ABRAXAS PETROLEUM CORP - Quarter Report: 2022 June (Form 10-Q)

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:

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.

GLOSSARY OF TERMS

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

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

Terms used to describe quantities of oil and gas:

“Bbl” – barrel or barrels.

“Bcf” – billion cubic feet of gas.

“Bcfe” – billion cubic feet of gas equivalent.

“Boe” – barrels of oil equivalent.

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

“MBbl” – thousand barrels.

“MBoe” – thousand barrels of oil equivalent.

“Mcf” – thousand cubic feet of gas.

“Mcfe” – thousand cubic feet of gas equivalent.

“MMBbl” – million barrels.

“MMBoe” – million barrels of oil equivalent.

“MMBtu” – million British Thermal Units of gas.

“MMcf” – million cubic feet of gas.

“MMcfe” – million cubic feet of gas equivalent.

“NGL” – natural gas liquids measured in barrels.

 Terms used to describe our interests in wells and acreage:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Part I

FINANCIAL STATEMENTS

Item 1. Financial Statements

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

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

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)

(in thousands, except share and per share data)

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

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands except per share data)

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

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY

(Unaudited)

(in thousands, except share data)

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

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

ABRAXAS PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(tabular amounts in thousands, except per share data)

1. Basis of Presentation

The accounting policies we follow as of January 1, 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 results of operations for the three and six month periods ended June 30, 2022  and the statement of cash flows for the six months ended June 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 six months ended June 30, 2022, (in thousands):

Restricted Stock Awards

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

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. The full text of the new Form of Restricted Stock Award Agreement under the Employee LTIP as of May 2022 is attached to this Form 10-Q as Exhibit 10.1.

AGEF and the Board also granted restrict 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 full text of the new Form of Restricted Stock Award Agreement under the Non-Employee LTIP as of May 2022 is attached to this Form 10-Q as Exhibit 10.2.

The following table summarizes our restricted stock activity for the six months ended June 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. 

Performance Based Restricted Stock

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

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

:

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

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

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

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. The full text of the MIP and the Abraxas Petroleum Corporation Management Incentive Plan Bonus Agreement are attached to this Form 10-Q as Exhibits 10.3 and 10.4, respectively.

Table A –Eligible NEOs

Table B – Aggregate Bonus Amount Calculation

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 June 30, 2022, the net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves.

Restoration, Removal and Environmental Liabilities

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

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

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

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

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.

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.

Significant Judgments

Principal versus Agent

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

Transaction price allocated to remaining performance obligations

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

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

Contract balances

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

To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as “Accounts receivable - Oil and gas production sales” in the accompanying condensed consolidated balance sheets. In this scenario, payment is also unconditional, as we have satisfied our performance obligations through delivery of the relevant product. As a result, we have concluded that our product sales do not give rise to contract assets or liabilities under ASU 2014-09. At June 30, 2022 and December 31, 2021, our receivables from contracts with customers were $7.6 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 six months ended June 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.

For the three and six months ended June 30, 2022, and 2021, there was no income tax benefit due to net operating loss carryforwards (“NOLs”) and we recorded a full valuation allowance against our net deferred tax asset. 

At December 31, 2021, we had, subject to the limitation discussed below, $245.2 million of pre-2018 NOLs and $190.8 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 use of our NOLs will be limited if there is an “ownership change” in our common stock, generally a cumulative ownership change exceeding 50% during a three year period, as determined under Section 382 of the Internal Revenue Code. As of June 30, 2022, we have not had an ownership change in our common stock as defined by Section 382.

Given historical losses, uncertainties exist as to the future utilization of the NOL carryforwards. Therefore, we established a valuation allowance of $117.3 million for deferred tax assets at  December 31, 2021.

As of June 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.

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

4. Long-Term Debt

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

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”). 

