What changed in this filing

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Item 2. Management’s Discussion and Analysis

2024-05-15 compared with 2023-11-15 · 133 added, 114 removed, 143 unchanged (63% of the section changed)

MANAGEMENT’S DISCUSSION A ND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations for the three and nine months ended September 30, 2023 and 2022 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

The following discussion is intended to assist in understanding our results of operations for the three months ended March 31, 2024 and 2023 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2023.

The results presented in this Form 10-Q are not necessarily indicative of future operating results.

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Recent Developments

Merger with Fury Resources.

On December 14, 2023, we entered into an Agreement and Plan of Merger, as amended (the “Merger Agreement”) with Fury Resources, Inc., a Delaware corporation (“Parent”) and San Jacinto Merger Sub, Inc.

(“Merger Sub”), a Delaware corporation and a direct, wholly owned subsidiary of Parent.

The Merger Agreement provides, that upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into us (the “Merger”), with us surviving as a wholly owned subsidiary of Parent.

Subject to the terms and conditions set forth in the Merger Agreement, at the effective time of the Merger, each of our issued and outstanding shares of Common Stock, par value $0.0001 per share (“Common Stock”) shall be converted into the right to receive $9.80 in cash, without interest, which represents a total transaction value of approximately $450.0 million (the “Merger Consideration”), and such shares shall otherwise cease to be outstanding, shall automatically be canceled and retired and cease to exist;

and each outstanding share of redeemable convertible

preferred stock will be contributed to Parent in exchange for new preferred shares of Parent, or sold to Parent for cash, in each case at valuation based on the conversion or redemption value of such preferred stock.

If the Merger is consummated, our shares of Common Stock will no longer trade on the NYSE American and will be deregistered under the Securities Exchange Act of 1934, as amended.

As a result, we will become a private company.

On January 24, 2024, Parent and we agreed to cause an amount equal to $10.0 million to be distributed from the escrow account to the Company.

On April 24, 2024, pursuant to an amendment to the Merger Agreement dated April 16, 2024, Parent paid to us $0.1 million to be used by us to pay our costs and expenses associated with printing and mailing the definitive Proxy Statement for the Merger to our stockholders.

On May 3, 2024, Parent provided Equity Financing Subscription Agreements evidencing agreements by the financing sources party thereto to provide an aggregate amount of equity financing to Parent equal to $160.0 million.

Of such $160.0 million equity financing commitments, $10.0 million has been drawn by Parent and was used to fund the initial $10.0 million deposit into escrow at the time the Merger Agreement was signed, and such deposit was released to the Company on January 24, 2024.

With respect to the remaining $150.0 million of equity financing commitments, under the terms of the applicable Equity Financing Subscription Agreements, the obligation of the relevant financing sources to fund their portion of the equity financing is conditioned upon the satisfaction of certain conditions, including Parent entering into Equity Financing Subscription Agreements evidencing an aggregate amount of equity financing equal to $200.0 million and the other parties to such Equity Financing Subscription Agreements providing the related equity funding in escrow concurrently with or prior to the closing of the transactions contemplated by the Merger Agreement.

The obligations of us, Parent and Merger Sub to consummate the Merger are subject to the satisfaction or waiver of certain customary closing conditions, including, among other things:

(a) the absence of any law or order of any Governmental Authority having jurisdiction over a party to the Merger Agreement prohibiting or making illegal the consummation of the Merger, and (b) the adoption of the Merger Agreement by a majority vote of the issued and outstanding shares of Company Common Stock.

We have incurred approximately $3.5 million as of May 9, 2024, and will continue to incur significant costs and expenses, including fees for professional services and other transaction costs, in connection with the Merger.

Preferred Stock Equity Issuance.

On March 28, 2023 and September 6, 2023, we sold, in private placements, an aggregate of 25,000 shares and 38,000 shares, respectively, of Series A Convertible Preferred Stock (the “preferred stock”) to certain funds managed by Luminus Management, LLC, Oaktree Capital Management, LP, and LSP Investment Advisors, LLC, who represent our largest three existing stockholders (the “Investors”).

We received $24.4 million in proceeds, net of $0.6 million in original issue discount, and $37.1 million in proceeds, net of $0.9 million of original issue discount, respectively.

On March 27, 2024, we sold, in a private placement, the remaining 20,000 shares of Series A-3 Convertible Preferred Stock (the “Series A-3 Preferred Stock”) under a commitment letter received during the third quarter of 2023 to certain funds managed by Luminus Management, LLC, Oaktree Capital Management, LP, and LSP Investment Advisors, LLC, who represent our largest three existing stockholders (the “Investors”).

We received $19.5 million in proceeds, net of $0.5 million in original issue discount.

On May 13, 2024, we sold, in a private placement, an aggregate of 20,000 shares of Series A-4 Redeemable Convertible Preferred Stock (the “Series A-4 Preferred Stock”) (together with the Series A-3 Preferred Stock, the “preferred stock”) to the Investors.

We received $19.5 million in proceeds, net of $0.5 million in original issue discount.

The issuances of preferred stock were approved by our board of directors upon recommendation by a special committee of disinterested directors that was established to evaluate the proposed terms of the preferred stock.

On May 14, 2024, proceeds from the sale of the Series A-4 Preferred Stock were used to make a $17.3 million prepayment of outstanding borrowings under the Amended Term Loan Agreement to cure noncompliance of the Total Net Leverage Ratio as of March 31, 2024.

Holders of the preferred stock have no voting rights with respect to the shares of preferred stock.

The preferred stock is entitled to annual dividends, paid either in cash at a fixed rate of 14.5% annually or accrued at a fixed rate of 16.0% annually (“PIK accrual”) at the option of the Company.

Currently, our Amended Term Loan Agreement

prohibits the payment of cash dividends.

The preferred stock is entitled to annual dividends, paid either in cash at a fixed rate of 14.5% annually or accrued at a fixed rate of 16.0% annually (“PIK accrual”) at our option.

Currently, our Amended Term Loan Agreement prohibits the payment of

cash dividends.

Paid in kind (“PIK”) dividends are cumulative, compound and accrue quarterly in arrears and are added to the Liquidation Preference (defined below) of the preferred stock.

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H2S Treating Joint Venture.

In May 2022, we entered into a joint venture agreement with Caracara Services, LLC (“Caracara”) to develop a strategic acid gas treatment and carbon sequestration facility (the “Facility”) in Winkler County, Texas.

The joint venture, operating as Wink Amine Treater, LLC (“WAT”) (previously Brazos Amine Treater, LLC (“BAT”)), has also entered into a Gas Treating Agreement (“GTA”) with us for natural gas production from our Monument Draw area.

In exchange for contributing to the joint venture a wellbore with an approved permit for the injection of acid gas and surface land, we retained a 5% equity interest in WAT, an unconsolidated subsidiary.

Caracara provided the initial capital for the construction of the Facility, which is expected to have an initial capacity of approximately 30 MMcf per day, and a design capacity to treat up to 10% combined concentrations for H2S and CO2.

During commissioning and initial operations, it was determined that additional pressure was required to initiate gas injection.

To correct this issue, a positive displacement pump was ordered and has been installed.

The Facility’s injection well also experienced pressure communication between the tubing and annular space after an injection procedure.

We commenced workover operations to remediate this issue and are exploring alternatives in the event such efforts prove inadequate.

During the third quarter of 2023, additional complications were encountered with the workover operation causing higher than expected costs.

To fund this workover operation, we advanced a capital contribution of $8.05 million on behalf of our joint venture partner in WAT.

Pursuant to the terms of the agreement governing the joint venture, we have multiple remedies to recover such advance, including (1) declaring such payment a loan, which pursuant to the agreement would have an interest rate of the lessor of 15% or the maximum rate permitted by law, (2) recoupment from distributions from the joint venture and (3) reallocation of equity of the joint venture based on the relative level of total capital contributions by the parties after taking into account the advance.

We estimate that we will advance additional capital contributions on behalf of our joint venture partner during the fourth quarter of 2023 of approximately $5.5 million to fund the necessary capital to WAT required to sidetrack the Acid Gas Injection (“AGI”) well.

Our current forecast assumes the AGI facility will be processing 20,000 mcf gas per day in the first quarter of 2024.

It is possible that the existing remedial well work could extend past this estimate.

Any delays in commissioning past the first quarter of 2024 will result in higher processing fees than currently forecast until such time the facility comes online.

Caracara provided the initial capital for the construction of the AGI Facility, which is expected to have an initial capacity of approximately 30 MMcf per day, and a design capacity to treat up to 10% combined concentrations for H2S and CO2.

We initially expected the AGI Facility to be mechanically complete in early April 2023 and to be in service in the second quarter of 2023.

However, during commissioning and initial operations, it was determined that additional pressure was required to initiate gas injection.

To correct this issue, a positive displacement pump was ordered and installed.

The AGI Facility’s injection well also experienced pressure communication between the tubing and annular space after an injection procedure.

We commenced workover operations to remediate this issue.

During the third quarter of 2023, additional complications were encountered with the workover operation at the AGI Facility causing higher than expected costs.

To fund this workover operation, we advanced capital contributions totaling approximately $18.5 million to date as of March 31, 2024 on behalf of our joint venture partner in WAT.

Pursuant to the terms of the agreement governing the joint venture, we believe that we have multiple remedies to recover such advance, including (1) declaring such payment a loan, which pursuant to the agreement would have an interest rate of the lesser of 15% or the maximum rate permitted by law, (2) recoupment from distributions from the joint venture and (3) reallocation of equity of the joint venture based on the relative level of total capital contributions by the parties after taking into account the advance.

Substantially all well work is complete and the facility began treating sour gas on March 9, 2024.

Our current forecast assumes the Acid Gas Injection (“AGI’) Facility will continue processing 20,000 Mcf of natural gas per day in the second quarter of 2024.

It is possible that the existing remedial facility work by WAT could extend past this estimate.

Any delays in commissioning or shut downs of the plant past the first quarter of 2024 will result in higher processing fees than currently forecast until such time the facility becomes fully operational.

Under the GTA, we will pay a treating rate that varies based on volumes delivered to the Facility for a term that will last 20 years from the in-service date of the Facility and have a minimum volume commitment of 20 MMcf per day, with certain rollover rights and start-up flexibility, for an initial term of five years from the in service date of the Facility, which can be extended up to seven years under certain conditions.

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Sufficient levels of available cash are required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves.

As of September 30, 2023, we had $42.7 million of cash and cash equivalents, no additional borrowing capacity under the Amended Term Loan Agreement (as defined in Note 5, “ Debt ” to the unaudited condensed consolidated financial statements) and a total of $95.0 million in debt repayments due through September 2025, including $10.0 million due during the remainder of 2023.

As of March 31, 2024, we had $49.0 million of cash and cash equivalents, no additional borrowing capacity under the Amended Term Loan Agreement (as defined in Note 4, “ Debt ” to the unaudited condensed consolidated financial statements) and a total of $55.0 million in debt repayments due through March 2025, including $40.0 million due during the remainder of 2024.

Our Amended Term Loan Agreement contains certain restrictive covenants as well as a mandatory repayment schedule.

We are required to make scheduled payments in the aggregate amount of $75.0 million from the fiscal quarter ending June 30, 2024 through the fiscal quarter ending September 30, 2025 with $12.5 million due at the end of each of the second and third quarters of 2024, $15.0 million due at the end of the fourth quarter of 2024 and the first quarter of 2025, and $10.0 million due at the end of each of the second and third quarters of 2025.

We will be required to make a final payment of $115.0 million at maturity on November 24, 2025.

In November 2022, we were required to seek an amendment to our Term Loan Agreement (as defined in Note 4, “Debt” to the unaudited condensed consolidated financial statements) to alleviate Current Ratio covenant compliance requirements through the first quarter of 2023 as a result of reduced commodity prices, higher interest rates, and the high capital costs experienced in our 2022 drilling program, which are by nature difficult to predict and subject to factors outside our control.

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As a result, we projected near-term future covenant breaches (specifically the Current Ratio) beginning with the first quarter of 2023, coupled with inadequate liquidity resources available to fully fund all of our upcoming obligations, including debt repayments and interest, capital expenditures and operating costs.

In the absence of additional liquidity from other sources with agreeable economic terms, we obtained $24.4 million in March 2023 and $37.1 million in September 2023 of additional preferred equity funding from our three largest existing stockholders.

Changes to our current business estimates and forecasts, based primarily on recent declines in commodity prices and modifications to our planned drilling schedule to achieve better overall well economics, indicate that we will require additional liquidity to continue our operations and meet our debt covenant requirements for the next 12 months from the issuance of these unaudited condensed consolidated financial statements.

In response to these events and conditions, we have continued to execute on a plan to reduce operating and capital costs to improve cash flow, including a reduction in headcount in April 2023 to align with planned drilling activity and the issuance of preferred stock totaling $63.0 million during 2023 .

We have also obtained a support letter from the Investors to purchase up to an additional $55.0 million of preferred equity securities.

When and as needed, we will provide notice to the Investors of our intent to draw the funds necessary to enable us to meet our obligations as they become due.

Management believes that based upon its operational forecasts, cash and cash equivalents on hand, cost reduction measures, and the commitment by the Investors to purchase $55.0 million in additional preferred equity, it is probable that we will have sufficient liquidity to fund our operations, meet our debt requirements and maintain compliance with our future debt covenants as described in Note 5, “ Debt, ” for the next 12 months from the issuance of these unaudited condensed consolidated financial statements.

In the absence of additional liquidity from other sources with agreeable economic terms, we obtained $95.6 million of preferred equity funding during 2023 and an additional $19.5 million during the quarter ended March 31, 2024 from our three largest existing stockholders.

At March 31, 2024, we were not in compliance with the Total Net Leverage Ratio covenant under our Amended Term Loan Agreement.

On May 13, 2024, we issued 20,000 additional shares of preferred equity and received net proceeds of $19.5 million, net of original issue discount and issuance costs.

On May 14, 2024, the proceeds were used to make an optional prepayment of outstanding borrowings in the amount of $17.3 million under the Amended Term Loan Agreement.

Such prepayment cured the noncompliance of the Total Net Leverage Ratio as of March 31, 2024.

We continue to execute on a plan to reduce operating and capital costs to improve cash flow, including the issuance of preferred stock totaling $115.1 million as of March 31, 2024 and the subsequent issuance on May 13, 2024 totaling $19.5 million .

Management believes that based upon its operational forecasts, cash and cash equivalents on hand, including the $10.0 million initial deposit amount under the Merger Agreement released from escrow, and cost reduction measures, it is probable that we will have sufficient liquidity to fund our operations, meet our debt requirements and maintain compliance with our future debt covenants as described in Note 4, “ Debt, ” for the next 12 months from the issuance of these unaudited condensed consolidated financial statements.

We will, however, continue to pursue alternative liquidity sources which could include entering into other financing arrangements (e.g.

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In the event the assumptions underlying our estimates and forecasts prove to be incorrect, our operating plans, capital requirements, and covenant compliance may be adversely impacted.

We continuously monitor changes in market conditions and will continue to adapt our operational and capital plans as necessary to strive to maintain sufficient liquidity, meet our drilling requirements, and selectively develop or expand our acreage position, while meeting our debt obligations and maintaining compliance with our restrictive covenants.

In the event our cash flows are materially less than anticipated or our costs are materially greater than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may be required to curtail drilling, development, land acquisitions and

other activities to reduce our capital spending.

However, significant or prolonged reductions in capital spending will adversely impact our production and may negatively affect our future cash flows.

We continuously monitor changes in market conditions and will continue to adapt our operational plans as necessary to strive to maintain sufficient liquidity, facilitate drilling on our undeveloped acreage position and permit us to selectively expand our acreage, as well as meet our debt obligations and restrictive covenants.

We continue to explore strategic transactions to address these concerns, while also looking at opportunities to significantly reduce expenses in the near term.

In this regard, we continue to consider whether it is advisable to continue to bear the ongoing costs of the listing of our common stock on the NYSE American and of being a reporting company under the Securities Exchange Act of 1934.

In this regard, we have considered whether it is advisable to continue to bear the ongoing costs of the listing of our common stock on the NYSE American and of being a reporting company under the Securities Exchange Act of 1934.

We believe that we currently qualify to suspend these obligations should we elect to do so.

While such a determination has not yet been made, we expect that the cost savings, particularly over the longer term, would be significant.

however, as we have noted in the past (see “ Risk Factors ” in our most recent annual report on Form 10-K), we believe doing so would adversely impact liquidity and the trading price of our common stock.

