30,484
$ 15,677
Oil sales (MBbls)
Gas sales (MMcf)
3,432
1,569
NGL sales (MBbls)
Oil equivalents (MBoe)
2,023
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.
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.
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,
(in thousands)
Expenditure category:
Exploration/Development
$ 1,145
$ 1,509
Acquisitions
-
-
Facilities and other
$ 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,
(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.
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
$
$
$ -
$ -
$ -
Total
$
$
$ -
$ -
$ -
___________________________
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,
(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
$ -
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.
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.
Recently Issued Accounting Standards
None

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None

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ITEM 9A. CONTROLS AND PROCEDURES
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.
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.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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....................................................................................
Vice President - Land
Clare E. Villarreal.........................................................................
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
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.
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)
374,958
-
-
-
-
13,675
388,633
381,691
-
-
-
-
13,150
394,841
Steven P. Harris
Vice President-Chief Financial Officer (9)
239,904
-
-
-
-
3,000
242,904
228,119
-
-
-
-
3,000
231,119
Peter A. Bommer
Vice President-Engineering
252,996
-
-
-
-
11,956
264,952
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.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END
There were no outstanding equity awards at December 31, 2022 for our named executive officers.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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.
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.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
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)
Consolidated Balance Sheets at December 31, 2021 and 2022
Consolidated Statements of Operations for the years ended December 31, 2021 and 2022
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2021 and 2022
Consolidated Statements of Cash Flows for the years ended December 31, 2021 and 2022
Notes to Consolidated Financial Statements
(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).
*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).
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
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
*
Management Compensatory Plan or Agreement.