AGEF was issued 685,505 shares of Series A Preferred Stock of the Company in the Exchange.   The Series A Preferred Stock has the terms set forth in the Company’s filed Preferred Stock Certificate of Designation (the “Certificate).  Pursuant to the Certificate, any proceeds distributed to the Company’s stockholders or otherwise received in respect of the capital stock of the Company in a merger or other liquidity event will be allocated among the Series A Preferred Stock and the Company’s common stock as follows: (1) first, 100% to the Series A Preferred Stock until the Series A Preferred Stock has received $100 million of proceeds in the aggregate (the “Tier One Preference Amount”), (2) second, 95% to the Series A Preferred Stock and 5% to the Company’s common stock until the Series A Preferred Stock has received $137.1 million, plus a 6.0% annual rate of return thereon from the date of issuance; (3) thereafter, 75% to the Series A Preferred Stock and 25% to the Company’s common stock. The Exchange Agreement entered into in connection with the Restructuring also provides for the potential funding by AGEF of an additional amount up to $12.0 million, if agreed to by AGEF and the disinterested members of the Company’s Board of Directors. Any such additional amount funded would result in an increase to the Tier One Preference Amount equal to 1.5 x the amount of such additional funding. The shares of Series A Preferred Stock vote together as a single class with the Company’s common stock, and each share of Series A Preferred Stock entitles the holder thereof to 69 votes. Accordingly, AGEF’s ownership of the Series A Preferred Stock entitle it to approximately 85% of the voting power of the Company’s current 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.

As a result of the Restructuring, AGEF has the power to exert significant control over the Company by controlling both the majority of the voting power of the Company’s outstanding capital stock and the composition of a majority of the Company’s Board. 

Real Estate Lien Note

We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. The outstanding principal accrues interest at a fixed rate of 4.9%. The note is payable in monthly installments of principal and accrued interest in the amount of $35,672. The maturity date of the note is July 20, 2023. As of  June 30, 2022 and   December 31, 2021,  $2.4  million and $2.5 million, respectively, were outstanding on the note.

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

5. Earnings per Share

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

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 six month periods ended  June 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 June 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:

7. Financial Instruments

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

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.

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. A more detailed description of our significant lease types is included below.

Field Equipment

We rent various field equipment from third parties in order to facilitate the downstream movement of our production from our drilling operations to market. Our compressor and cooler arrangements are typically structured with a non-cancelable primary term of one  year and continue thereafter on a month-to-month basis subject to termination by either party with thirty days’  notice. These leases are considered short term and  are not capitalized. We have a small number of  compressor leases that are longer than  twelve months. We have concluded that our equipment rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term. We enter into daywork contracts for drilling rigs with third parties to support our drilling activities. Our drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells or well pads by providing thirty days’ notice prior to the end of the original contract term. We have concluded that our drilling rig arrangements represent short-term operating leases. The accounting guidance requires us to make an assessment at contract commencement if we are reasonably certain that we will exercise the option to extend the term. Due to the continuously evolving nature of our drilling schedules and the potential volatility in commodity prices in an annual period, our strategy to enter into shorter term drilling rig arrangements allows us the flexibility to respond to changes in our operating and economic environment. We exercise our discretion in choosing to extend or not extend contracts on a rig by rig basis depending on the conditions present at the time the contract expires. At the time of contract commencement, we have determined we cannot conclude with reasonable certainty if we will choose to extend the contract beyond its original term. Pursuant to the full cost method, these costs are capitalized as part of natural gas and oil properties on our balance sheet when paid.

Discount Rate

Our leases typically do not provide an implicit rate. Accordingly, we are required to use our incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our incremental borrowing rate reflects the estimated rate of interest that we would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. We use the implicit rate in the limited circumstances in which that rate is readily determinable.

Practical Expedients and Accounting Policy Elections

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

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

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

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

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

At June 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. 

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 June 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. 

AGEF was issued 685,505 shares of Series A Preferred Stock of the Company in the Exchange.   The Series A Preferred Stock has the terms set forth in the Company’s filed Preferred Stock Certificate of Designation (the “Certificate).  Pursuant to the Certificate, any proceeds distributed to the Company’s stockholders or otherwise received in respect of the capital stock of the Company in a merger or other liquidity event will be allocated among the Series A Preferred Stock and the Company’s common stock as follows: (1) first, 100% to the Series A Preferred Stock until the Series A Preferred Stock has received $100 million of proceeds in the aggregate (the “Tier One Preference Amount”), (2) second, 95% to the Series A Preferred Stock and 5% to the Company’s common stock until the Series A Preferred Stock has received $137.1 million, plus a 6.0% annual rate of return thereon from the date of issuance; (3) thereafter, 75% to the Series A Preferred Stock and 25% to the Company’s common stock. The Exchange Agreement entered into in connection with the Restructuring also provides for the potential funding by AGEF of an additional amount up to $12.0 million, if agreed to by AGEF and the disinterested members of the Company’s Board of Directors. Any such additional amount funded would result in an increase to the Tier One Preference Amount equal to 1.5 x the amount of such additional funding. The shares of Series A Preferred Stock vote together as a single class with the Company’s common stock, and each share of Series A Preferred Stock entitles the holder thereof to 69 votes. Accordingly, AGEF’s ownership of the Series A Preferred Stock entitle it to approximately 85% of the voting power of the Company’s current outstanding capital stock.

Exchange Agreement

On January 3, 2022, the Company and AG Energy Funding, LLC, a Delaware limited liability company (“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.

Any proceeds distributed to the Company’s stockholders or otherwise received in respect of the capital stock of the Company in a merger or other liquidity event will be allocated among the Preferred Stock and the Company’s common stock as follows: (1) first, 100% to the Preferred Stock until the Preferred Stock has received $100 million of proceeds in the aggregate (the “Tier One Preference Amount”), (2) second, 95% to the Preferred Stock and 5% to the Company’s common stock until the Preferred Stock has received $137.1 million (which is equal to the amount of the aggregate Claims outstanding under the Second Lien Debt Agreement) plus a 6.0% annual rate of return thereon from the date hereof; (3) thereafter, 75% to the Preferred Stock and 25% to the Company’s common stock. The Exchange Agreement also provides for the potential funding by AGEF of an additional amount up to $12.0 million, which may be funded following closing if agreed to by AGEF and the disinterested members of the Company’s Board of Directors. Any such additional amount funded will result in an increase to the Tier One Preference Amount equal to 1.5 x the amount of such additional funding. The shares of Preferred Stock will vote together as a single class with the Company’s common stock, and each share of Preferred Stock will entitle the holder thereof to 69 votes. Accordingly, AGEF’s ownership of the Preferred Stock will entitle it to approximately 85% of the voting power of the Company’s outstanding capital stock.

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 Board of Directors of the Company (the “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 and is currently acting as financial advisor to the Board and to the Special Committee of the Board in connection with the proposed Exchange. 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.

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 the acquisition, development and production of oil and gas in the United States. 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. As a result of these activities, we believe that we have a number of development opportunities on our properties. 

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”). 

AGEF was issued 685,505 shares of Series A Preferred Stock of the Company in the Exchange.   The Series A Preferred Stock has the terms set forth in the Company’s filed Preferred Stock Certificate of Designation (the “Certificate).  Pursuant to the Certificate, any proceeds distributed to the Company’s stockholders or otherwise received in respect of the capital stock of the Company in a merger or other liquidity event will be allocated among the Series A Preferred Stock and the Company’s common stock as follows: (1) first, 100% to the Series A Preferred Stock until the Series A Preferred Stock has received $100 million of proceeds in the aggregate (the “Tier One Preference Amount”), (2) second, 95% to the Series A Preferred Stock and 5% to the Company’s common stock until the Series A Preferred Stock has received $137.1 million, plus a 6.0% annual rate of return thereon from the date of issuance; (3) thereafter, 75% to the Series A Preferred Stock and 25% to the Company’s common stock. The Exchange Agreement entered into in connection with the Restructuring also provides for the potential funding by AGEF of an additional amount up to $12.0 million, if agreed to by AGEF and the disinterested members of the Company’s Board of Directors. Any such additional amount funded would result in an increase to the Tier One Preference Amount equal to 1.5 x the amount of such additional funding. The shares of Series A Preferred Stock vote together as a single class with the Company’s common stock, and each share of Series A Preferred Stock entitles the holder thereof to 69 votes. Accordingly, AGEF’s ownership of the Series A Preferred Stock entitle it to approximately 85% of the voting power of the Company’s current outstanding capital stock.

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.

The results of our operations are highly dependent upon the prices received for our oil and gas production. The prices we receive for our production are dependent upon spot market prices, differentials and the effectiveness of our derivative contracts, which we sometimes refer to as hedging arrangements. Substantially all of our sales of oil and gas are made in the spot market, or pursuant to contracts based on spot market prices, and not pursuant to long-term, fixed-price contracts. Accordingly, the prices received for our oil and gas production are dependent upon numerous factors beyond our control. Factors that influence oil and gas prices include the global demand for and global supply of oil, NGL and gas; the implementation of and compliance with production quotas by oil exporting countries; the availability of refining capacity; the price and availability of transportation and pipeline systems; weather conditions, natural disasters, and public health threats; the price and availability of alternative fuel sources; domestic and international drilling activity; geopolitical tensions; and general economic conditions. 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. 

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.

Effects of Inflation and Pricing

The oil and gas industry is characterized by its capital-intensive operations, low supply and demand elasticity, and boom-and-bust cyclical nature. An increase in the price of oil and natural gas generally corresponds to an increase in the costs of producing goods and services that are dependent on oil and natural gas. 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, borrowing-base calculations, capital-raising capabilities, debt and equity financing opportunities, property value in purchase and sale transactions, ability to retain personnel, rate of future growth, and business operations. As the commodity prices of oil and natural gas increase or decrease, we anticipate correlative increases or decreases in the business costs associated with and the demand for exploration, development, and production services.

U.S. inflation has drastically increased over the past year, reaching a new four-decade record peak in June 2022. Interventions to combat inflation, such as interest-rate hikes by the Federal Reserve, escalate the risk of recession and economic slowdown. The U.S. economy experienced negative growth in the first two consecutive quarters of 2022, which by some standards signals a recession. An economic slowdown, or even the perceived risk of an economic slowdown, could cause reductions in the drilling activities of operators and the demand for oil and natural gas. Reduced production or a decline in oil and gas prices could adversely affect our financial condition, results of operations, and cash flows.

During the six months ended June 30, 2022, the NYMEX future price for oil averaged $101.83 per Bbl as compared to $62.22 per Bbl in the same period of 2021. During the six months ended June 30, 2022, the NYMEX future spot price for gas averaged $6.05 per MMBtu compared to $2.85 per MMBtu in the same period of 2021. Prices closed on June 30, 2022 at $105.73 per Bbl of oil and $5.24 per MMBtu of gas, compared to closing on June 30, 2021 at $73.47 per Bbl of oil and $3.65 per MMBtu of gas.  On August 8, 2022, prices closed at$90.76 per Bbl of oil and $7.59 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, including reducing any then existing drilling activities. 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: 

The following table sets forth our average differentials for the six month periods ended June 30, 2022 and 2021:

(1) 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 or conduct successful exploration and development activities.  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.  While we have had some success in finding, acquiring and developing additional reserves, we have not always been able to fully replace the production volumes lost from natural field declines and property sales. Our ability to acquire or find additional reserves in the future will be dependent, upon the amount of available funds for acquisition, exploration and development projects. 

We had capital expenditures during the six months ended June 30, 2022 of $0.7 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 six months ended June 30, 2022, and 2021:

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 six months ended June 30, 2022 and 2021, by our major operating regions:

Availability of Capital.  As described more fully under “Liquidity and Capital Resources” below, our sources of capital are cash flow from operating activities, proceeds from the sale of properties, and if an appropriate opportunity presents itself, credit facilities, or the sale of debt or equity securities, although we may not be able to complete any asset sales or financings 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 June 30, 2022, we had  $2.4  million outstanding under our real estate lien note (including the current portion). The real estate lien note was paid in full on August 3, 2022.

Exploration and Development Activity.  We believe we could access capital to resume development of our assets. We believe that our high quality asset base, high degree of operational control and inventory of drilling projects position us for future growth. 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. We have identified numerous additional drilling locations on our existing leaseholds, the successful development of which we believe could significantly increase our production and proved reserves. Alternatively, given our high quality asset base, we may find attractive opportunities to enter into sale transactions that permit the Company to realize value for the assets that might affect the risks of additional borrowing and uncertain exploration success.

Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that are profitable to produce. The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced unless we acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that we will have any significant exploration and development activities in the near term or that they will result in increases in our proved reserves. If our proved reserves decline in the future, our production may also decline and, consequently, our cash flow from operations will decline. If cash flow declines and we have no access to additional capital, we will be unable to acquire or develop additional reserves or develop our existing undeveloped reserves, in which case our results of operations and financial condition will be adversely affected. Additionally, due to our current lack of liquidity, all of our proved undeveloped reserves are required to be and have been removed from our asset base. 

Results of Operations

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

___________________

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

Operating Revenue. During the three months ended June 30, 2022, operating revenue decreased to $14.5 million from $18.4 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 $7.1  million to operating revenue for the three months ended June 30, 2022.  Lower sales volumes negatively impacted revenue by $11.0  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 291 MBoe and $8.9 million to revenue in the second quarter of 2021. 

Oil sales volumes decreased to 103 MBbl during the three months ended June 30, 2022 from 249 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 119 MBbls.  Gas sales volumes decreased to 372 MMcf for the three months ended June 30, 2022 from 904 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 456 MMcf in the second quarter of 2021.

Lease Operating Expenses (“LOE”). LOE for the three months ended June 30, 2022  decreased to $2.5  million from $4.1 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 $1.8 million in LOE in the second quarter of 2021.  LOE per Boe for the three months ended June 30, 2022 was $12.78 compared to $7.72 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 June 30, 2022 decreased to $1.2  million from $1.7 million for the same period of 2021.  Production and ad valorem taxes for the three months ended June 30, 2022 were 8% of total oil, gas and NGL sales  compared to 9% for the same period of 2021. The decrease in percentage was due to all 2022 production being in Texas, which has a lower tax rate.    

General and Administrative (“G&A”) Expense. G&A expenses, excluding stock-based compensation,  decreased to $1.8 million for the three months ended June 30, 2022  from $2.1 million for the same period of   2021. G&A per Boe, excluding stock-based compensation, was $8.94 for the quarter ended June 30, 2022 compared to $3.92 for the same period of 2021.  The increase in G&A per Boe, excluding stock based compensation, was primarily due to lower sale  volumes for the three months ended June 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 three months ended June 30, 2022, stock-based compensation  was $0.1 million compared to $0.2 million for the period ended June 30, 2021.  As of June 30, 2022 all of our stock based compensation related to stock options and performance based shares had been fully amortized. Expense recognized during the second quarter of 2022 relates to restricted stock awards in May 2022.

Depreciation, Depletion and Amortization (“DD&A”) Expense. DD&A expense, excluding accretion of future site restoration, for the three months ended June 30, 2022  decreased to $1.5 million from  $4.2 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 cost included in the June 30, 2022 internal reserve report.  DD&A expense per Boe for the three months ended June 30, 2022 was $7.74 compared to $7.91 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 June 30, 2022  and  June 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 Expense. Interest expense for the three months ended June 30, 2022 decreased to $0.03 million compared to $7.7 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 5 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. We have elected not to apply hedge accounting to our derivative contracts; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consisted of NYMEX-based fixed price swaps and basis differential swaps as of June 30, 2021. When our derivative contract prices are higher than prevailing market prices, we incur gains and, conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses. For the three months ended June 30, 2021, we recognized a loss on our commodity derivative contracts of $9.9 million, including a loss of $7.1 million upon the termination of existing contracts.

Income Tax Expense. For the three months ended June 30, 2022 and June 30, 2021 there was no income tax expense recognized due to our NOL carryforwards. The Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”),  that was enacted March 27, 2020, includes income tax provisions that allow net operating losses (“NOLs”) to be carried back, allows interest expense to be deducted up to a higher percentage of adjusted taxable income, and modifies tax depreciation of qualified improvement property, among other provisions.  These provisions did not have a material impact on the Company.

Comparison of Six Months Ended June 30, 2022 to Six Months Ended June 30, 2021

Operating Revenue. During the six months ended June 30, 2022, operating revenue decreased to $26.7 million from $35.1 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 $18.8  million to operating revenue for the six months ended June 30, 2022.  Lower sales volumes negatively impacted revenue by $27.2 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 581 MBoe and $17.0 million to revenue in the first half of 2021. 

Oil sales volumes decreased to 213 MBbl during the six months ended June 30, 2022 from 513 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 252 MBbls during the first half of 2022, as well as natural field declines and no new production during the first half of 2022. Gas sales volumes decreased to 725 MMcf for the six months ended June 30, 2022 from 1,703 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 914 MMcf in the first half of 2021.

Lease Operating Expenses (“LOE”). LOE for the six months ended June 30, 2022  decreased to $5.1  million from  $8.5 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 $3.6 million in LOE in the first half of 2021.  LOE per Boe for the six months ended June 30, 2022 was $12.98 compared to $8.24 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 six months ended June 30, 2022 decreased to $2.3  million from $3.1 million for the same period of 2021.  Production and ad valorem taxes for the six months ended June 30, 2022 were 9% of total oil, gas and NGL sales for the six months ended  June 30, 2021 and 2022.    

General and Administrative (“G&A”) Expense. G&A expenses, excluding stock-based compensation,  was $3.5 million for the six months ended June 30, 2022  compared to $3.8 for the same period of   2021. G&A per Boe, excluding stock-based compensation, was $8.91 for the six months ended June 30, 2022 compared to $3.71 for the same period of 2021.  The increase in G&A per Boe, excluding stock based compensation, was primarily due to lower sales  volumes for the six months ended June 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 six months ended June 30, 2022, stock-based compensation  was $0.3 million compared to  $0.5 million for the period ended June 30, 2021.  As of June 30, 2022 all stock based compensation related to stock options and performance based shares had been fully amortized. Expense incurred in the second quarter of 2022 relate to restricted stock awards in May 2022.

Depreciation, Depletion and Amortization (“DD&A”) Expense. DD&A expense, excluding accretion of future site restoration, for the six months ended June 30, 2022  decreased to $3.1 million from $8.0 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 June 30, 2022 internal reserve report. DD&A expense per Boe for the six months ended June 30, 2022 was $7.81 compared to $7.76 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 June 30, 2022  and  June 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 Expense. Interest expense for the six months ended June 30, 2022 decreased to $0.1 million compared to $13.7 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. We have elected not to apply hedge accounting to our derivative contracts; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consisted of NYMEX-based fixed price swaps and basis differential swaps as of June 30, 2021. When our derivative contract prices are higher than prevailing market prices, we incur gains and, conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses. For the six months ended June 30, 2021, we recognized a loss on our commodity derivative contracts of $32.6  million, including a loss of $7.1 million related to the termination of existing contracts during the second quarter of 2021.

Income Tax Expense. For the six months ended June 30, 2022 and June 30, 2021 there was no income tax expense recognized due to our NOL carryforwards. The CARES Act, that was enacted March 27, 2020, includes income tax provisions that allow NOLs to be carried back, allows interest expense to be deducted up to a higher percentage of adjusted taxable income, and modifies tax depreciation of qualified improvement property, among other provisions.  These provisions did not have a material impact on the Company.

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 service debt and to fund the following:

The amount of capital expenditures we are able to make has a direct impact on our ability to increase cash flow from operations and, thereby, will directly affect our ability to grow the business through the development of existing properties and the acquisition of new properties. 

Our principal sources of capital are cash flows from operations, proceeds from the sale of properties, and if an opportunity presents itself, credit facilities, or the sale of debt or equity securities, although we may not be able to sell properties or complete sales or financings on terms acceptable to us, if at all. We believe that our cash flow from these sources going forward, will be adequate to fund our operations.