Accordingly, we will continue to consider the matter while we simultaneously pursue strategic and financial alternatives that may render it unnecessary.

However, there can be no assurance that such efforts will succeed, that we will not find it necessary to delist or cease being a reporting company or that absent additional capital, reducing costs or other material favorable developments, we will not experience liquidity and covenant compliance issues in the future.

We will continue to pursue additional liquidity sources which could include entering into other financing arrangements (e.g.

future equity raises), a sale of a portion of our non-core assets, for example deep rights, pursuing strategic merger opportunities or joint ventures, further reducing our discretionary capital program, or pursuing other general and administrative or other cost reduction opportunities including aligning our workforce headcount with planned drilling activity.

However, there can be no assurance that, absent additional capital, reducing costs or other material favorable developments, we will not experience liquidity and covenant compliance issues in the future.

Other Risks and Uncertainties.

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Even if we are otherwise successful in growing our proved reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.

Additionally, particularly in periods of increasing commodity prices, we continue to be at risk to supply chain issues, including, but not limited to, labor shortages, pipe restrictions and potential delays in obtaining frac and/or drilling related equipment that could impact our business.

Additionally, in periods of increasing commodity prices, we continue to be at risk to supply chain issues, including, but not limited to, labor shortages, pipe restrictions and potential delays in obtaining frac and/or drilling related equipment that could impact our business.

During these periods, the costs and delivery times of rigs, equipment and supplies may also be substantially greater.

The unavailability or high cost of drilling rigs and/or frac crews, pressure pumping equipment, tubulars and other supplies, and of qualified personnel can materially and adversely affect our operations and profitability.

Lastly, actual or anticipated declines in domestic or foreign economic activity or growth rates, regional or worldwide increases in tariffs or other trade restrictions, turmoil affecting the United States or global financial system and markets and a severe economic contraction either regionally or worldwide, resulting from international conflicts, efforts to contain the COVID-19 pandemic or other factors, could materially affect our business and financial condition and impact our ability to finance operations by worsening the actual or anticipated future drop in worldwide oil demand, negatively impacting the price received for oil and natural gas production or adversely impacting our ability to comply with covenants in our Amended Term Loan Agreement.

Lastly, actual or anticipated declines in domestic or foreign economic activity or growth rates, regional or worldwide increases in tariffs or other trade restrictions, turmoil affecting the United States or global financial system and markets and a severe economic contraction either regionally or worldwide, resulting from international conflicts, efforts to contain pandemics or other factors, could materially affect our business and financial condition and impact our ability to finance operations by worsening the actual or anticipated future drop in worldwide oil demand, negatively impacting the price received for oil and natural gas production or adversely impacting our ability to comply with covenants in our Amended Term Loan Agreement.

Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our vendors and suppliers or cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations.

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On November 24, 2021, we and our wholly owned subsidiary, Halcón Holdings, LLC (Borrower) entered into the Term Loan Agreement with Macquarie Bank Limited, as administrative agent, and certain other financial institutions party thereto, as lenders.

On November 14, 2022, we paid approximately $2.4 million and entered into a further Amended Credit Agreement (the “Amended Term Loan Agreement”) with our lenders which modified certain provisions of its original Term Loan Agreement including, but not limited to, our Current Ratio financial covenant, interest rate benchmark, and prepayment premiums, all as further described below.

As of September 30, 2023, we had $210.2 million of indebtedness outstanding and no letters of credit outstanding under the Amended Term Loan Agreement.

We currently, as of November 14, 2023, have $4.7 million available for the issuance of letters of credit.

Agreement including, but not limited to, our Current Ratio financial covenant, interest rate benchmark, and prepayment premiums, all as further described below.

On March 28, 2024, we entered into the Third Amendment to the Amended Term Loan Agreement (the “Third Amendment”) with our lenders.

The Third Amendment, amended the Amended Term Loan Agreement to, among other things, (a) amend the approved plan of development (“APOD”) for certain properties, (b) remove the Proved Developed Producing (“PDP”) Production Test and APOD Economic Test (each defined in the Term Loan Agreement), (c) require the Borrower to receive cash proceeds from equity issuances and/or cash contributions in an aggregate amount of not less than $38.0 million during the period from Amendment Effective Date through March 31, 2024 (the “Specified Additional Equity Capital”), which such Specified Additional Equity Capital shall be excluded from the calculation of Consolidated Cash Balance (as defined in the Term Loan Agreement), and (d) make amendments to certain other affirmative covenants in connection with the foregoing.

As of March 31, 2024, we had $190.0 million of indebtedness outstanding and $0.3 million of letters of credit outstanding under the Amended Term Loan Agreement.

We currently, as of May 14, 2024, have $172.7 million in borrowings outstanding and $4.7 million available for the issuance of letters of credit.

The maturity date of the Amended Term Loan Agreement is November 24, 2025.

Borrowings under the Amended Term Loan Agreement bear a variable interest rate based on the Secured Overnight Financing Rate (“SOFR”) plus 0.15% plus a fixed applicable margin of 7.5%.

The weighted average interest rate on our borrowings for the quarter ended September 30, 2023 was approximately 12.89%.

Our Amended Term Loan Agreement contains a mandatory repayment schedule with $10.0 million due at the end of the fourth quarter in 2023 and first quarter of 2024, $12.5 million due at the end of each of the second and third quarters in 2024 and in the aggregate, $50.0 million due from the third quarter ending September 30, 2024 through the fiscal quarter ending September 30, 2025 as well as a $115.0 million payment due upon maturity.

Amounts outstanding under the Amended Term Loan Agreement are guaranteed by certain of the Borrower’s direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Borrower and such direct and indirect subsidiaries,

and all of the equity interests of the Borrower held by us.

The weighted average interest rate on our borrowings for the quarter ended March 31, 2024 was approximately 12.99%.

Our Amended Term Loan Agreement contains a mandatory repayment schedule with $12.5 million due at the end of each of the second and third quarters in 2024 and in the aggregate, $50.0 million due from the fourth quarter ending December 31, 2024 through the fiscal quarter ending September 30, 2025 as well as a $115.0 million payment due upon maturity.

As part of the Amended Term Loan Agreement there are certain restrictions on the transfer of assets, including cash, to Battalion from the guarantor subsidiaries.

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For each fiscal quarter after January 1, 2023, we are required to make mandatory prepayments when our Consolidated Cash Balance, as defined in the Amended Term Loan Agreement, exceeds $20.0 million.

Until December 31, 2024, the forecasted approved plan of development (“APOD”) capital expenditures for the succeeding fiscal quarter are excluded for purposes of determining the Consolidated Cash Balance.

Until December 31, 2024, the forecasted APOD capital expenditures for the succeeding fiscal quarter are excluded for purposes of determining the Consolidated Cash Balance.

As of March 31, 2024, the Consolidated Cash Balance, as defined in the Amended Term Loan Agreement, did not exceed $20.0 million;

therefore, no mandatory prepayment was necessary.

The Amended Term Loan Agreement also contains certain financial covenants (as defined), including the maintenance of the following ratios:

● Asset Coverage Ratio of not less than 1.80 to 1.00 as of September 30, 2023 and each fiscal quarter thereafter

● Total Net Leverage Ratio of not greater than 2.50 to 1.00 as of September 30, 2023, and each fiscal quarter thereafter, and

● Current Ratio of not less than 1.00 to 1.00, determined as of the last day of any fiscal quarter period, as of September 30, 2023 and for each fiscal quarter thereafter.

As of September 30, 2023, we were in compliance with the financial covenants under the Term Loan Agreement.

The Amended Term Loan Agreement also contains an APOD for our Monument Draw acreage through the drilling and completion of certain wells.

The Amended Term Loan Agreement contains a proved developed producing production test and an APOD economic test which we must maintain compliance with otherwise, subject to any available remedies or waivers, we are required to immediately cease making expenditures in respect of the approved plan of development other than any expenditures deemed necessary by us in respect of no more than six additional approved plan of development wells.

● Asset Coverage Ratio of not less than 1.80 to 1.00 as of March 31, 2024 and each fiscal quarter thereafter

● Total Net Leverage Ratio of not greater than 2.50 to 1.00 as of March 31, 2024, and each fiscal quarter thereafter, and

● Current Ratio of not less than 1.00 to 1.00, determined as of the last day of any fiscal quarter period, as of March 31, 2024 and for each fiscal quarter thereafter.

As of March 31, 2024, we were not in compliance with the Total Net Leverage Ratio covenant but were in compliance with the remaining financial covenants under the Amended Term Loan Agreement.

Under the Amended Term Loan Agreement, we have a right to cure noncompliance with the Total Net Leverage Ratio covenant within 15 days of delivery of financial statements by making an optional prepayment in an amount not greater than the amount required for purposes of complying with the Total Net Leverage Ratio and such prepayment shall not be subject to the applicable prepayment premium.

Once such prepayment is made, the Total Net Leverage Ratio shall be recalculated giving effect to the reduction in the outstanding amount of borrowings as if such prepayment had occurred on the last day of the quarter.

Accordingly, on May 14, 2024, we made a prepayment of outstanding borrowings under the Amended Term Loan Agreement in the amount of $17.3 million resulting in total borrowings outstanding of $172.7 million.

Upon giving effect to such prepayment for the calculation of the Total Net Leverage Ratio at March 31, 2024, we were in compliance with such financial covenant.

The Amended Term Loan Agreement contains an APOD for our Monument Draw acreage through the drilling and completion of certain wells.

The Amended Term Loan Agreement also contains certain events of default, including non-payment;

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Changes in the level and timing of our production, drilling and completion costs, the cost and availability of transportation for our production and other factors varying from our expectations can affect our ability to comply with the covenants under our Amended Term Loan Agreement.

As a consequence, we endeavor to anticipate potential covenant compliance issues and work with our lenders under our Amended Term Loan Agreement to address any such issues ahead of time.

While we have largely been successful in obtaining modifications of our covenants as needed, as evidenced most recently by the amendment of our Term Loan Agreement in November 2022 which reduced the Current Ratio covenant as of September 30, 2022 and each successive quarter through the quarter ended September 30, 2023, there can be no assurance that we will be successful in the future.

In the event we are not successful in obtaining future modifications or

amendments to our covenants, if needed, there is no assurance that we will be successful in implementing alternatives that allow us to maintain compliance with our covenants or that we will be successful in obtaining alternative financing that provides us with the liquidity that we need to operate our business.

As a consequence, we endeavor to anticipate potential covenant compliance issues and work with our lenders to address any such issues ahead of time.

While we have largely been successful in obtaining modifications of our covenants as needed, as evidenced most recently by the Third Amendment in March 2024 and the amendment of our Term Loan Agreement in November 2022 which reduced the Current Ratio covenant as of September 30, 2022 through March 31, 2023, there can be no assurance that we will be successful in the future.

In the event we are not successful in obtaining covenant modifications, if needed, there is no assurance that we will be successful in implementing alternatives that allow us to maintain compliance with our covenants or that we will be successful in obtaining alternative financing that provides us with the liquidity that we need to operate our business.

Even if successful, alternative sources of financing could prove more expensive than borrowings under our Amended Term Loan Agreement.

Net increase (decrease) in cash and cash equivalents is summarized as follows (in thousands):

Nine Months Ended

September 30,

Cash flows provided by operating activities

Net decrease in cash and cash equivalents is summarized as follows (in thousands):

Three Months Ended

Cash flows provided by (used in) operating activities

Cash flows used in investing activities

Cash flows provided by financing activities

Net increase (decrease) in cash, cash equivalents and restricted cash

Net decrease in cash, cash equivalents and restricted cash

Operating Activities .

Net cash flows provided by operating activities for the nine months ended September 30, 2023 and 2022, respectively were $11.1 million and $53.8 million.

Items impacting operating cash flows were (i) lower total operating revenues resulting from an approximate $23.42 per Boe decrease in average realized prices (excluding the impact of hedging arrangements) and lower production volumes for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, partially offset by the impact of settled derivative contracts period over period, (ii) increased operating costs per Boe and increased interest costs in 2023 and (iii) changes in working capital.

Net cash flows provided by operating activities for the three months ended March 31, 2024 were $3.9 million compared to net cash flows used in operating activities of $0.7 million for the three months ended March 31, 2023.

Items impacting operating cash flows were (i) lower total operating revenues resulting from an approximate $2.17 per Boe decrease in average realized prices (excluding the impact of hedging arrangements) and lower production volumes for the three months ended March 31, 2024 compared to the three months ended March 31, 2023, partially offset by the impact of settled derivative contracts period over period, (ii) increased operating costs per Boe and increased interest costs in 2023 and (iii) changes in working capital.

Investing Activities.

Net cash flows used in investing activities for the nine months ended September 30, 2023 and 2022 were approximately $37.1 million and $87.8 million, respectively, primarily for drilling and completion activities.

During the nine months ended September 30, 2023, we spent $36.7 million on oil and natural gas capital expenditures, of which $31.6 million related to drilling and completion costs and $4.1 million related to the development of our treating equipment and gathering support infrastructure.

During the nine months ended September 30, 2023, our cash capital expenditures included amounts related to the drilling and completion activities that occurred in the fourth quarter of 2022.

In the first nine months of 2023, we ran one operated rig in the Delaware Basin and completed and put online one operated well.

We also received $1.2 million in proceeds from the sale of oil and natural gas assets that were deemed to be unnecessary for future operations.

During the nine months ended September 30, 2022, we spent $87.0 million on oil and natural gas capital expenditures, of which $77.5 million related to drilling and completion costs and $6.8 million related to the development of our treating equipment and gathering support infrastructure.

Net cash flows used in investing activities for the three months ended March 31, 2024 and 2023 were approximately $31.8 million and $27.7 million, respectively, primarily for drilling and completion activities.

During the three months ended March 31, 2024, we spent $24.6 million on oil and natural gas capital expenditures, of which $23.7 million related to drilling and completion costs and $0.5 million related to the development of our treating equipment and gathering support infrastructure.

During the first quarter of 2024, our cash capital expenditures included amounts related to the drilling and completion activities that occurred in the fourth quarter of 2023.

In the first quarter of 2024, we ran one operated rig in the Delaware Basin and drilled and cased 2 gross (2 net) operated wells.

During the three months ended March 31, 2023, we spent $28.6 million on oil and natural gas capital expenditures, of which $25.7 million related to drilling and completion costs and $2.4 million related to the development of our treating equipment and gathering support infrastructure.

Financing Activities.

Net cash flows provided by financing activities for the nine months ended September 30, 2023 and 2022 were $35.9 million and $19.2 million, respectively.

During the nine months ended September 30, 2023, we received $61.4 million from our Series A preferred stock equity issuance and repaid $25.1 million under our Amended Term Loan Agreement.

During the nine months ended September 30, 2022, we borrowed $20.1 million under the first delayed draw of the Tern Loan Agreement.

Net cash flows provided by financing activities for the three months ended March 31, 2024 and 2023 were $19.3 million and $18.9 million, respectively.

During the three months ended March 31, 2024, we received $19.5 million from our Series A preferred stock equity issuance and repaid $10.0 million under our Amended Term Loan Agreement.

Our net cash flows provided by financing activities during the three months ended March 31, 2024 also reflect the receipt of the $10.0 million distributed from the Merger escrow account to the Company.

During the three months ended March 31, 2023, we received $24.4 million from our Series A preferred stock equity issuance and repaid $5.0 million under our Amended Term Loan Agreement.

Critical Accounting Policies and Estimates

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Results of Operations

We reported net losses of $53.8 million and $35.7 million for the three and nine months ended September 30, 2023, respectively, and net income of $105.9 million and $26.2 million for the three and nine months ended September 30, 2022, respectively.

The table below sets forth financial information for the periods presented.

Three Months Ended

Nine Months Ended

September 30,

In thousands (except per unit and per Boe amounts)

Net (loss) income

Operating revenues:

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Interest expense and other

Reorganization items, net

Gain (loss) on extinguishment of debt

Net (loss) income

Natural Gas - MMcf

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Operating Revenues.

Oil, natural gas and NGLs revenues were $53.4 million and $171.6 million for the three and nine months ended September 30, 2023, respectively.

Oil, natural gas and NGLs revenues were $98.7 million and $281.4 million for the three and nine months ended September 30, 2022, respectively.

The decrease in revenues is primarily attributable to a decrease in our average realized prices and lower production volumes for the nine months ended in September 30, 2023 compared to the same period in 2022.

Average realized prices (excluding the effects of hedging arrangements) decreased approximately $20.44 per Boe and $23.42 per Boe, respectively, for the three and nine months ended September 30, 2023 when compared with the same periods in 2022.

Oil, natural gas and NGLs revenues were $49.5 million and $64.3 million for the three months ended March 31, 2024 and 2023, respectively.

The decrease in revenues is primarily attributable to a decrease in our average realized prices and lower production volumes in 2024 compared to 2023.

Average realized prices (excluding the effects of hedging arrangements) decreased approximately $2.17 per Boe for the three months ended March 31, 2024 when compared with the same period in 2023.

The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, quality of production, basis differentials and other factors.

Production averaged 12,717 Boe/d and 14,377 Boe/d for the three and nine months ended September 30, 2023 , respectively.

Production averaged 16,228 Boe/d and 15,352 Boe/d for the three and nine months ended September 30, 2022, respectively.

Production was lower for the three and nine months ended September 30, 2023 compared with the same periods in 2022 primarily from midstream disruptions and plant curtailments causing sales per day to be lower on an equivalent basis and natural production declines on producing wells, partially offset by additional operated wells being put online in the third quarter of 2022.

Production averaged 12,989 Boe/d and 16,200 Boe/d for the three months ended March 31, 2024 and 2023, respectively.

Production is lower in the first quarter of 2024 compared with the same period in 2023 due largely to the timing of capital expenditures spent to bring new wells online and natural production declines on our existing producing wells.

Over the twelve months preceding March 31, 2024, we put online 2 gross (2 net) operated wells while in the twelve months preceding March 31, 2023, we put online 10 gross (9.5 net) operated wells.

Also impacting 2024 production volumes was curtailment in Monument Draw due to downstream throughput limitations.

Lease Operating Expenses.

Lease operating expenses were $11.2 million and $34.2 million for the three and nine months ended September 30, 2023, respectively.

Lease operating expenses were $12.3 million and $35.7 million for the three and nine months ended September 30, 2022, respectively.

On a per unit basis, lease operating expenses were $9.53 per Boe and $8.72 per Boe for the three and nine months ended September 30, 2023, respectively.

On a per unit basis, lease operating expenses were $8.22 per Boe and $8.52 per Boe for the three and nine months ended September 30, 2022, respectively.

The increase in lease operating expenses per Boe for the three months and nine months ended September 30, 2023 compared to the prior year resulted primarily midstream disruptions and plant curtailments causing sales per day to be lower on an equivalent basis .

Lease operating expenses were $11.6 million and $11.7 million for the three months ended March 31, 2024 and 2023, respectively.

On a per unit basis, lease operating expenses were $9.80 per Boe and $8.02 per Boe for the three months ended March 31, 2024 and 2023, respectively.

The increase in lease operating expenses on a per unit basis in the first quarter of 2024 is primarily a result of an inflationary market increase in maintenance, power, and chemical costs combined with lower production .

Workover and Other Expenses.

Workover and other expenses were $0.7 million and $4.7 million for the three and nine months ended September 30, 2023, respectively.

Workover and other expenses were $2.6 million and $4.8 million for the three and nine months ended September 30, 2022, respectively.

On a per unit basis, workover and other expenses were $0.60 per Boe and $1.19 per Boe for the three and nine months ended September 30, 2023, respectively.

On a per unit basis, workover and other expenses were $1.71 per Boe and $1.15 per Boe for the three and nine months ended September 30, 2022, respectively.

The decreased workover and other expenses for the three months ended September 30, 2023 relate to more significant workover projects undertaken in the prior year.

Workover and other expenses were $0.9 million and $1.3 million for the three months ended March 31, 2024 and 2023, respectively.

On a per unit basis, workover and other expenses were $0.75 per Boe and $0.92 per Boe for the three months ended March 31, 2024 and 2023, respectively.

The decreased workover and other expenses in 2024 relate to more significant workover projects undertaken in the prior year.

Taxes Other than Income.

Taxes other than income were $3.3 million and $9.7 million for the three and nine months ended September 30, 2023, respectively.

Taxes other than income were $5.6 million and $15.9 million for the three and nine months ended September 30, 2022, respectively.

Taxes other than income were $3.0 million and $3.2 million for the three months ended March 31, 2024 and 2023, respectively.

Severance taxes are based on realized prices and volumes at the wellhead, while ad valorem taxes are tied to the annual valuation of our properties.

As revenues or volumes from oil and natural gas sales increase or decrease, severance taxes on these sales also increase or decrease.

On a per unit basis, taxes other than income were $2.83 per Boe and $2.47 per Boe for the three and nine months ended September 30, 2023, respectively.

On a per unit basis, taxes other than income were $3.76 per Boe and $3.80 per Boe for the three and nine months ended September 30, 2022, respectively.

The decrease in taxes other than income was largely driven by the reduced commodity pricing experienced in 2023 in addition to lower volumes for the three and nine months ended September 30, 2023, compared to the prior year period.

On a per unit basis, taxes other than income were $2.53 per Boe and $2.19 per Boe for the three months ended March 31, 2024 and 2023, respectively.

Gathering and Other Expenses.

Gathering and other expenses were $15.5 million and $48.9 million for the three and nine months ended September 30, 2023, respectively.

Gathering and other expenses were $16.7 million and $47.8 million for the three and nine months ended September 30, 2022, respectively.

Gathering and other expenses were $17.3 million and $16.5 million for the three months ended March 31, 2024 and 2023, respectively.

Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production and operating expenses of our gathering support infrastructure.

Our gathering and other expenses are primarily driven by the amount and location of natural gas production, the concentration of H2S in our sour gas produced, and the amounts paid to treat our sour gas volumes, either through our own hydrogen sulfide treating plant or through third parties.

On a per unit basis, gathering and other expenses were $13.26 per Boe and $12.45 per Boe for the three and nine months ended September 30, 2023, respectively, and $11.16 per Boe and $11.40 per Boe for the three and nine months ended September 30, 2022 ,

respectively.

On a per unit basis, gathering and other expenses were $14.62 per Boe and $11.33 per Boe for the three months ended March 31, 2024 and 2023, respectively.

The increases in gathering and other expenses per Boe are primarily related to midstream disruptions and plant curtailments as well as an increased percentage of total production requiring H2S treatment, compared to 2023, as well as inflationary impacts on costs associated with our own hydrogen sulfide treating plant.

General and Administrative Expense.

General and administrative expense was $3.9 million and $14.8 million for the three and nine months ended September 30, 2023, respectively.

General and administrative expense was $3.8 million and $12.6 million for the three and nine months ended September 30, 2022, respectively.

On a per unit basis, general and administrative expenses were $3.31 per Boe and $3.77 per Boe for the three and nine months ended September 30, 2023, respectively, and were $2.56 per Boe and $2.99 per Boe for the three and nine months ended September 30, 2022, respectively.

The increase in general and administrative expense for the three and nine months ended September 30, 2023 compared with prior year periods is primarily associated with an increase in professional fees, partially offset by a decrease in payroll and benefits in connection with the headcount reduction in April 2023.

General and administrative expense was $4.0 million and $4.9 million for the three months ended March 31, 2024 and 2023, respectively.

On a per unit basis, general and administrative expenses were $3.36 per Boe and $3.37 per Boe for the three months ended March 31, 2024 and 2023, respectively.

The decrease in general and administrative expense for the three months ended March 31, 2024 compared with the prior year period is primarily associated with a decrease in payroll and benefits in connection with the headcount reduction in 2023 partially offset by an increase in legal fees associated with the merger.

Depletion, Depreciation, and Amortization Expense.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period.

Depletion expense was $13.1 million and $43.2 million for the three and nine months ended September 30, 2023, respectively.

Depletion expense was $13.4 million and $35.9 million for the three and nine months ended September 30, 2022, respectively.

On a per unit basis, depletion expense was $11.17 per Boe and $11.02 per Boe for the three and nine months ended September 30, 2023, respectively.

On a per unit basis, depletion expense was $8.97 per Boe and $8.56 per Boe for the three and nine months ended September 30, 2022, respectively.

The increase in our depletion rate per Boe is primarily due to increased future development costs (tied to market and inflationary increases) associated with proved reserve additions relative to the change in proved reserves.

Depletion expense was $12.6 million and $15.8 million for the three months ended March 31, 2024 and 2023, respectively.

On a per unit basis, depletion expense was $10.68 per Boe and $10.84 per Boe for the three months ended March 31, 2024 and 2023, respectively.

The decrease in our depletion rate per Boe is primarily due to a period over period decrease in future development costs associated with proved reserves relative to the associated period over period decrease in proved reserves.

Net (loss) gain on derivative contracts.

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Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the unaudited condensed consolidated statements of operations.

For the three and nine months ended September 30, 2023, respectively, we recorded net derivative losses of $53.7 million and $29.7 million ($46.8 million net loss on unsettled contracts and $6.9 million net realized loss on settled contracts for the three months ended September 30, 2023, and $23.5 million net loss on unsettled contracts and $6.3 million net realized loss on settled contracts for the nine months ended September 30, 2023).

For the three and nine months ended September 30, 2022, respectively, we recorded a net derivative gain of $67.6 million and a net derivative loss of $88.1 million ($102.1 million net gain on unsettled contracts and $34.5 million net realized loss on settled contracts three months ended September 30, 2022, and $23.9 million net gain on unsettled contracts and $112.0 million net realized loss on settled contracts for the nine months ended September 30, 2022).

At September 30, 2023, we had a $6.7 million derivative asset ($4.6 million current) and a $71.5 million derivative liability ($36.4 million current).

For the three months ended March 31, 2024, we recorded a net derivative loss of $24.2 million ($19.8 million net loss on unsettled contracts and $4.4 million net realized loss on settled contracts).

For the three months ended March 31, 2023, we recorded a net derivative gain of $19.5 million ($21.0 million net gain on unsettled contracts offset by $1.5 million net realized loss on settled contracts).

At March 31, 2024, we had a $11.5 million derivative asset ($7.6 million current) and a $50.7 million derivative liability ($28.8 million current).

Interest Expense and Other.

Interest expense and other was $6.9 million and $24.2 million for the three and nine months ended September 30, 2023, respectively.

Interest expense and other was $5.7 million and $13.2 million for the three and nine months ended September 30, 2022, respectively.

Interest expense and other primarily increased in the current year periods due to increased interest rates, an increased average debt balance due to the additional borrowings in April and November of 2022, and amortization/accretion of financing related costs since November 2022 associated with our Amended Term Loan Agreement.

Our weighted average interest rate was approximately 12.89% for the quarter ended September 30, 2023 and 12.56% for the nine months ended September 30, 2023 .

For the fourth quarter of 2023, our interest rate will be approximately 13.04% on outstanding borrowings.

Interest expense and other was $7.0 million and $7.8 million for the three months ended March 31, 2024 and 2023, respectively.

Interest expense and other primarily decreased in the current year period compared to the same period in the prior year due to a lower average debt balance resulting from repayment of borrowings associated with our Amended Term Loan Agreement.

Our weighted average interest rate was approximately 12.99% for the quarter ended March 31, 2024 .

For the second quarter of 2024, our interest rate will be approximately 12.95% on outstanding borrowings .

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis