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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED September 30, 2022

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

COMMISSION FILE NUMBER: 001-16071

ABRAXAS PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Nevada		74-2584033
(State of Incorporation)		(I.R.S. Employer Identification No.)

18803 Meisner Drive, San Antonio, TX 78258

(Address of principal executive offices) (Zip Code)

210-490-4788

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol	Name of each exchange on which registered:
Common Stock, par value $.01 per share	AXAS	OTCQX

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

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

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

Large accelerated filer ☐	Accelerated filer ☐
Non-accelerated filer ☐	Smaller reporting company ☒
	Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Sec 13(a) of the Exchange Act. ☐

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

The number of shares of the issuer’s common stock outstanding as of November 8, 2022 was 100,701,430

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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.

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:

•

the prices we receive for our production and the effectiveness of our hedging activities, if any;

•

the availability of capital including under any applicable credit facilities;

•

our success in development, exploitation and exploration activities;

•

declines in our production of oil and gas;

•

volatility in oil, gas and natural gas liquids prices;

•

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

•

limits on our growth and our ability to finance our operations, fund our capital needs and respond to changing conditions;

•

our ability to make planned capital expenditures;

•

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

•

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

•

compliance with government regulations, including environmental, health, and safety regulations and liabilities thereunder;

•

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

•

general instability of economic and political conditions in the United States, including inflationary pressures, increased interest rates, economic slowdown or recession, and escalating geopolitical tensions;

•

price and availability of alternative fuels;

•

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

•

our acquisition and divestiture activities;

•

weather conditions and events; and

•

other factors discussed elsewhere in this report.

Many of the foregoing risks and uncertainties, as well as risks and uncertainties that are currently unknown to us, are, and may be, exacerbated by factors such as the ongoing conflict between Ukraine and Russia, escalating tensions between China and Taiwan, increasing economic uncertainty and inflationary pressures, the evolving nature of the COVID-19 pandemic and the emergence of new viral variants, and any consequent worsening of the global business and economic environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this quarterly report, our annual report on Form 10-K for the year ended December 31, 2021, or other filings with the SEC occur or should our underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We undertake no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

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.

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GLOSSARY OF TERMS

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

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

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

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

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

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

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

“Proved 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.

Table of Contents

ABRAXAS PETROLEUM CORPORATION

FORM 10 – Q

INDEX

PART I


ITEM 1 -	Financial Statements
	Condensed Consolidated Balance Sheets - September 30, 2022 (unaudited) and December 31, 2021	6
	Condensed Consolidated Statements of Operations – (unaudited) Three and Nine Months Ended September 30, 2022 and 2021	8
	Condensed Consolidated Statements of Stockholders' Equity (unaudited) Three and Nine Months Ended September 30, 2022 and 2021	9
	Condensed Consolidated Statements of Cash Flows – (unaudited) Nine Months Ended September 30, 2022 and 2021	10
	Notes to Condensed Consolidated Financial Statements - (unaudited)	11

ITEM 2 -	Management's Discussion and Analysis of Financial Condition and Results of Operations	24

ITEM 3 -	Quantitative and Qualitative Disclosures about Market Risk	35

ITEM 4 -	Controls and Procedures	35

PART II
OTHER INFORMATION

ITEM 1 -	Legal Proceedings	36
ITEM 1A -	Risk Factors	36
ITEM 2 -	Unregistered Sales of Equity Securities and Use of Proceeds	37
ITEM 3 -	Defaults Upon Senior Securities	37
ITEM 4 -	Mine Safety Disclosure	37
ITEM 5 -	Other Information	37
ITEM 6 -	Exhibits	37
	Signatures	38

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Part I

FINANCIAL STATEMENTS

Item 1. Financial Statements

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

	*September 30,*			*December 31,*
	*2022*			*2021*
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	25,101		$	10,034
Accounts receivable:
Joint owners, net		128			1,117
Oil and gas production sales		5,244			12,280
Other		30			150
Total accounts receivable		5,402			13,547

Assets held for sale		3,082			—
Other current assets		861			498
Total current assets		34,446			24,079

Property and equipment:
Proved oil and gas properties, full cost method		1,122,317			1,165,707
Other property and equipment		24,688			39,337
Total		1,147,005			1,205,044
Less accumulated depreciation, depletion, amortization and impairment		(1,093,557	)		(1,099,075	)
Total property and equipment, net		53,448			105,969

Operating lease right-of-use assets		2			173
Other assets		255			255
Total assets	$	88,151		$	130,476

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

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ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)

(in thousands, except share and per share data)

	*September 30,*			*December 31,*
	*2022*			*2021*
	(Unaudited)
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	8,265		$	4,678
Joint interest oil and gas production payable		3,011			13,347
Accrued interest		-			477
Accrued expenses		761			347
Right of use liability		2			40
Derivative liabilities - short-term		-			442
Termination of derivative contracts		-			8,022
Current maturities of long-term debt		-			212,688
Total current liabilities		12,039			240,041

Long-term debt – less current maturities		-			2,205
Operating lease right-of-use liabilities		-			110
Future site restoration		2,995			4,708
Total liabilities		15,034			247,064

Commitments and contingencies (Note 9)

Stockholders’ Equity:
Preferred stock, par value $0.01 per share – authorized 1,000,000 shares; 685,505 and -0- shares issued and outstanding at September 30, 2022 and December 31, 2021, respectively		7			-
Common stock, par value $0.01 per share, authorized 20,000,000 shares; 10,070,143 and 8,421,910 issued and outstanding at September 30, 2022 and December 31, 2021, respectively		101			84
Additional paid-in capital		576,993			430,422
Accumulated deficit		(503,984	)		(547,094	)
Total stockholders' equity (deficit)		73,117			(116,588	)
Total liabilities and stockholders’ equity (deficit)	$	88,151		$	130,476

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

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ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands except per share data)

	*Three Months Ended September 30,*						*Nine Months Ended September 30,*
	*2022*			*2021*			*2022*			*2021*
Revenues:
Oil and gas production revenues
Oil	$	9,733		$	15,506		$	31,307		$	45,199
Gas		2,434			2,415			5,733			5,344
Natural gas liquids		1,077			2,933			2,913			5,416
Other		8			11			20			19
Total revenue		13,252			20,865			39,973			55,978
Operating costs and expenses:
Lease operating		2,609			4,612			7,700			13,059
Production and ad valorem taxes		1,115			1,551			3,410			4,624
Rig expense		114			119			338			363
Depreciation, depletion, amortization and accretion		1,660			3,812			4,807			11,951
General and administrative (including stock-based compensation of $2,971 $273, $3,296 and $780, respectively)		5,231			1,942			9,049			6,253
Total operating cost and expenses		10,729			12,036			25,304			36,250
Operating income		2,523			8,829			14,669			19,728

Other (income) expense:
Interest income		(14	)		(4	)		(15	)		(13	)
Interest expense		11			8,057			111			21,742
Gain on sale of oil and gas assets		—			—			(29,359	)		—
Loss (gain) on sale of non-oil and gas assets		—			—			669			(29	)
Amortization of deferred financing fees		—			1,201			—			3,603
Financing fees		—			568			—			1,852
Debt forgiveness		—			—			(6,645	)		(1,384	)
Loss on debt extinguishment					—
Other		100			—			600			—
Loss on derivative contracts		—			252			—			32,897
Total other expense (income)		97			10,074			(34,639	)		58,668

Income (loss) before income tax		2,426			(1,245	)		49,308			(38,940	)
Income tax expense (benefit)		—			—			—			—
Net income (loss)		2,426			(1,245	)		49,308			(38,940	)
Accretion of preferred stock		2,134			—		$	6,198		$	-
Net income (loss) attributable to common stock	$	292		$	(1,245	)	$	43,110		$	(38,940	)

Net income (loss) per common share - basic	$	0.03		$	(0.15	)	$	4.64		$	(4.63	)
Net income (loss) per common share - diluted	$	0.03		$	(0.15	)	$	4.64		$	(4.63	)

Weighted average shares outstanding:
Basic		9,705			8,406			9,281			8,406
Diluted		9,705			8,406			9,281			8,406

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

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ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY

(Unaudited)

(in thousands, except share data)

									*Additional*
	*Common Stock*				*Preferred Stock*				*Paid in*			*Accumulated*
	*Shares*		*Amount*		*Shares*		*Amount*		*Capital*			*Deficit*			*Total*
Balance at December 31, 2021		8,421,910	$	84	$	-	$	-	$	430,422		$	(547,094	)	$	(116,588	)
Net income		-		-		-		-		-			43,110			43,110
Issuance of Restricted Stock, net of cancellations		1,648,233		17		-				(17	)		-			-
Issuance of Preferred Stock		-		-		685,505		7		137,094			-			137,101
Accretion of Preferred Stock		-		-		-		-		6,198			-			6,198
Stock-based compensation		-		-		-		-		3,296			-			3,296
Balance at September 30, 2022		10,070,143	$	101		685,505	$	7	$	576,993		$	(503,984	)	$	73,117

									*Additional*
	*Common Stock*				*Preferred Stock*				*Paid in*		*Accumulated*
	*Shares*		*Amount*		*Shares*		*Amount*		*Capital*		*Deficit*			*Total*
Balance at December 31, 2020		8,421,910	$	84		-	$	-	$	429,476	$	(502,527	)	$	(72,967	)
Net loss		-		-		-		-		-		(38,940	)		(38,940	)
Stock-based compensation		-		-		-		-		780		-			780
Balance at September 30, 2021		8,421,910	$	84		-	$	-	$	430,256	$	(541,467	)	$	(111,127	)

									*Additional*
	*Common Stock*				*Preferred Stock*				*Paid in*		*Accumulated*
	*Shares*		*Amount*		*Shares*		*Amount*		*Capital*		*Deficit*			*Total*
Balance at June 30, 2022		10,070,143	$	101		685,505	$	7	$	571,888	$	(504,276	)	$	67,720
Net income		-		-		-		-		-		292			292
Accretion of Preferred Stock		-		-		-		-		2,134		-			2,134
Issuance of restricted stock, net of cancellations		-		-		-		-		-		-			-
Stock-based compensation		-		-		-		-		2,971		-			2,971
Balance at September 30, 2022		10,070,143	$	101		685,505		7	$	576,993	$	(503,984	)	$	73,117

									*Additional*
	*Common Stock*				*Preferred Stock*				*Paid in*		*Accumulated*
	*Shares*		*Amount*		*Shares*		*Amount*		*Capital*		*Deficit*			*Total*
Balance at June 30, 2021		8,421,910	$	84		-	$	-	$	429,983	$	(540,222	)	$	(110,155	)
Net loss		-		-		-		-		-		(1,245	)		(1,245	)
Stock-based compensation		-		-		-		-		273		-			273
Balance at September 30, 2021		8,421,910	$	84		-	$	-	$	430,256	$	(541,467	)	$	(111,127	)

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

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ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	*Nine Months Ended September 30,*
	*2022*			*2021*
Operating Activities
Net income (loss)	$	43,110		$	(38,940	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net loss on derivative contracts		—			32,897
Net cash settlements paid on derivative contracts		—			(1,497	)
Gain on sale of oil and gas properties		(29,359	)		—
Loss (gain) on sale of non-oil and gas properties		669			(29	)
Depreciation, depletion, amortization and accretion of future site restoration		4,807			11,951
Amortization of deferred financing fees and issuance discount		—			5,734
Stock-based compensation		3,296			780
Settlements of asset retirement obligations		—			336
Accretion of preferred stock		6,198			—
Debt forgiveness		(6,645	)		(1,384	)
Non-cash interest expense		—			14,406
Non-cash hedge contract termination		—			9,943
Changes in operating assets and liabilities:
Accounts receivable		8,145			(4,766	)
Other assets		(744	)		(10,186	)
Accounts payable and accrued expenses		(6,841	)		631
Net cash provided by operating activities		22,636			19,876

Investing Activities
Capital expenditures, including purchases and development of properties		(1,084	)		(856	)
Proceeds from the sale of oil and gas properties		72,047			117
Proceeds from the sale of non-oil and gas properties		637			256
Net cash provided by (used in) investing activities		71,600			(483	)

Financing Activities
Proceeds from PPP loan		—			1,336
Payments on long-term borrowings		(77,966	)		(14,296	)
Deferred financing fees		(1,203	)		(157	)
Net cash used in financing activities		(79,169	)		(13,117	)

Increase in cash and cash equivalents		15,067			6,276
Cash and cash equivalents at beginning of period		10,034			2,775
Cash and cash equivalents at end of period	$	25,101		$	9,051

Supplemental disclosures of cash flow information:
Interest paid	$	70		$	4,667

Non-cash investing and financing activities:
Non-cash interest paid in kind	$	-		$	14,406
Non-cash issuance of preferred stock	$	137,101		$	-
Change in capital expenditures included in accounts payable	$	(41	)	$	28
Change in future site restoration on properties sold	$	1,839		$	2,704
Debt forgiveness	$	(6,645	)	$	1,384

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

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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, 2022 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, 2021 filed with the SEC on March 31, 2022. 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 statements of operations for the three and nine month periods ended September 30, 2022 , the statements of stockholders' equity for the three and nine months ended Septermbert 30, 2022, and the statement of cash flows for the nine months ended September 30, 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, 2021.

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 Cash Compensation

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 nine months ended September 30, 2022, (in thousands):

	*Number of Shares*			*Weighted Average Option Exercise Price Per Share*		*Weighted Average Grant Date Fair Value Per Share*
Outstanding, December 31, 2021		55		$	53.79	$	36.95
Cancelled/Forfeited		(44	)	$	55.79	$	38.05
Expired		(4	)	$	40.43	$	29.23
Balance, September 30, 2022		7		$	-	$	-

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Restricted Stock Awards

Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the 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.

On May 12, 2022, AG Energy Funding, LLC (“AGEF”) and our Board of Directors (the “Board”) approved grants of restricted stock to certain of our executives to incentivize their retention. The grants were made pursuant to the Abraxas Petroleum Corporation Amended and Restated 2005 Employee Long-Term Equity Incentive Plan (the “Employee LTIP”) and vest one-third on each of the first, second, and third anniversary of the grant date. The vesting schedule accelerates, and the restricted shares become fully vested, upon death or total disability of the grantee or upon a Change of Control (as defined in the Employee LTIP) of the Company.

On September 13, 2022, AGEF and Biglari Holdings Inc., an Indiana corporation (“Biglari Holdings”), entered into a Preferred Stock Purchase Agreement (the “Preferred Purchase Agreement”) and an Assignment and Assumption Agreement (the “Assignment Agreement”), pursuant to which AGEF agreed to sell and assign to Biglari Holdings, and Biglari Holdings agreed to purchase, acquire, and assume all 685,505 shares of the Company’s Series A Preferred Stock (the “ Preferred Shares”) held by AGEF and all of AGEF’s rights, title, and interests in, and duties and obligations under, an Exchange Agreement dated January 3, 2022 (the “Exchange Agreement”) between the Company and AGEF (such transactions between AGEF and Biglari Holdings, the “Sale and Assignment”). 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.

See Note 4 “Long-Term Debt - Restructuring” and Note 10 “Disposition of Assets and Restructuring” to the Consolidated Financial Statements.

AGEF and the Board also granted restricted stock to one of its non-employee directors for incentivization and retention purposes. The restricted stock grant vests one-third on each of the first, second, and third anniversary of the grant date and was made pursuant to the Abraxas Petroleum Corporation Amended and Restated 2005 Non-Employee Director Long-Term Equity Incentive Plan (the “Non-Employee LTIP”).

The restricted stock granted under the Employee LTIP and the Non-Employee LTIP vested in September 2022 as a result of the Change of Control that occurred upon the Sale and Assignment between Biglari Holdings and AGEF.

The following table summarizes our restricted stock activity for the nine months ended September 30, 2022. Grants of restricted shares included: (i) 500,000 to Robert L.G. Watson, (ii) 162,000 to Steven P. Harris, (iii) 178,000 to Kenneth W. Johnson (each of the foregoing under the Employee LTIP), and (iv) 50,000 to Brian Melton under the Non-Employee LTIP.

	*Number of Shares (thousands)*			*Weighted Average Grant Date Fair Value Per Share*
Unvested, December 31, 2021		14		$	27.97
Granted		1,650		$	1.88
Vested/Released		(1,664	)		27.97
Unvested, September 30, 2022	$	-		$	-

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

	*Number of Shares (thousands)*			*Weighted Average Grant Date Fair Value Per Share*
Unvested, December 31, 2021		28		$	26.80
Expired		(28	)	$	26.80
Unvested, September 30, 2022		-		$	-

Compensation expense associated with the performance-based restricted stock is based on the grant date fair value of a single share as determined using a Monte Carlo Simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the performance-based restricted stock awards with shares of 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.

	*Three Months Ended*				*Nine Months Ended*
	*September 30,*				*September 30,*
	*2022*		*2021*		*2022*		*2021*
Options	$	-	$	1	$	-	$	(22	)
Restricted stock		2,971		211		3,217		527
Performance shares		-		61		79		275
	$	2,971	$	273	$	3,296	$	780

As of September 30, 2022, all expense related to stock-based compensation related to stock options and performance shares has been fully amortized.

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Cash Compensation for Non-Employee Directors

On May 12, 2022, AGEF and the Board approved cash compensation in the amount of $10,000 per calendar quarter to each non-employee member of the Board for the purpose of attracting and retaining qualified individuals to serve as Board members.

Management Incentive Plan

On May 12, 2022, AGEF and the Board approved the Abraxas Petroleum Corporation Management Incentive Plan (the “MIP”), pursuant to which participants (“Eligible Employees”), including our named executive officers (“NEOs”), earn a bonus payment (a “Bonus”) upon a Change of Control (as defined in the MIP) of the Company. Under the MIP, any such Bonus is payable (i) in cash and securities in the same ratio as the consideration received by the Company and/or its stockholders in connection with such Change of Control, and (ii) in an amount equal to (x) such Eligible Employee’s MIP Allocation (shown in Table A below for our NEOs, expressed as a percentage of the MIP shares owned by such NEO compared to the total MIP shares available under the MIP) multiplied by (y) the MIP value calculation (shown in Table B below).

The aggregate MIP payout is capped at $12.0 million. The Board’s Compensation Committee will determine in good faith the Change of Control value of the MIP Bonus pool based on the consideration received by Abraxas in any asset sale or the equity value of Abraxas implied by the consideration received by the stockholders of Abraxas in any merger or similar transaction. Any MIP payout is subject to adjustment as set forth in the MIP based on the timing of the Change of Control following the adoption of the MIP.

On September 13, 2022, AGEF and Biglari Holdings entered into the Preferred Purchase Agreement and the Assignment Agreement, pursuant to which AGEF agreed to sell and assign to Biglari Holdings, 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 between the Company and AGEF. 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. While a Change of Control occurred, the imputed value of the transaction contemplated by the Sale and Assignment, if relevant to the required determination of Change of Control Value, and if adjusted to cover the aggregate value of the outstanding capital stock of the Company, did not exceed $100 million.

See Note 4 “Long-Term Debt - Restructuring” and Note 10 “Disposition of Assets and Restructuring” to the Consolidated Financial Statements.

Table A –Eligible NEOs

Eligible Employee	Allocation of MIP Value %
Robert Watson		45.00	%
Kenny Johnson		9.50	%

Table B – Aggregate Bonus Amount Calculation

Tier	Change of Control Value Range	MIP Pool Enhancement			Accreted Amount
I	$0-100 million		0	%
II	$100-110 million		50	%	$	5,000,000
III	$110-140 million		5	%	$	1,500,000
IV	$140-180 million		10	%	$	4,000,000
V	$180+ million		15	%	up to $1,500,000

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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, 2022, the net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves.

Assets Held for Sale

On September 26, 2022, the Company entered into an agreement to sell its corporate headquarters building for approximately $5.0 million. Assets held for sale are stated at net book value. It is anticipated that the sale will close in the fourth quarter of 2022.

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 nine months ended September 30, 2022 and the year ended December 31, 2021 (in thousands):

	*September 30, 2022*			*December 31, 2021*
Beginning future site restoration obligation	$	4,708		$	7,360
New wells placed on production and other		-			1
Deletions related to property sales		(1,839	)		(2,845	)
Deletions related to plugging costs		-			(342	)
Accretion expense		128			330
Revisions and other		(2	)		204
Ending future site restoration obligation	$	2,995		$	4,708

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2. 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.

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Disaggregation of Revenue

We have 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.

	*Three Months Ended September 30,*
	*2022*						*2021*
	*Oil*		*Gas*		*NGL*		*Oil*		*Gas*		*NGL*
Operating Regions:
Permian/Delaware Basin	$	9,733	$	2,434	$	1,077	$	8,341	$	1,232	$	724
Rocky Mountain	$	-	$	-	$	-	$	7,165	$	1,183	$	2,209

	*Nine Months Ended September 30,*
	*2022*						*2021*
	*Oil*		*Gas*		*NGL*		*Oil*		*Gas*		*NGL*
Operating Regions:
Permian/Delaware Basin	$	31,307	$	5,733	$	2,913	$	23,906	$	3,096	$	1,412
Rocky Mountain	$	-	$	-	$	-	$	21,293	$	2,248	$	4,004

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. The Company reports revenue on a net basis.

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.

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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, 2022 and December 31, 2021, our receivables from contracts with customers were $5.2 million and $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 nine months ended September 30, 2022 and 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

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.

At December 31, 2021, we had, subject to the limitation discussed below, $245.2 million of pre-2018 net operating loss carryforwards (“ NOLs”) and $179.0 million of post 2017 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 2021 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 Company has recorded full valuation allowances against our deferred tax asset for net operating losses. The Company released a portion of the valuation allowances during the three and nine months ended September 30, 2022, which resulted in not having an income tax expense during the respective periods.

As of September 30, 2022, we did not have any accrued interest or penalties related to uncertain tax positions. The tax years 2014 through 2021 remain open to examination by the tax jurisdictions to which we are subject.

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4. Long-Term Debt

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

	*September 30, 2022*		*December 31, 2021*

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
Total long term debt		-		218,822
Less current maturities		-		(212,688	)
		-		6,134
Deferred financing fees and debt issuance cost, net		-		(3,929	)
Total long-term debt, net of deferred financing fees and debt issuance costs	$	-	$	2,205

Restructuring

Pursuant to the Exchange Agreement, dated as of January 3, 2022, between Abraxas and AGEF (the “ First Exchange Agreement”) and certain other agreements entered into by Abraxas on January 3, 2022, we effectuated a restructuring of our then-existing indebtedness through a multi-part interdependent 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 after customary closing adjustments) (the “Sale”), (ii) the pay down of the indebtedness and other obligations of Abraxas and its subsidiaries under the First Lien Credit Facility, by and among Abraxas, the financial institutions party thereto as lenders, and Société Générale, as “Issuing Lender” and administrative agent and certain specified secured hedges from the proceeds of the Sale and, to the extent necessary, other cash of Abraxas, and (iii), a debt for equity exchange of the indebtedness and other obligations of Abraxas and its subsidiaries under the Second Lien Credit Facility, by and among Abraxas, the financial institutions party thereto as lenders, and Angelo Gordon Energy Servicer, LLC, as administrative agent 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 in the Exchange, which entitled AGEF to approximately 85% of the voting power of the Company’s outstanding capital stock.

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

On September 13, 2022, AGEF and Biglari Holdings, entered into the Preferred Purchase Agreement, pursuant to which AGEF agreed to sell and assign to Biglari Holdings, 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.

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, 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, 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 (the “Amendment”).

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

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

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

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 note was paid in full in August 2022.

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5. Earnings per Share

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

	*Three Months Ended September 30,*					*Nine Months Ended September 30,*
	*2022*		*2021*			*2022*		*2021*
Numerator:
Net income (loss)	$	292	$	(1,245	)	$	43,110	$	(38,940	)
Denominator:
Denominator for basic earnings per share – weighted-average common shares outstanding		9,705		8,406			9,281		8,406
Effect of dilutive securities:
Stock options, restricted shares and warrants				-					-
Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options and restricted shares		9,705		8,406			9,281		8,406

Net income (loss) per common share - basic	$	0.03	$	(0.15	)	$	4.64	$	(4.63	)

Net income (loss) per common share - diluted	$	0.03	$	(0.15	)	$	4.64	$	(4.63	)

Basic earnings per share, excluding any dilutive effects of stock options and unvested restricted stock, is computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted net income per share is computed similar to basic; however diluted income per share reflects the assumed conversion of all potentially dilutive securities. For the three and nine month periods ended September 30, 2021 there were no dilutive potential shares relating to stock options and restricted stock due to our depressed stock price.

6. Hedging Program and Derivatives

As of September 30, 2022, the Company is not party to any hedge agreements. The liability as of December 31, 2021 relates to the settlement of the December 2021 contract:

*Fair Value of Derivative Contracts as December 31, 2021*
	*Asset Derivatives*			*Liability Derivatives*
Derivatives not designated as hedging instruments	*Balance Sheet Location*	*Fair Value*		*Balance Sheet Location*	*Fair Value*
Commodity price derivatives	Derivatives – current	$	-	Derivatives – current	$	442
Commodity price derivatives	Derivatives – long-term		-	Derivatives – long-term		-
		$	-		$	442

7. Financial Instruments

The Company did not have any active financial instruments as of September 30, 2022. The Level 2 financial instruments as of December 31, 2021 relates to the settlement of the December 31, 2021 contract.

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2021
Liabilities:
NYMEX fixed price derivative contracts	$	—	$	442	$	—	$	442
Total Liabilities	$	—	$	442	$	-	$	442

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Nonrecurring Fair Value Measurements

Non-financial assets and liabilities measured at fair value on a nonrecurring basis included certain non-financial assets and liabilities as may be acquired in a business combination and thereby measured at fair value and the initial recognition of asset retirement obligations for which fair value is used. Unproved oil and gas properties are assessed periodically, at least annually, to determine whether impairment has occurred. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, the economic viability of development if proved reserves were assigned and other current market conditions. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligation is presented in Note 1 “ Basis of Presentation”.

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable and accounts payable approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying value of our debt approximates fair value as the interest rates are market rates and this debt is considered Level 2.

8. Leases

Nature of Leases

We lease certain field equipment and other equipment under cancelable and non-cancelable leases to support our operations.

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Practical Expedients and Accounting Policy Elections

Certain of our lease agreements include lease and non-lease components. For all existing asset classes with multiple component types, we have utilized the practical expedient that exempts us from separating lease components from non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component. In addition, for all of our existing asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less and does not include an option to purchase the underlying asset that we are reasonably certain to exercise). Accordingly, we recognize lease payments related to our short-term leases in our statement of operations on a straight-line basis over the lease term which has not changed from our prior recognition. To the extent that there are variable lease payments, we recognize those payments in our statement of operations in the period in which the obligation for those payments is incurred. None of our current leases contain variable payments. Refer to “ Nature of Leases” above for further information regarding those asset classes that include material short-term leases.

The components of our total lease expense for the three and nine months ended September 30, 2022, the majority of which is included in lease operating expense, are as follows:

	*Three Months Ended September 30, 2022*		*Nine Months Ended September 30, 2022*
Operating lease cost	$	2	$	10
Short-term lease expense (1)	$	118	$	434
Total lease expense	$	120	$	444

Short-term lease costs (2)	$	-	$	-

	(1)	Short-term lease expense represents expense related to leases with a contract term of 12 months or less.
	(2)	These short-term lease costs are related to leases with a contract term of 12 months or less which are related to drilling rigs and are capitalized as part of natural gas and oil properties on our balance sheet.

Supplemental balance sheet information related to our operating leases is included in the table below:

	*September 30, 2022*
Operating lease ROU assets	$	2
Operating lease liability - current	$	2
Operating lease liabilities - long-term	$	-

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

	*September 30, 2022*
Weighted Average Remaining Lease Term (in years)		0.3
Weighted Average Discount Rate		6	%

Our lease liabilities with enforceable contract terms that are greater than one year mature as follows:

	*Operating Leases*
Remainder of 2022	$	2
2023		—
2024		—
2025		—
2026		—
Thereafter		—
Total lease payments		2
Less imputed interest		—
Total lease liability	$	2

At September 30, 2022, we had only a lease on office equipment, with minimum lease payments with commitments that had initial or remaining lease terms in excess of one year.

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9. Commitments and 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 September 30, 2022, we were not involved in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on our financial position or results of operations.

10. Disposition of Assets and Restructuring

On January 3, 2022, the Company and Lime Rock Resources V-A, L.P., a Delaware limited partnership (“Lime Rock”), entered into an Asset Purchase and Sale Agreement (the “Purchase Agreement”), pursuant to which the Company agreed to sell to Lime Rock certain oil, gas, and mineral properties in the Williston Basin region of North Dakota (the “Properties”) and other related assets (together with the Properties, the “Assets”) belonging to the Company and its subsidiaries for $87,200,000 in cash, subject to customary purchase price adjustments (the “Purchase Price”; such sale, the “Sale”). As described in and subject to the limitations set forth in the Purchase Agreement, the Assets include, among other things, the oil and gas leases described in the Purchase Agreement; the leasehold, mineral, and royalty interests in, and the production and development rights to, the Properties; all contracts, agreements, and instruments by which the Properties are bound; and all rights and interests in the drilling, spacing, or pooled units designated in the Purchase Agreement. The Purchase Agreement includes customary terms and conditions for agreements of this nature. The Purchase Agreement also contains indemnification obligations of both the Company and Lime Rock with respect to customary matters, including breaches of representations, warranties, and covenants. The closing of the transactions contemplated by the Purchase Agreement occurred concurrently with execution of the agreement on January 3, 2022.

As discussed in Note 4 above, on January 3, 2022, the Company effectuated the Restructuring of our then-existing indebtedness through a multi-part interdependent de-levering transaction consisting of: (i) the Purchase Agreement and the Sale, (ii) the pay down of the indebtedness and other obligations of Abraxas and its subsidiaries under the First Lien Credit Facility, by and among Abraxas, the financial institutions party thereto as lenders, and Société Générale, as “Issuing Lender” and administrative agent and certain specified secured hedges from the proceeds of the Sale and, to the extent necessary, other cash of Abraxas; and (iii), a debt for equity exchange of the indebtedness and other obligations of Abraxas and its subsidiaries under the Second Lien Credit Facility, by and among Abraxas, the financial institutions party thereto as lenders, and Angelo Gordon Energy Servicer, LLC, as administrative agent and all related loan and security documents.

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Exchange Agreement

On January 3, 2022, the Company and AGEF and an affiliate of the Second Lien Agent, entered into an Exchange Agreement (the “Exchange Agreement”) pursuant to which, and effective immediately upon the consummation of the transactions contemplated by the Purchase Agreement and the First Lien Release Agreement, AGEF transferred to the Company all of AGEF’s claims outstanding under the Second Lien Debt Agreement (the “Claims”) in exchange for the Company’s issuance to AGEF of 685,505 shares of the Company’s preferred stock, par value $0.01 per share, designated as “Series A Preferred Stock” (the “Preferred Stock”), having the terms set forth in the Preferred Stock Certificate of Designation (the “Certificate”; such exchange between the Company and AGEF, the “Exchange”). Effective upon the Exchange, all of the Claims in favor of AGEF were automatically deemed paid and satisfied in full, discharged, terminated, released, and cancelled for all purposes under the Second Lien Debt Agreement.

In connection with the consummation of the Exchange Agreement, on January 3, 2022, the Second Lien Parties entered into an Amendment No. 2 to Forbearance Agreement (the “Second Lien Forbearance”) with respect to the Second Lien Debt Agreement. Under the Second Lien Forbearance, the parties thereto agreed to (i) extend the temporary forbearance period under the Forbearance Agreement until January 14, 2022, unless terminated earlier by a “Forbearance Termination Event” (as defined in the Second Lien Forbearance), and (ii) amend certain other terms of the Forbearance Agreement. Subject to the terms and conditions set forth in the Second Lien Forbearance, the Second Lien Agent and the Second Lien Lenders agreed to release their liens and security interests on the Assets being sold by the Company to Lime Rock under the Purchase Agreement.

The foregoing description of the Exchange Agreement, the Certificate and the Second Lien Forbearance is a summary only, does not purport to be complete, and is qualified in its entirety by reference to the complete text of the Exchange Agreement, the Certificate, and the Second Lien Forbearance, which are filed as Exhibits 10.3, 3.1 and 4.1, and 10.4, on Form 8-K filed on January 3, 2022, and are incorporated by reference herein.

In connection with the proposed Sale of the Assets to Lime Rock, as contemplated by the Purchase Agreement, and the proposed Exchange of AGEF’s claims outstanding under the Second Lien Debt Agreement for the Preferred Stock, as contemplated by the Exchange Agreement, the Company’s Board requested that Petrie Partners Securities, LLC (“Petrie”) render opinions as to whether the Purchase Price and the Exchange are fair, from a financial point of view, to the Company. Petrie represented the Company in the broadly marketed sale of the Assets. On January 2, 2022, Petrie delivered opinions to the Board, dated January 3, 2022 (the “Fairness Opinions”), stating that the Purchase Price and the Exchange are fair, from a financial point of view, to the Company.

As discussed above AGEF was issued 685,505 shares of Series A Preferred Stock of the Company in the Exchange, which entitled AGEF to approximately 85% of the voting power of the Company’s outstanding capital stock.

As discussed in Note 4 above, subsequently, Biglari Holdings acquired the Preferred Shares from AGEF, and later the Company caused 90,631,287 shares of common stock to be registered in the name of Biglari Holdings.The Company cancelled the Preferred Shares 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 such Second Exchange, the Company is a consolidated subsidiary of Biglari Holdings, and Biglari Holdings has the power to exert significant control over the Company by controlling both 90% of the voting power of the Company’s outstanding capital stock and a majority of the Company’s Board.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following is a discussion and analysis of our financial condition, results of operations, liquidity and capital resources and should be read in conjunction with our consolidated financial statements and the notes thereto, included in this Quarterly Report on Form 10-Q and the consolidated financial statements and notes thereto as of and for the year ended December 31, 2021 and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations, both of which are contained in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the SEC on March 31, 2022. Please see “Forward Looking Information” above.

Except as otherwise noted, all tabular amounts are in thousands, except per unit values.

Critical Accounting Policies

There have been no changes from the Critical Accounting Policies described in our Annual Report on Form 10-K for the year ended December 31, 2021.

General

We are an independent energy company primarily engaged in producing oil and gas in the Permian Basis. Historically, we have grown through the acquisition and subsequent development of producing properties, principally through the development of shale or tight oil reservoirs in areas known to be productive of oil and gas utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys and horizontal drilling and stage fracturing. Moreover, we believe that we have a number of development opportunities on our properties.

Restructuring

See Note 4 “Long-Term Debt - Restructuring” and Note 10 “Disposition of Assets and Restructuring” to the Consolidated Financial Statements.

Factors Affecting Our Financial Results

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; and

•

the level and success of exploration and development activity.

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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 and differentials. 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. Factors that influence oil and gas prices include the global demand for and global supply of oil, NGL and gas. 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.

Effects of Inflation and Pricing

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 the 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. In accordance with historical trends, we expect that the volatility of oil, NGL, and gas pricing will persist. The market price of oil and condensate, NGL and gas largely determines the amount of cash generated from operating activities, which will in turn impact our financial position.

Material changes in the prices we receive for the oil and natural gas that we produce will impact our operating revenues, cash flow, financial condition, estimates of future reserves.

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During the nine months ended September 30, 2022, the NYMEX future price for oil averaged $98.25 per Bbl as compared to $65.04 per Bbl in the same period of 2021. During the nine months ended September 30, 2022, the NYMEX future spot price for gas averaged $6.69 per MMBtu compared to $3.35 per MMBtu in the same period of 2021. Prices closed on September 30, 2022 at $79.49 per Bbl of oil and $6.77 per MMBtu of gas, compared to closing on September 30, 2021 at $75.03 per Bbl of oil and $5.87 per MMBtu of gas. On November 7, 2022, prices closed at $91.79 per Bbl of oil and $6.94 per MMBtu of gas. If commodity prices decline, our revenue and cash flow 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 flow from operations will also likely decrease which could cause us to alter our business plans. Such declines have required, and in future periods could also require us to write down the carrying value of our oil and gas assets which would also cause a reduction in net income. The prices that we receive are also impacted by basis differentials, which can be significant, and are dependent on actual delivery points. Finally, low commodity prices will likely cause a reduction of our proved reserves.

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

•

basis differentials which are dependent on actual delivery location;

•

adjustments for BTU content;

•

quality of the hydrocarbons; and

•

gathering, processing and transportation costs.

The following table sets forth our average differentials for the nine-month periods ended September 30, 2022 and 2021:

	Oil - NYMEX					Gas - NYMEX
	2022		2021			2022			2021
Average realized price (1)	$	98.60	$	60.82		$	4.97		$	2.06
Average NYMEX price		98.25		65.04			6.69			3.35
Differential	$	0.35	$	(4.22	)	$	(1.72	)	$	(1.29	)

(1) 2021 excludes the impact of derivative activities.

Production Volumes. Our proved reserves will decline as oil and gas is produced, unless we find, acquire or develop additional properties containing proved reserves. Based on the reserve information set forth in our reserve report as of December 31, 2021, our average annual estimated decline rate for our net proved developed producing reserves is 20%; 15%; 13%; 12% and 11% in 2022, 2023, 2024, 2025 and 2026, respectively, 9% in the following five years, and approximately 10% thereafter. These rates of decline are estimates and actual production declines could be materially different.

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We had capital expenditures during the nine months ended September 30, 2022 of $1.1 million related to our existing properties. We have not formally established a capital expenditure budget for 2022.

The following table presents historical net production volumes for the three and nine months ended September 30, 2022, and 2021:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2022			2021			2022			2021
Total production (MBoe)		216			516			608			1,541
Average daily production (Boepd)		2,350			5,605			2,228			5,664
% Oil		56	%		45	%		52	%		48	%

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 three and nine months ended September 30, 2022 and 2021, by our major operating regions:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Oil production (MBbls)
Rocky Mountain (2)		-		108		-		360
Permian/Delaware Basin		104		122		318		383
Total		104		230		318		743
Gas production (MMcf)
Rocky Mountain (2)		-		477		-		1,391
Permian/Delaware Basin		429		415		1,154		1,204
Total		429		892		1,154		2,595
NGL production (MBbls)
Rocky Mountain (2)		-		107		-		283
Permian/Delaware Basin		41		30		98		82
Total		41		137		98		365
Total production (MBoe) (1)		216		516		608		1,541
Average sales price per Bbl of oil (3)
Rocky Mountain (2)	$	-	$	66.08	$	-	$	59.07
Permian/Delaware Basin		93.51		68.66		98.60		62.48
Composite		93.51		67.44		98.60		60.82
Average sales price per Mcf of gas (2)
Rocky Mountain (2)	$	-	$	2.48	$	-	$	1.62
Permian/Delaware Basin		5.67		2.97		4.97		2.57
Composite	$	5.67		2.71	$	4.97		2.06
Average sales price per Bbl of NGL
Rocky Mountain (2)	$	-	$	20.70	$	-	$	14.14
Permian/Delaware Basin		26.51		23.80		29.59		17.17
Composite		26.51		21.39		29.59		14.83
Average sales price per Boe (2)	$	61.25	$	40.44	$	65.68	$	36.32
Average cost of production per Boe produced (4)
Rocky Mountain (2)	$	-	$	8.16	$	-	$	6.88
Permian/Delaware Basin		12.07		9.87		12.49		10.61
Composite		12.07		8.87		12.49		8.48

(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)	Rocky Mountain properties were sold on January 3, 2022.
	(3)	2021 amounts are before the impact of hedging activities.

(4)

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

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Availability of Capital. As described more fully under “Liquidity and Capital Resources” below, our sources of capital are cash flow from operating activities and sales of properties, although we may not be able to complete any asset sales on terms acceptable to us, if at all. Our First Lien Credit Facility was settled and our Second Lien Credit Facility was converted to Class A Preferred Stock in connection with the Restructuring that took place on January 3, 2022. See Note 4 “Long-Term Debt Restructuring” and Note 10. “Disposition of Assets and Restructuring” to the Consolidated Financial Statements. We do not currently have a credit facility in place and have not formally established a capital budget for 2022.

Borrowings and Interest. At September 30, 2022, we had no outstanding debt.

Exploration and Development Activity. We believe that our high quality asset base, high degree of operational control and inventory of drilling projects position us to partner with other parties. At December 31, 2021, we operated properties accounting for virtually all of our PV-10, giving us substantial control over the timing and incurrence of operating and capital expenditures.

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Results of Operations

Selected Operating Data. The following table sets forth operating data from continuing operations for the periods presented.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Operating revenue (1):(2)
Oil sales	$	9,733	$	15,506	$	31,307	$	45,199
Gas sales		2,434		2,415		5,733		5,344
NGL sales		1,077		2,933		2,913		5,416
Other		8		11		20		19
Total operating revenues	$	13,252	$	20,865	$	39,973	$	55,978
Operating income	$	2,523	$	8,829	$	14,669	$	19,728
Oil sales (MBbls)		104		230		318		743
Gas sales (MMcf)		429		892		1,154		2,595
NGL sales (MBbls)		41		137		98		365
Oil equivalents (MBoe)		216		516		608		1,541
Average oil sales price (per Bbl)(1)	$	93.51	$	67.44	$	98.60	$	60.82
Average gas sales price (per Mcf)(1)	$	5.67	$	2.71	$	4.97	$	2.06
Average NGL sales price (per Bbl)	$	26.51	$	21.39	$	29.59	$	14.83
Average oil equivalent sales price (Boe) (1)	$	61.25	$	40.44	$	65.68	$	36.32

___________________

	(1)	2021 revenue and average sales prices are before the impact of hedging activities.
	(2)	2021 amounts include activity from our Rocky Mountain properties that were sold on January 3, 2022

Comparison of Three Months Ended September 30, 2022 to Three Months Ended September 30, 2021

Operating Revenue. During the three months ended September 30, 2022, operating revenue decreased to $13.3 million from $20.9 million for the same period of 2021. The decrease in revenue was primarily due to lower sales volumes offset by higher commodity prices. Higher realized prices for all products added $4.2 million to operating revenue for the three months ended September 30, 2022. Lower sales volumes negatively impacted revenue by $11.8 million. Lower sales volumes were primarily due to the sale of our Bakken properties in North Dakota on January 3, 2022. Sales from the Bakken properties contributed 295 MBoe and $10.6 million to revenue in the third quarter of 2021.

Oil sales volumes decreased to 104 MBbl during the three months ended September 30, 2022 from 230 MBbl for the same period of 2021. The decrease in oil sales volume was primarily due to the sale of our Bakken properties on January 3, 2022, which contributed 108 MBbls in the third quarter of 2021. Gas sales volumes decreased to 429 MMcf for the three months ended September 30, 2022 from 892 MMcf for the same period of 2021. The decrease in gas volumes was primarily due to the sale of our Bakken properties on January 3, 2022, which contributed 477 MMcf in the third quarter of 2021.

Lease Operating Expenses (“LOE”). LOE for the three months ended September 30, 2022 decreased to $2.6 million from $4.6 million for the same period of 2021. The decrease in LOE was primarily due to sale of our Bakken properties on January 3, 2022, which incurred $2.4 million in LOE in the third quarter of 2021. LOE per Boe for the three months ended September 30, 2022 was $12.07 compared to $8.94 for the same period of 2021. The increase per Boe was due primarily to higher cost of services in 2022 as compared to 2021.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended September 30, 2022 decreased to $1.1 million from $1.6 million for the same period of 2021. Production and ad valorem taxes for the three months ended September 30, 2022 were 8% of total oil, gas and NGL sales compared to 7% for the same period of 2021.

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General and Administrative (“G&A”) Expense. G&A expenses, excluding stock-based compensation, increased to $2.3 million for the three months ended September 30, 2022 from $1.7 million for the same period of 2021. G&A per Boe, excluding stock-based compensation, was $10.45 for the quarter ended September 30, 2022 compared to $3.24 for the same period of 2021. The increase in G&A was primarily due to higher legal and professional fees in 2022, as well as severance paid in connection with staff reductions in 2022. The increase in G&A per Boe, excluding stock based compensation, was primarily due to lower sale volumes for the three months ended September 30, 2022 compared to the same period of 2021 as well as higher overall costs.

Stock-Based Compensation. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options’ vesting period. In addition to options, restricted shares of our common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the three months ended September 30, 2022, stock-based compensation was $3.0 million compared to $0.3 million for the period ended September 30, 2021. The increase in stock based was due to the vesting of restricted stock awards made in May 2022 that vested in September 2022 as a result of the change of control that occurred when Biglari Holdings acquired the Preferred Shares from AGEF. As of September 30, 2022 all of our stock-based compensation related to stock options, restricted stock and performance based shares had been fully amortized.

Depreciation, Depletion and Amortization (“DD&A”) Expense. DD&A expense, excluding accretion of future site restoration, for the three months ended September 30, 2022 decreased to $1.6 million from $3.8 million for the same period of 2021. The decrease was primarily due to lower production volumes offset by a lower full cost pool as a result of the impairments recorded in 2020, the sale of the Bakken assets as well as lower future development costs included in the September 30, 2022 internal reserve report. DD&A expense per Boe for the three months ended September 30, 2022 was $7.48 compared to $7.25 in the same period of 2021.

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 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 flow from operating activities. However, such write-downs do impact the amount of our stockholders’ equity and reported earnings. As of September 30, 2022 and September 30, 2021, our net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves.

The risk that we will be required to write-down the carrying value of our oil and gas assets increases when oil and gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves. We cannot assure you that we will not experience additional write-downs in the future.

Interest (Income) Expense. Interest income for the three months ended September 30, 2022 decreased to $0.03 million compared to expense of $8.1 million for the same period of 2021. The decrease in interest expense in 2022 was due to the settlement of our First Lien Credit Facility and the conversion of our Second Lien Credit Facility into preferred stock on January 3, 2022. See Note 4 Long-Term Debt - Restructuring and Note 10. “ Disposition of Assets and Restructuring” to the Consolidated Financial Statements. Interest expense for the three months ended September 30, 2022, relates to the real estate lien note that was paid in full in August 2022.

Loss (Gain) on Derivative Contracts. As of January 1, 2022 we are not party to any derivative agreements. Derivative gains or losses were determined by actual derivative settlements during the period and on the periodic mark to market valuation of derivative contracts in place at period end. For the three months ended September 30, 2021, we recognized a loss on our commodity derivative contracts of $0.3 million.

Income Tax Expense. The Company has recorded full valuation allowances against our deferred tax asset for net operating losses. The Company released a portion of the valuation allowances during the three and nine months ended September 30, 2022, which resulted in not having an income tax expense during the respective periods.

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Comparison of Nine Months Ended September 30, 2022 to Nine Months Ended September 30, 2021

Operating Revenue. During the nine months ended September 30, 2022, operating revenue decreased to $40.0 million from $56.0 million for the same period of 2021. The decrease in revenue was primarily due to lower sales volumes offset by higher commodity prices. Higher realized prices for all products added $24.9 million to operating revenue for the nine months ended September 30, 2022. Lower sales volumes negatively impacted revenue by $40.9 million. Lower sales volumes were primarily due to the sale of our Bakken properties in North Dakota on January 3, 2022. Sales from the Bakken properties contributed 875 MBoe and $27.5 million to revenue in the first nine months of 2021.

Oil sales volumes decreased to 318 MBbl during the nine months ended September 30, 2022 from 743 MBbl for the same period of 2021. The decrease in oil sales volume was primarily due to the sale of our Bakken properties on January 3, 2022, which contributed 360 MBbls during the nine months ended September 30, 2021, as well as natural field declines and no new production during the first nine months of 2022. Gas sales volumes decreased to 1,154 MMcf for the nine months ended September 30, 2022 from 2,595 MMcf for the same period of 2021. The decrease in gas volumes was primarily due to the sale of our Bakken properties on January 3, 2022, which contributed 1,391 MMcf in the nine months ended September 30, 2021.

Lease Operating Expenses (“LOE”). LOE for the nine months ended September 30, 2022 decreased to $7.7 million from $13.1 million for the same period of 2021. The decrease in LOE was primarily due to the sale of our Bakken properties on January 3, 2022, which incurred $6.0 million in LOE in the nine months ended September 30, 2021. LOE per Boe for the nine months ended September 30, 2022 was $12.66 compared to $8.48 for the same period of 2021. The increase per Boe was due primarily to higher cost of services in 2022 as compared to 2021, as well as lower sales volumes in 2022.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the nine months ended September 30, 2022 decreased to $3.4 million from $4.6 million for the same period of 2021. Production and ad valorem taxes for the nine months ended September 30, 2022 were 9% of total oil, gas and NGL sales for the nine months ended September 30, 2022 as compared to 8% for the same period of 2021.

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General and Administrative Expense. G&A expenses, excluding stock-based compensation, was $5.8 million for the nine months ended September 30, 2022 compared to $5.5 million for the same period of 2021. G&A per Boe, excluding stock-based compensation, was $9.46 for the nine months ended September 30, 2022 compared to $3.55 for the same period of 2021. The increase in G&A was primarily due to higher legal and professional fees as well as severance paid in connection with staff reductions. The increase in G&A per Boe, excluding stock based compensation, was primarily due to lower sales volumes for the nine months ended September 30, 2022 compared to the same period of 2021.

Stock-Based Compensation. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options’ vesting period. In addition to options, restricted shares of our common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the nine months ended September 30, 2022, stock-based compensation was $3.3 million compared to $0.8 million for the period ended September 30, 2021. The increase in stock based compensation was due to the vesting of restricted stock awards made in May 2022 that vested in September 2022 as a result of the change of control that occurred when Biglari Holdings acquired the Preferred Shares from AGEF. As of September 30, 2022 all stock- based compensation related to stock options, restricted stock and performance based shares had been fully amortized.

Depreciation, Depletion and Amortization Expense. DD&A expense, excluding accretion of future site restoration, for the nine months ended September 30, 2022 decreased to $4.7 million from $11.7 million for the same period of 2021. The decrease was primarily due to lower production volumes offset by a lower full cost pool as a result of the impairments recorded in 2020, the sale of our Bakken assets on January 3, 2022 as well as lower future development cost included in the September 30, 2022 internal reserve report. DD&A expense per Boe for the nine months ended September 30, 2022 was $7.69 compared to $7.59 in the same period of 2021.

Interest Expense. Interest expense for the nine months ended September 30, 2022 decreased to $0.1 million compared to $21.7 million for the same period of 2021. The decrease in interest expense in 2022 was due to the settlement of our First Lien Credit Facility and the conversion of our Second Lien Credit Facility into preferred stock on January 3, 2022. See Note 4 “ Long-Term Debt - Restructuring and Note 10.” Disposition of Assets and Restructuring” to the Consolidated Financial Statements.

Loss (Gain) on Derivative Contracts. As of January 1, 2022 we are not party to any derivative agreements. Derivative gains or losses were determined by actual derivative settlements during the period and on the periodic mark to market valuation of derivative contracts in place at period end. For the nine months ended September 30, 2021, we recognized a loss on our commodity derivative contracts of $32.9 million, including a loss of $7.1 million related to the termination of existing contracts during the second quarter of 2021.

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Liquidity and Capital Resources

General. The oil and gas industry is a highly capital intensive and cyclical business. Our capital requirements are driven principally by our obligations to fund production and transportation facilities.

Working Capital (Deficit). At September 30, 2022, our current assets of $34.4 million exceed our current liabilities of $12.0 million, resulting in a working capital surplus of $22.4 million. This compares to a working capital deficit of $216.0 million at December 31, 2021. Current assets as of September 30, 2022 primarily consisted of cash of $25.1 million, accounts receivable of $5.4 million assets held for sale of $3.1 million, and other current assets of $0.9 million. Current liabilities at September 30, 2022 primarily consisted of trade payables of $8.3 million, including $5.9 million in post-closing costs related to the sale of our North Dakota Bakken properties on January 3, 2022, revenues due third parties of $3.0 million and other accrued expenses of $0.8 million.

Capital Expenditures. Capital expenditures for the nine months ended September 30, 2022 and 2021 were $1.1 million and $0.9 million respectively.

The table below sets forth the components of these capital expenditures:

	Nine Months Ended September 30,
	2022		2021
	(In thousands)
Expenditure category:
Exploration/Development	$	1,060	$	850
Facilities and other		24		6
Total	$	1,084	$	856

During the nine months ended September 30, 2022 and 2021, our capital expenditures were primarily on our existing properties.

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Sources 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:

	Nine Months Ended September 30,
	2022			2021
	(In thousands)
Net cash provided by operating activities	$	22,636		$	19,876
Net cash provided by (used in) investing activities		71,600			(483	)
Net cash used in financing activities		(79,169	)		(13,117	)
Total	$	15,067		$	6,276

Operating activities for the nine months ended September 30, 2022 provided $22.6 million in cash compared to providing $19.9 million in the same period of 2021. Higher net income and changes in operating assets and liabilities accounted for most of these funds. Investing activities provided $71.6 million during the nine months ended September 30, 2022, primarily from sales of oil and gas properties in North Dakota as well as various non-oil and gas assets on January 3, 2022. Investing activities used $0.5 million during the nine months ended September 30, 2021, primarily for the development of our existing properties. Financing activities used $79.2 million for the nine months ended September 30, 2022 primarily for the settlement of the First Lien Credit Facility in connection with the Restructuring, compared to using $13.1 million for the same period of 2021,primarily for the reduction of long-term debt. See Note 4 “ Long-Term Debt – Restructuring” and Note 10 “Disposition of Assets and Restructuring” to the Consolidated Financial Statements.

We maintain a reserve for costs associated with future site restoration related to the retirement of tangible long-lived assets. At September 30, 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 Condensed Consolidated Financial Statements.

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Off-Balance Sheet Arrangements. At September 30, 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 September 30, 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 (in thousands):

	September 30, 2022		December 31, 2021

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
Total long term debt		-		218,822
Less current maturities		-		(212,688	)
		-		6,134
Deferred financing fees and debt issuance cost, net		-		(3,929	)
Total long-term debt, net of deferred financing fees and debt issuance costs	$	-	$	2,205

Restructuring

Pursuant to the Exchange Agreement, dated as of January 3, 2022, between Abraxas and AGEF and certain other agreements entered into by Abraxas on January 3, 2022, we effectuated a restructuring of our then-existing indebtedness through a multi-part interdependent 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 after customary closing adjustments) (the “Sale”), (ii) the pay down of the indebtedness and other obligations of Abraxas and its subsidiaries under the First Lien Credit Facility, by and among Abraxas, the financial institutions party thereto as lenders, and Société Générale, as “Issuing Lender” and administrative agent and certain specified secured hedges from the proceeds of the Sale and, to the extent necessary, other cash of Abraxas; and (iii), a debt for equity exchange of the indebtedness and other obligations of Abraxas and its subsidiaries under the Second Lien Credit Facility, by and among Abraxas, the financial institutions party thereto as lenders, and Angelo Gordon Energy Servicer, LLC, as administrative agent and all related loan and security documents (the “Exchange” and, together with the transactions referred to in clauses (i) and (ii), the “Restructuring”).

On September 13, 2022, AGEF and Biglari Holdings entered into the Sale and Assignment. Following Biglari Holdings’ acquisition of the Preferred Shares in the Sale and Assignment, 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 Sale and Assignment, Biglari Holdings proposed the Second Exchange, 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. 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 Series A Preferred Stock of the Company then outstanding, by delivering a Stock Power and Assignment to the Company. The Company cancelled the Preferred Shares and the Preferred Stock Certificate of Designation, such that only common stock of the Company remains outstanding. The foregoing description of the Second Exchange and the Second Exchange Agreement is a summary only, does not purport to be complete, and is qualified in its entirety by reference to the complete text of the Second Exchange Agreement, which is filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 3, 2022, and is incorporated by reference herein.

See Note 4 “Long-Term Debt - Restructuring” and Note 10 “Disposition of Assets and Restructuring” to the Consolidated Financial Statements.

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 real estate lien note was paid in full on August 3, 2022.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Commodity Price Risk

As an independent oil and gas producer, our revenue, cash flow 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 indexes 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 nine months ended September 30, 2022, a 10% decline in oil and gas prices would have reduced our operating revenue, cash flow and net income by approximately $13.3 million. If commodity prices decline from current levels, the impact on operating revenues and cash flow, could be much more significant.

Interest Rate Risk

The Company has no outstanding debt at September 30, 2022; accordingly we are not currently subject to interest rate risk.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through our trade receivables.

We are subject to risks of loss from nonpayment or nonperformance by our customers. Continued volatility in both credit and commodity markets may reduce the liquidity of our customer base, which may impact our ability to collect accounts receivable. Accounts receivable are generally from companies with significant oil and gas marketing or operating activities. While we perform ongoing credit evaluations of our customers, we generally do not require our customers to post collateral.

We also maintain any cash and cash equivalents in excess of federally insured limits in prominent financial institutions that we consider to be of high credit quality.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e)and 15d-15(e)) and concluded that the disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal controls over financial reporting during the nine months ended September 30, 2022 covered by this report that could materially affect, or are reasonably likely to materially affect, our financial reporting.

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PART II

Item 1. Legal Proceedings.

From time to time, we are involved in litigation relating to claims arising out of its operations in the normal course of business. At September 30, 2022, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse impact on our financial position or results of operations.

Item 1A. Risk Factors.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2021, which could materially affect our business, financial condition or future results. Except as set forth below, there have been no material changes from the risk factors disclosed in our Annual Report on Form 10-K. The risks described in our Annual Report on Form 10-K and below are not the only risks facing Abraxas. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

By controlling a majority of the voting power of the Company’s outstanding capital stock and a majority of the Company’s Board, Biglari Holdings can control all major corporate decisions for the Company, and its interests may conflict with those of other holders of our capital stock.

On October 26, 2022, 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 Biglari Holdings assigned and transferred the Preferred Shares to the Company, constituting all of the Series A Preferred Stock of the Company then outstanding. The Company cancelled the Preferred Shares and the Preferred Stock Certificate of Designation, such that only common stock of the Company remains outstanding. As a result of the foregoing, 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. For so long as Biglari Holdings continues to hold a majority of the voting power through its capital stock ownership and representation on the Board, Biglari Holdings will exercise a controlling influence over our business and affairs and will have the power to determine all matters submitted to a vote of our stockholders. Biglari Holdings could cause corporate actions to be taken that conflict with the interests of other stockholders, and the concentration of ownership by Biglari Holdings could deter or hinder a change in control transaction that might otherwise benefit our other stockholders.

A deterioration of general macroeconomic conditions could materially and adversely affect our business and financial results.

Our business and financial results are subject to global economic conditions, including any resulting effect on spending and investment by us or our customers. Volatility in the global economic environment has created market uncertainty and the risk of rapid and sudden destabilization. A deterioration of general macroeconomic conditions, including slower growth or recession, diminished liquidity and capital availability, inflation, increases in oil, natural gas, and NGL prices, global supply-chain disruptions, rising interest rates, labor shortages, or decreases in consumer spending power or confidence may harm our business, financial condition, and results of operations.

Our operating results could be adversely affected by natural disasters, public health crises, geopolitical conflicts, or other catastrophic events.

Our business and operations could be negatively impacted to an uncertain degree by: (i) natural disasters, such as freezes, fires, earthquakes, hurricanes, and other adverse weather events, which may increase in frequency and severity due to climate change; (ii) public health crises, including the evolving COVID-19 pandemic and newly declared public health emergencies such as the monkeypox outbreak; and (iii) escalating geopolitical tension. Any disruptions resulting from the foregoing events could also magnify the impact of other risks that we face.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None

Item 3. Defaults Upon Senior Securities.

None

Item 4. Mine Safety Disclosure.

Not applicable

Item 5. Other Information.

None

Item 6. Exhibits.

(a)

Exhibits


	Exhibit 31.1	Certification - Robert L.G. Watson, CEO
	Exhibit 31.2	Certification - G. William Krog, Jr., CAO
	Exhibit 32.1	Certification pursuant to 18 U.S.C. Section 1350 - Robert L.G. Watson, CEO
	Exhibit 32.2	Certification pursuant to 18 U.S.C. Section 1350 - G. William Krog, Jr. CAO
	101.INS	Inline XBRL Instance Document (the Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document)
	101.SCH	Inline XBRL Taxonomy Extension Schema Document
	101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document
	101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document
	101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document
	101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document
	104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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ABRAXAS PETROLEUM CORPORATION

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date	November 14, 2022	By: /s/Robert L.G. Watson
		ROBERT L.G. WATSON,
		President and
		Principal Executive Officer

Date	November 14, 2022	By: /s/G. William Krog, Jr.
		G. WILLIAM KROG, JR.,
		Vice President and
		Principal Accounting and Financial Officer

ABRAXAS PETROLEUM CORP 10-Q