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

All share and per share data has been retroactively adjusted to reflect the 1-for-20 reverse stock split effective October 19, 2020, as described in Note 2 to our consolidated financial statements.

Forward-Looking Information

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

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

GLOSSARY OF TERMS

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

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

Terms used to describe quantities of oil and gas:

“Bbl” – barrel or barrels.

“Bcf” – billion cubic feet of gas.

“Bcfe” – billion cubic feet of gas equivalent.

“Boe” – barrels of oil equivalent.

“Boed or Boepd” – barrels of oil equivalent per day.

“MBbl” – thousand barrels.

“MBoe” – thousand barrels of oil equivalent.

“Mcf” – thousand cubic feet of gas.

“Mcfe” – thousand cubic feet of gas equivalent.

“MMBbl” – million barrels.

“MMBoe” – million barrels of oil equivalent.

“MMBtu” – million British Thermal Units of gas.

“MMcf” – million cubic feet of gas.

“MMcfe” – million cubic feet of gas equivalent.

“NGL” – natural gas liquids measured in barrels.

 Terms used to describe our interests in wells and acreage:

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

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

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

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

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

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

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

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

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

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

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

“Developed oil and gas reserves*” Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)    Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)   Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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

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

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

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

“PV-10” means estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation, calculated in accordance with guidelines promulgated by the Securities and Exchange Commission (“SEC”). PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes.

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

“Undeveloped oil and gas reserves*” Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

* This definition is an abbreviated version of the complete definition set forth in Rule 4-10(a) of Regulation S-X. 

Part I

FINANCIAL STATEMENTS

Item 1. Financial Statements

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

All share and per share data has been retroactively adjusted to reflect the 1-for-20 reverse stock split effective October 19, 2020, as described in Note 2 to our condensed consolidated financial statements. 

See accompanying notes to condensed consolidated financial statements (unaudited).

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)

(in thousands, except share and per share data)

See accompanying notes to condensed consolidated financial statements (unaudited).

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands except per share data)

See accompanying notes to condensed consolidated financial statements (unaudited).

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY

(Unaudited)

(in thousands, except share data)

See accompanying notes to condensed consolidated financial statements (unaudited).

See accompanying notes to condensed consolidated financial statements (unaudited).

ABRAXAS PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(tabular amounts in thousands, except per share data)

1. Basis of Presentation

The accounting policies we follow as of January 1, 20212022 are set forth in the notes to our audited consolidated financial statements in the Annual Report on Form 10-K for the year ended December 31, 20202021 filed with the SEC on May 6,March 31, 20212022.  The accompanying interim condensed consolidated financial statements have not been audited by our independent registered public accountants. In the opinion of management, these statements reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. Although management believes the unaudited interim related disclosures in these condensed consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America  (“GAAP”)  have been condensed or omitted pursuant to the rules and regulations of the SEC. The results of operations for the three and ninemonth periodsperiod ended September 30, 2021March 31, 2022  and the statement of cash flows for the ninethree months ended September 30, 2021March 31, 2022, are not necessarily indicative of the results to be expected for the full year. The condensed consolidated financial statements included herein should be read in conjunction with the consolidated audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 20202021.

COVID-19

In the first quarter of 2020, a new strain of coronavirus (“COVID-19”) emerged, creating a global health emergency that has been classified by the World Health Organization as a pandemic. As a result of the COVID-19 pandemic, consumer demand for both oil and gas decreased as a direct result of travel restrictions placed by governments in an effort to curtail the spread of COVID-19 and its variant strains. In addition, in March 2020, members of Organization of Petroleum Exporting Countries (“OPEC”) failed to agree on production levels, which caused an increased supply of oil and gas and led to a substantial decrease in oil prices and an increasingly volatile market. OPEC agreed to cut global petroleum output but did not go far enough to offset the impact of COVID-19 on demand. As a result of this decrease in demand and increase in supply, the price of oil and gas decreased, which affected our liquidity. Since that time, demand and the price of oil and gas have increased, but uncertainty related to the pandemic caused by COVID-19 and its variant strains persists.  

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

Going Concern

Our present level of indebtedness and the recent commodity price environment present challenges to our ability to comply with certain covenants in our credit facilities, and under applicable auditing standards, the independent accountants' opinion on our  financial statements for the year ended December 31, 2020 contains an explanatory paragraph regarding the Company’s  ability to continue as a “going concern.”    At December 31, 2020, we had a total of $95.0  million outstanding under our First Lien Credit Facility, $112.7 million under our Second Lien Credit Facility, and total indebtedness of  $220.5 million including a $10.0 million exit fee. As of  September 30, 2021, we had a total of  $81.7  million outstanding under our First Lien Credit Facility, $137.1 million under our Second Lien Credit Facility, including a  $10.0 million exit fee, and total indebtedness of  $221.4  million. Additionally, we have a liability of approximately $9.2 million related to the termination of our hedging agreements. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements.

Specifically, with regard to our credit agreements, we did not satisfy the first lien debt to consolidated EBITDAX ratio covenant under our First Lien Credit Facility as of the December 31, 2020 measurement date and such failure represented an event of default under our First Lien Credit Facility. In addition,  it was anticipated that we would not maintain compliance with the Second Lien Credit Facility total leverage ratio covenant or the minimum asset coverage ratio (as defined in Note 5) both of which were to be  first tested as of September 30, 2021, for the required twelve month period and, accordingly, the audit report prepared by our auditors with respect to the financial statements in our Form 10-K for the year ended December 31, 2020 included an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern”.  The inability to maintain compliance with certain covenants of our Second Lien Credit Facility represents an additional default under our First Lien Credit Facility as of the end of any such future fiscal quarters. The consolidated financial statements do not include any adjustments that might result from the outcome of the “going concern”  uncertainty.

The existing defaults at March 31, 2021 were subject to forbearance agreements with our lenders that expired on May 6, 2021. If the Company’s  lenders accelerate the payment of amounts outstanding under its credit facilities, the Company does not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so. The Company could attempt to obtain additional sources of capital from asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination thereof. However, the Company cannot provide any assurances that it will be successful in obtaining capital from such transactions on acceptable terms, or at all. 

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

The Company has continued its previously announced investigation of strategic alternatives and is in discussions with its creditors in an effort to restructure its balance sheet. Any negotiated transaction with its lenders would likely include a sale of a significant block of assets, the proceeds from which would be applied to reduce debt, the exchange of a significant amount of equity interests in the Company for outstanding indebtedness, and/or other possible negotiated transactions, which in the aggregate could eliminate or substantially reduce the outstanding indebtedness under  its First Lien Credit facility and Second Lien Credit Facility and result in significant dilution of existing stockholder interests and reduction or potentially elimination of value for existing stockholders.  Any such transaction could involve a proceeding under the U.S. Bankruptcy Code.  No assurance can be provided that any such potential transactions can be successfully concluded, in which event the Company’s lenders could commence foreclosure proceedings seeking to liquidate Company assets to repay the outstanding indebtedness.  In any such foreclosure proceedings, it is unlikely that stockholders would recover more than a de minimis amount for their stock, and the stock could become worthless.

In April 2021, we received notice that certain of our hedging agreements were being terminated as a result of events of default under the First Lien Credit Facility, and we voluntarily terminated most of our other  hedging arrangements. As a result of the settlement of the terminated hedges, we have outstanding obligations of $9.2 million. These obligations were added to the outstanding balance under our First Lien Credit Facility and will accrue interest at the default interest rate, currently 8.75%,  until repaid. Our remaining  hedging agreement may also be terminated as a result of such events of default. The settlement of terminated hedging agreements may result in losses and limit our ability to reduce exposure to adverse fluctuations in oil and gas prices. See Note 10 “Events of Default” for current information regarding non-compliance with certain covenants.

Consolidation Principles

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

Rig Accounting

In accordance with SEC Regulation S-X, no income is recognized in connection with contractual drilling services performed in connection with properties in which we or our affiliates hold an ownership, or other economic interest. Any income not recognized as a result of this limitation is credited to the full cost pool and recognized through lower amortization as reserves are produced.

Use of Estimates

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Stock-Based Compensation, Option Plans and Warrants

Stock Options

We currently utilize a standard option-pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors.

The following table summarizes our stock option activity for the ninethree months ended September 30, 2021March 31, 2022, (in thousands):

Restricted Stock Awards

Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the recipient of the award terminates employment with us prior to the lapse of the restrictions. The fair value of such stock was determined using the closing price on the grant date and compensation expense is recorded over the applicable vesting periods.

The following table summarizes our restricted stock activity for the ninethree months ended September 30, 2021March 31, 2022: 

Performance Based Restricted Stock

We issue performance-based shares of restricted stock to certain officers and employees under the Abraxas Petroleum Corporation Amended and Restated 2005 Employee Long-Term Equity Incentive Plan. The shares will vest in three years from the grant date upon the achievement of performance goals based on our Total Shareholder Return (“TSR”) as compared to a peer group of companies. The number of shares which would vest depends upon the rank of our TSR as compared to the peer group at the end of the three-year vesting period and can range from zero0 percent of the initial grant up to 200% of the initial grant.

The table below provides a summary of Performance Based Restricted Stock as of the date indicated:

Compensation expense associated with the performance based restricted stock is based on the grant date fair value of a single share as determined using a Monte Carlo Simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the performance based restricted stock awards with shares of our common stock, the awards are accounted for as equity awards and the expense is calculated on the grant date assuming a 100% target payout and amortized over the life of the awards.

The following table summarizes stock-based compensation from the various forms of compensation utilized by the Company (in thousands). as of the dates indicated.

As of September 30, 2021March 31, 2022, substantially all expense related to stock based compensation has been amortized. Options are fully amortized while restricted stock and performance shares have approximately $0.2 million and $0.1 million, respectively, that will be amortized over the remainder of 2021 through April 2022.

Warrants for Common Stock

As of September 30, 2021, outstanding warrants to purchase shares of common stock were as follows:

In connection with the amended Second Lien Credit Agreement, on August 11, 2020, the Company issued a warrant to the lender to purchase a total of 33,445,792 shares of common stock at an exercise price of $0.01 per share. As a result of the  October 19, 2020 reverse stock split of the Company’s  authorized, issued and outstanding shares of common stock at a ratio of 1-for-20, the warrant was adjusted to provide that the lender may purchase a total of 1,672,290 shares of common stock at an exercise price of $0.20 per share.  The warrant is  exercisable immediately, in whole or in part, at any time on or before five years from the issuance date. The fair value of the warrant was recorded as debt issuance costs, presented in the consolidated balance sheets as a deduction from the carrying amount of the note payable, and is being amortized over the loan term. 

Oil and Gas Properties

We follow the full cost method of accounting for oil and gas properties.  Under this method, all direct costs and certain indirect costs associated with the acquisition of properties and successful and unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves.  Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Costs in excess of the present value of estimated net revenue from proved reserves discounted at 10% are charged to proved property impairment expense.  No gain or loss is recognized upon sale or disposition of oil and gas properties for full cost accounting companies with proceeds accounted for as an adjustment of capitalized cost. An exception to this rule occurs when the adjustment to the full cost pool results in a significant alteration of the relationship between capitalized cost and proved reserves. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented.   At September 30, 2020, the net capital cost of oil and gas properties exceeded the cost ceiling of our estimated proved reserves  resulting in an impairment of $54.6 million and $136.1  million for the three and nine months ended September 30, 2020, respectively.  At September 30, 2021March 31, 2022, the net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves.

Restoration, Removal and Environmental Liabilities

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

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

We account for future site restoration obligations based on the guidance of ASC 410 which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense in the accompanying condensed consolidated financial statements.

The following table summarizes our future site restoration obligation transactions for the ninethree months ended September 30, 2021March 31, 2022 and the year ended December 31, 20202021 (in thousands):

In April 2021, the Company divested various non-Bakken properties in North Dakota and Montana, primarily for plugging liability. The result of the transaction was a decrease of approximately $2.7 million in future site development liability, with a corresponding reduction in the full cost pool.

Recently Adopted Accounting Standards 

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

Recently Issued Accounting Standards

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

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

22. Reverse Stock Split

On October 19, 2020, the Company effected a 1-for-20 reverse stock split of its issued and outstanding shares of common stock, $0.01 par value. The Company effected the reverse stock split pursuant to the Company’s filing of a Certificate of Change  with the Secretary of State of the State of Nevada on September 29, 2020. Under Nevada law, no amendment to the Company’s  Articles of Incorporation was required in connection with the reverse stock split. The Company was authorized to issue 400,000,000 shares of common stock. As a result of the reverse stock split, the Company is authorized to issue 20,000,000 shares of common stock.  As a result of the reverse split, 168,069,305 outstanding shares of the Company’s  common stock were exchanged for approximately 8,421,910 shares of the Company’s  common stock (subject to adjustment due to the effect of rounding fractional shares into whole shares). The reverse stock split did not have any effect on the stated par value of the common stock.   All per share amounts and number of shares in the condensed consolidated financial statements and related notes have been retroactively restated to reflect the reverse stock split.

Additionally on October 19, 2020, all options, warrants and other convertible securities of the Company outstanding immediately prior to the reverse stock split were adjusted by dividing by 20 the number of shares of common stock into which the options, warrants and other convertible securities are exercisable or convertible, and multiplying the exercise or conversion price thereof by 20, all in accordance with the terms of the plans, agreements or arrangements governing such options, warrants and other convertible securities and subject to rounding to the nearest whole share.

The common stock began trading on a split-adjusted basis on the NASDAQ at the market open on October 19, 2020. The trading symbol for the common stock remains “AXAS”. On July 26, 2021, the Company received a notice from the Nasdaq Stock Market LLC that the Company's common stock would be suspended. The Company's securities were subsequently suspended from trading on NASDAQ on August 4, 2021 and removed from listing and registration on  September 17, 2021, and are currently listed on the OTCQX market place.

3. Revenue from Contracts with Customers

Revenue Recognition

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

Oil sales

Our oil sales contracts are generally structured such that we sell our oil production to a purchaser at a contractually specified delivery point at or near the wellhead. The crude oil production is priced on the delivery date based upon prevailing index prices less certain deductions related to oil quality, physical location and transportation costs incurred by the purchaser subsequent to delivery. We recognize revenue when control transfers to the purchaser upon delivery at or near the wellhead at the net price received from the purchaser.

Gas and NGL Sales

Under our gas processing contracts, we deliver wet gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to us based upon either (i) the resulting sales price of NGL and residue gas received by the midstream processing entity from third party customers, or (ii) the prevailing index prices for NGL and residue gas in the month of delivery to the midstream processing entity. Gathering, processing, transportation and other expenses incurred by the midstream processing entity are typically deducted from the proceeds that we receive.

In these scenarios, we evaluate whether the midstream processing entity is the principal or the agent in the transaction. In our gas purchase contracts, we have concluded that the midstream processing entity is the agent, and thus, the midstream processing entity is our customer. Accordingly, we recognize revenue upon delivery to the midstream processing entity based on the net amount of the proceeds received from the midstream processing entity.

Disaggregation of Revenue

We arehave been focused on the development of oil and natural gas properties primarily located in the following two operating regions in the United States: (i) the Permian/Delaware Basin, and (ii) Rocky Mountain. All of our  Rocky Mountain properties sold on January 3, 2022. Revenue attributable to each of those regions is disaggregated in the tables below.

Significant Judgments

Principal versus agent

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

Transaction price allocated to remaining performance obligations

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

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

Contract balances

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

To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as “Accounts receivable - Oil and gas production sales” in the accompanying condensed consolidated balance sheets. In this scenario, payment is also unconditional, as we have satisfied our performance obligations through delivery of the relevant product. As a result, we have concluded that our product sales do not give rise to contract assets or liabilities under ASU 2014-09. At September 30, 2021March 31, 2022 and December 31, 20202021, our receivables from contracts with customers were $13.3$7.4 million and $8.8$12.3 million, respectively.

Prior-period performance obligations

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

We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three  and ninemonths ended SeptemberMarch 31, 2022 30,2021and 2020,2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

4.3.  Income Taxes

Deferred tax assets and liabilities are determined based on differences between financial reporting and tax basis of assets and liabilities and are measured using the tax rates and laws expected to be in effect when the differences are expected to reverse.

For the three and ninemonths ended September 30, 2021,March 31, 2022, and 20202021, there was 0 income tax benefit due to net operating loss carryforwards (“NOLs”) and we recorded a full valuation allowance against our net deferred tax asset. 

At December 31, 20202021, we had, subject to the limitation discussed below, $245.2 million of pre-2018 NOLs and $137.8$190.8 million of post 20182017 NOL carryforwards for U.S. tax purposes.  Our pre-2018 NOLs will expire in varying amounts from 2022 through 2037, if not utilized. Any NOLs arising in 2018, 2019, 2020,and 20202021 can generally be carried back five years, carried forward indefinitely and can offset 100% of taxable income for tax years 2020 and up to 80% of future taxable income for tax years after December 31, 2020. Any NOLs arising on or after January 1, 2021 can generally be carried forward indefinitely and can offset up to 80% of future taxable income. The use of our NOLs will be limited if there is an “ownership change” in our common stock, generally a cumulative ownership change exceeding 50% during a three year period, as determined under Section 382 of the Internal Revenue Code. As of September 30, 2021March 31, 2022, we have not had an ownership change in our common stock as defined by Section 382.

Given historical losses, uncertainties exist as to the future utilization of the NOL carryforwards. Therefore, we established a valuation allowance of $117.3 million for deferred tax assets at December 31, 20202021.

As of September 30, 2021March 31, 2022, we did not have any accrued interest or penalties related to uncertain tax positions. The tax years 20152014 through 20202021 remain open to examination by the tax jurisdictions to which we are subject.

The Coronavirus Aid, Relief, and Economic Security Act  that was enacted March 27, 2020 includes income tax provisions that allow NOLs to be carried back, allow interest expense to be deducted up to a higher percentage of adjusted taxable income, and modify tax depreciation of qualified improvement property, among other provisions.  These provisions have no material impact on the Company.

5.4. Long-Term Debt
 

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

The following is a description of our debt as of September 30, 2021March 31, 2022 and December 31, 20202021 (in thousands):

First Lien Credit FacilityRestructuring

The Company has a senior secured First Lien Credit Facility with Société Générale,Pursuant to the Exchange Agreement, dated as administrative agentof January 3,2022, between Abraxas and issuing lender,AG Energy Funding, LLC (“AGEF”) and certain other lenders.  Asagreements entered into by Abraxas on January 3,2022, we effectuated a restructuring of September 30, 2021, $81.7our then-existing indebtedness through a multi-part interdependent de levering transaction consisting of: (i) an Asset Purchase and Sale Agreement  pursuant to which Abraxas sold to Lime Rock Resources V-A, L.P. certain oil, gas, and mineral properties in the Williston Basin region of North Dakota and other related assets belonging to the Company and its subsidiaries for $87,200,000 in cash ($70.3 million was outstanding underafter customary closing adjustments) (the “Sale”), (ii) the First Lien Credit Facility. 

Outstanding amountspay down of the indebtedness and other obligations of Abraxas and its subsidiaries under the First Lien Credit Facility, accrue interest at a rate per annum equal to (i) for borrowings that we elect to accrue interest atby and among Abraxas, the reference rate  at the greater of (x) the reference rate announced from time to time byfinancial institutions party thereto as lenders, and Société Générale, (y) the federal funds rate plus 0.5%,as “Issuing Lender” and (z)  daily one-month LIBOR plus, in each case, 1.5%-2.5%, depending on the utilization of the borrowing base,administrative agent and (ii) for borrowings that  we elect to accrue interest at the Eurodollar rate, LIBOR plus 2.5%-3.5% depending on the utilization of the borrowing base.

 However, at any time an event of default exists, the default rate is 3.0% plus the amounts set forth above. At September 30, 2021, the interest rate on the First Lien Credit Facility was approximately 8.75%.

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

Each of the Company’s  subsidiaries has guaranteed our obligations under the First Lien Credit Facility on a senior secured basis. Obligations under the First Lien Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of the Company and its subsidiary guarantors’ material property and assets. As of September 30, 2021, the collateral is required to include properties comprising at least 90% of the PV-9 of the Company’s  proven reserves and 95% of the PV-9 of the Company’s  PDP reserves.

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

The borrowing base will be reduced by any mandatory prepayments from excess cash flow (in an amount equal to such prepayment) and upon the dispositionequity exchange of the Company’s oilindebtedness and gas properties. At September 30, 2021, the Company’s borrowing base was $81.7 million, the amount outstanding on the First Lien Credit Facility,other obligations of Abraxas and thus the Company had 0 further borrowings available.

As of September 30, 2021, we were not in compliance with the financial covenants under the First Lien Credit Facility, as amended. See Note 10 “Events of Default” for details.

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

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

Events of default have occurred under the First Lien Credit Facility as a result of (i) our failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, (ii) our inability to comply with the first lien debt to consolidated EBITDAX ratio for the fiscal quarter ended December 31, 2020, (iii) our failure to cause certain deposit accounts to be subject to control agreements in favor of the administrative agent for the First Lien Credit Facility and (iv) certain cross-defaults that have occurred, or may occur, as a result of the events of default under the First Lien Credit Agreement and corresponding cross-defaultsits subsidiaries under the Second Lien Credit Facility, by and cross-defaults or similar termination events under our hedging contracts. See Note 10 “Events of Default” for details.

Second Lien Credit Facility

On November 13, 2019, we entered intoamong Abraxas, the Term Loan Credit Agreement, withfinancial institutions party thereto as lenders, and Angelo Gordon Energy Servicer, LLC, as administrative agent and certain other lenders party thereto, which we referall related loan and security documents (the “Exchange” and, together with the transactions referred to as the Second Lien Credit Facility.  The Second Lien Credit Facility was amended on June 25, 2020. The Second Lien Credit Facility has a maximum commitment of $100.0 million. As of  September 30, 2021in clauses (i) and (ii), the outstanding balance on the Second Lien Credit Facility was $137.1 million, which includes a $10.0 million exit fee.“Restructuring”). 

AGEF was issued 685,505 shares of Series A Preferred Stock of the Company in the Exchange.   The stated maturitySeries A Preferred Stock has the terms set forth in the Company’s filed Preferred Stock Certificate of Designation (the “Certificate).  Pursuant to the Certificate, any proceeds distributed to the Company’s stockholders or otherwise received in respect of the capital stock of the Company in a merger or other liquidity event will be allocated among the Series A Preferred Stock and the Company’s common stock as follows: (1) first, 100% to the Series A Preferred Stock until the Series A Preferred Stock has received $100 million of proceeds in the aggregate (the “Tier One Preference Amount”), (2) second, 95% to the Series A Preferred Stock and 5% to the Company’s common stock until the Series A Preferred Stock has received $137.1 million, plus a 6.0% annual rate of return thereon from the date of the Second Lien Credit Facility is issuance; (November 13, 2022. 3Prior) thereafter, 75% to the latest amendments of the Second Lien Credit Facility, accrued interest was payable quarterly on reference rate loansSeries A Preferred Stock and at the end of each three-month interest period on Eurodollar loans. We are permitted to prepay the loans in whole or in part, in compliance with certain notice and dollar increment requirements.

Each of our subsidiaries has guaranteed our obligations under the Second Lien Credit Facility. Obligations under the Second Lien Credit Facility are secured by a first priority perfected security interest, subject to certain permitted liens, including those securing the indebtedness under the First Lien Credit Facility25% to the extent permitted by the IntercreditorCompany’s common stock. The Exchange Agreement of even dateentered into in connection with the Second Lien Credit Facility, among us, our subsidiaries, Angelo Gordon Energy Servicer, LLCRestructuring also provides for the potential funding by AGEF of an additional amount up to $12.0 million, if agreed to by AGEF and Société Générale, in all of our subsidiary guarantors’ material property and assets. As of  September 30, 2021, the collateral is required to include properties comprising at least 90% of the PV-9disinterested members of the Company’s proven reservesBoard of Directors. Any such additional amount funded would result in an increase to the Tier One Preference Amount equal to 1.5x the amount of such additional funding. The shares of Series A Preferred Stock vote together as a single class with the Company’s common stock, and 95%each share of Series A Preferred Stock entitles the holder thereof to 69 votes. Accordingly, AGEF’s ownership of the PV-9Series A Preferred Stock entitle it to approximately 85% of the voting power of the Company’s PDP reserves. 

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

 As of  September 30, 2021, we were not in compliance with the financial covenants under the Second Lien Credit Facility, as amended. See Note 10 “Events of Default” for details.

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

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

Events of default have occurred under the Second Lien Credit Facility as a result of (i) our failure to timely deliver audited financial statements without a “going concern” or like qualification for the fiscal year ended December 31, 2020, (ii) our failure to cause certain deposit accounts to be subject to control agreements in favor of the administrative agent for the Second Lien Credit Facility, (iii)  the failure of the Company to meet certain hedging requirements, and (iv) certain cross-defaults that have occurred, or may occur, as a result of the occurrence of events of default under the First Lien Credit Facility and the Second Lien Credit Facility and corresponding cross-defaults or similar termination events under our hedging contracts. Additional events of default have occurred as of September 30, 2021, as a result of our failure to comply with certain financial covenants under the Second Lien Credit Facility, as amended. See Note 10 ”Events of Default” for details

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

The Notice of Default declares that our obligations under the Second Lien Credit Facility are immediately due and payable, in each case without presentment, demand, protest or other requirements of any kind, and have begun to bear interest at the rate applicable to such amount under the Second Lien Credit Facility, plus an additional 3%. Additionally, the administrative agent and the lenders have reserved their right to exercise further rights, powers and remedies under the Second Lien Credit Facility, at any time or from time to time, with respect to any of the events of default described above. Angelo Gordon agreed to forbear from exercising remedies available to it until May 6, 2021. We are in discussions with Angelo Gordon regarding further forbearance, but no assurance can be provided that we will be able to enter into any additional forbearance agreements.stock.

Real Estate Lien Note

We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. The outstanding principal accrues interest at a fixed rate of 4.9%. The note is payable in monthly installments of principal and accrued interest in the amount of $35,672. The maturity date of the note is July 20, 2023. As of  September 30, 2021March 31, 2022 and  December 31, 2020,2021,  $2.62.4  million and $2.8$2.5 million, respectively, were outstanding on the note.

Pending Discussions Regarding Debt Restructurings

The Company is in discussions with its creditors in an effort to restructure its balance sheet and eliminate or substantially reduce the outstanding indebtedness under its First Lien Credit Facility and Second Lien Credit Facility.  Any negotiated transaction with its lenders would likely include the possible sale of a significant block of assets, the proceeds from which would be applied to reduce debt, the exchange of a significant amount of equity interests in the Company for outstanding indebtedness, and/or other possible negotiated transactions, which in the aggregate would likely result in significant dilution of existing stockholder interests and reduction or potentially elimination of value for existing stockholders.  Any such transaction could involve a proceeding under the U.S. Bankruptcy Code.  No assurance can be provided that any such transaction can be successfully concluded, in which event the Company’s lenders may commence foreclosure proceedings seeking to liquidate Company assets to repay the outstanding indebtedness.  In any such proceeding, it is unlikely that stockholders would recover any more than a de minimis amount for their stock, and the stock may become worthless.

6.5. Earnings per Share

The following table sets forth the computation of basic and diluted earnings per share: