BATTALION OIL CORP

Previous wording

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.

Current wording

The following discussion is intended to assist in understanding our results of operations for the six months ended June 30, 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.

Previous wording

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.

Current wording

We have incurred approximately $3.6 million as of August 8, 2024, and will continue to incur significant costs and expenses, including fees for professional services and other transaction costs, in connection with the Merger.

Previous wording

Shares of preferred stock are convertible, subject to conversion ratios and prices stipulated in the certificate of designation of the preferred stock, at any time by the holders of the preferred stock and by Battalion after meeting certain other agreement requirements. Battalion also has the right to redeem the preferred stock in cash at an amount equal to between 100-120% of the Liquidation Preference ($1,000 per share, or $118.0 million, increased for any PIK accruals) determined according to the redemption date. Additionally, in the event of a change of control, holders of the preferred stock have the right to receive, (i) at any time on or prior to 150 days following the closing date, and at the election of the Company, a cash payment equal to the Liquidation Preference or equity consideration equal to the 107.5% of the Liquidation Preference, or (ii) at any time after 150 days following the closing date, a cash payment equal to between 100-120% of the Liquidation Preference determined by the redemption date or conversion into common stock. Until (i) a termination of or certain amendments to the Amended Term Loan Agreement or (ii) one year past the maturity date of the Amended Term Loan Agreement, an election of the cash payment option by holders in a change of control scenario is not permitted. For additional information, see Note 9, “*Redeemable Convertible Preferred Stock”*to the unaudited condensed consolidated financial statements.

Current wording

Shares of preferred stock are convertible, subject to conversion ratios and prices stipulated in the certificate of designation of the preferred stock, at any time by the holders of the preferred stock and by Battalion after meeting certain other agreement requirements. Battalion also has the right to redeem the preferred stock in cash at an amount equal to between 100-120% of the Liquidation Preference ($1,000 per share, or $138.0 million, increased for any PIK accruals) determined according to the redemption date. Additionally, in the event of a change of control, holders of the preferred stock have the right to receive, (i) at any time on or prior to 150 days following the closing date, and at the election of the Company, a cash payment equal to the Liquidation Preference or equity consideration equal to the 107.5% of the Liquidation Preference, or (ii) at any time after 150 days following the closing date, a cash payment equal to between 100-120% of the Liquidation Preference determined by the redemption date or conversion into common stock. Until (i) a termination of or certain amendments to the Amended Term Loan Agreement or (ii) one year past the maturity date of the Amended Term Loan Agreement, an election of the cash payment option by holders in a change of control scenario is not permitted. For additional information, see Note 9, “*Redeemable Convertible Preferred Stock”*to the unaudited condensed consolidated financial statements.

Previous wording

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 “AGI 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 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.

Current wording

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 “AGI 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 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 H 2 S 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.

Previous wording

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.

Current wording

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 June 30, 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, none of which would occur until the expiration of the current tolling agreement between the parties.

Previous wording

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.

Current wording

The Acid Gas Injection (“AGI”) well and facility have been operational since March 9, 2024 and continued to process gas in the second quarter of 2024. Additional projects have been completed causing interruption in the daily rates, however, the facility has processed over 2.1 Bcf effectively since operational through the second quarter of 2024. The delays during the second quarter of 2024 have resulted in higher than expected gathering and treating costs. It is possible that the existing remedial facility work by WAT could extend past the second quarter of 2024 and any delays in commissioning or shut downs of the plant past the second quarter of 2024 will result in higher processing fees than currently forecast until such time the facility becomes fully operational.

Previous wording

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. Once in service, the GTA has a tiered-rate structure which isexpected to drive a greater than 50 percent reduction in treating fees. Our current estimates of facility in-service dates and future treating fee reductions are subject to various operational and other risk factors, some of which are beyond our control, which could impact the timing and extent of these estimates.

Current wording

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. Once in service, the GTA has a tiered-rate structure which isexpected to drive a greater than 50 percent reduction in treating fees. Our current estimates of facility in-service

Previous wording

Overview. Our ability to execute our operating strategy is dependent on our ability to maintain adequate liquidity and access additional capital, as needed. Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves. Sufficient levels of available cash are required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves. 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.

Current wording

Overview. Our ability to execute our operating strategy is dependent on our ability to maintain adequate liquidity and access additional capital, as needed. Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves. Sufficient levels of available cash are required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves. We generated a net loss of $45.5 million for the six months ended June 30, 2024 and had a negative working capital of $69.1 million as of June 30, 2024. As of June 30, 2024, we had $54.4 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 $52.5 million in debt repayments due through June 2025, including $27.5 million due during the remainder of 2024.

Previous wording

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.

Current wording

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 $62.5 million from the fiscal quarter ending September 30, 2024 through the fiscal quarter ending September 30, 2025 with $12.5 million due at the end of the third quarter of 2024, $15.0 million due at the end of each 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 $97.7 million at maturity on November 24, 2025.

Previous wording

We continue to execute on a plan to reduce operating and capital costs to improve cash flow, includingthe 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. future equity raises), a sale of a portion of our non-core assets, seeking capital partners for our drilling program, pursuing strategic merger opportunities or joint ventures, the sale of the Company, or pursuing additional general and administrative or other cost reduction opportunities. Our estimates and forecasts are based upon assumptions that may prove to be incorrect due to many factors that are currently unknown, such as prevailing economic conditions, many of which are beyond our control.

Current wording

We continue to execute on a plan to reduce operating and capital costs to improve cash flow, includingthe issuance of preferred stock totaling $134.6 million as of June 30, 2024. Changes to our current business estimates and forecasts, based primarily on recent 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, satisfy our debt payment requirements and meet our debt covenant requirements for the next 12 months from the issuance of these 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. We have also obtained a support letter from our three largest current investors to purchase up to $30 million of additional preferred equity securities over the next 12 months. We believe that, based upon our operational forecasts, cash and cash equivalents on hand, cost reduction measures, and the commitment of the investors to purchase up to $30 million in additional preferred equity if needed, 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 condensed consolidated financial statements. We will, however, continue to consider alternative liquidity sources which could include entering into other financing arrangements (e.g. the refinancing of our Amended Term Loan), a sale of a portion of our non-core

Previous wording

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. 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

Current wording

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. 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.

Previous wording

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

Current wording

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

Previous wording

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

Current wording

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.

Previous wording

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.

Current wording

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) through December 31, 2024, and (d) make amendments to certain other affirmative covenants in connection with the foregoing.

Previous wording

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 March 31, 2024 was approximately 12.99%.

Current wording

As of June 30, 2024, we had $160.2 million of indebtedness outstanding and $0.3 million of letters of credit outstanding under the Amended Term Loan Agreement. We currently, as of August 8, 2024, have $160.2 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 June 30, 2024 was approximately 12.95%.

Previous wording

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. 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. 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.

Current wording

Our Amended Term Loan Agreement contains a mandatory repayment schedule with $12.5 million due at the end of the third quarter 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 $97.7 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. 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.

Previous wording

We may be required to make mandatory prepayments of the loans under the Amended Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales, or with cash on hand in excess of certain maximum levels beginning in 2023. 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 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.

Current wording

We may be required to make mandatory prepayments of the loans under the Amended Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales, or with cash on hand in excess of certain maximum levels beginning in 2023. 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 APOD capital expenditures for the succeeding fiscal quarter are excluded for purposes of determining the Consolidated Cash Balance. As of June 30, 2024, the Consolidated Cash Balance, as defined in the Amended Term Loan Agreement and excluding the Specified Additional Equity Capital, did not exceed $20.0 million; therefore, no mandatory prepayment was necessary.

Previous wording

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.

Current wording

At March 31, 2024, subject to the cure provision discussed below, 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.

Previous wording

Operating Activities. 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.

Current wording

Operating Activities. Net cash flows provided by operating activities for the six months ended June 30, 2024 were $33.7 million compared to net cash flows used in operating activities of $8.7 million for the six months ended June 30, 2023. Items impacting operating cash flows were (i) lower total operating revenues resulting from an approximate $0.96 per Boe decrease in average realized prices (excluding the impact of hedging arrangements) and lower production volumes for the six months ended June 30, 2024 compared to the six months ended June 30, 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.

Previous wording

*Investing Activities.*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.

Current wording

*Investing Activities.*Net cash flows used in investing activities for the six months ended June 30, 2024 and 2023 were approximately $45.7 million and $31.7 million, respectively, primarily for drilling and completion activities.

Previous wording

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.

Current wording

During the six months ended June 30, 2024, we spent $44.8 million on oil and natural gas capital expenditures, of which $42.2 million related to drilling and completion costs and $2.0 million related to the development of our treating equipment and gathering support infrastructure. During the first half 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 six months of 2024, we ran one (1) operated rig in the Delaware Basin, drilled and cased four (4) gross (3.73 net), and completed and put online two (2) gross (1.925 net) operated wells. We also received $7.0 million in proceeds from the sale of oil and natural gas assets that were deemed to be unnecessary for future operations.

Previous wording

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.

Current wording

During the six months ended June 30, 2023, we spent $32.6 million on oil and natural gas capital expenditures, of which $28.1 million related to drilling and completion costs and $3.8 million related to the development of our treating equipment and gathering support infrastructure. In the first six months of 2023, we ran one operated rig in the Delaware Basin and completed and put online one operated well.

Previous wording

Financing Activities. 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.

Current wording

Financing Activities. Net cash flows provided by financing activities for the six months ended June 30, 2024 and 2023 were $8.9 million. During the six months ended June 30, 2024, we received $38.8 million from our preferred stock equity issuances and repaid $39.9 million under our Amended Term Loan Agreement. Our net cash flows provided by financing activities during the six months ended June 30, 2024 also reflect the receipt of the $10.0 million distributed from the Merger escrow account to the Company. During the six months ended June 30, 2023, we received $24.4 million from our preferred stock equity issuance and repaid $15.0 million under our Amended Term Loan Agreement.

Previous wording

Operating Revenues. 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.

Current wording

Oil, natural gas and NGLs revenues were $98.6 million and $118.2 million for the six months ended June 30, 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 $0.96 per Boe for the six months ended June 30, 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.

Previous wording

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.

Current wording

Production averaged 12,857 Boe/d and 14,253 Boe/d for the three months ended June 30, 2024 and 2023, respectively, and 12,923 Boe/d and 15,221 for the six months ended June 30, 2024 and 2023, respectively. Production was lower in the second quarter and year to date period 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 June 30, 2024, we put online 4 gross (3.93 net) operated wells while in the twelve months preceding June 30, 2023, we put online 7 gross (6.5 net) operated wells. Also impacting 2024 production volumes was curtailment in Monument Draw due to downstream throughput limitations causing increased downtime and shut-in production.

Previous wording

Lease Operating Expenses. 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.

Current wording

Lease Operating Expenses. Lease operating expenses were $11.0 million and $11.4 million for the three months ended June 30, 2024 and 2023, respectively, and $22.6 million and $23.1 million for the six months ended June 30, 2024 and 2023, respectively. On a per unit basis, lease operating expenses were $9.41 per Boe and $8.76 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $9.61 per Boe and $8.37 per Boe for the six months ended June 30, 2024 and 2023, respectively. The increase in lease operating expenses on a per unit basis in the second quarter and first six months of 2024 is primarily a result of an inflationary market increase in maintenance, power, and chemical costs combined with lower production.

Previous wording

Workover and Other Expenses. 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.

Current wording

Workover and Other Expenses. Workover and other expenses were $1.0 million and $2.6 million for the three months ended June 30, 2024 and 2023, respectively and $1.8 million and $4.0 million for the six months ended June 30, 2024 and 2023, respectively. On a per unit basis, workover and other expenses were $0.81 per Boe and $2.03 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $0.78 per Boe and $1.44 per Boe for the six months ended June 30, 2024 and 2023, respectively. The decreased workover and other expenses in 2024 relate to more significant workover projects undertaken in the prior year.

Previous wording

Taxes Other than Income. 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 $2.53 per Boe and $2.19 per Boe for the three months ended March 31, 2024 and 2023, respectively.

Current wording

Taxes Other than Income. Taxes other than income were $3.3 million and $3.2 million for the three months ended June 30, 2024 and 2023, respectively, and $6.3 million and $6.4 million for thesix months ended June 30, 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 $2.86 per Boe and $2.45 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $2.70 per Boe and $2.31 per Boe for the six months ended June 30, 2024 and 2023, respectively.

Previous wording

Gathering and Other Expenses. 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 $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.

Current wording

Gathering and Other Expenses. Gathering and other expenses were $12.1 million and $16.8 million for the three months ended June 30, 2024 and 2023, respectively, and $29.4 million and $33.3 million for the six months ended June 30, 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 H 2 S 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 $10.36 per Boe and $12.97 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $12.51 per Boe and $12.10 per Boe for the sixmonths ended June 30, 2024 and 2023, respectively. The decrease in gathering and other expenses per Boe for the three months

Previous wording

General and Administrative Expense. 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.

Current wording

General and Administrative Expense. General and administrative expense was $3.3 million and $6.0 million for the three months ended June 30, 2024 and 2023, respectively, and $7.3 million and $11.0 million for the six months ended June 30, 2024 and 2023, respectively. On a per unit basis, general and administrative expenses were $2.82 per Boe and $4.64 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $3.09 per Boe and $3.97 per Boe for the six months ended June 30, 2024 and 2023, respectively. The decreases in general and administrative expense for the three and six months ended June 30, 2024 compared with the prior year periods 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.

Previous wording

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 isprimarily 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.

Current wording

Depletion expense was $12.8 million and $14.4 million for the three months ended June 30, 2024 and 2023, respectively, and $25.4 million and $30.2 million for the six months ended June 30, 2024 and 2023, respectively. On a per unit basis, depletion expense was $10.95 per Boe and $11.07 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $10.82 per Boe and $10.95 per Boe for the six months ended June 30, 2024 and 2023, respectively. The decreases in our depletion rate per Boe isprimarily 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.

Previous wording

For the three months ended March 31, 2024, we recorded a net derivative loss of $24.2 million ($19.8 million net losson 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 gainon 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).

Current wording

For the three months ended June 30, 2024, we recorded a net derivative gain of $1.2 million ($4.4 million net gainon unsettled contracts and $3.2 million net realized loss on settled contracts). For the three months ended June 30, 2023, we recorded a net derivative gain of $4.5 million ($2.4 million net gain on unsettled contracts and $2.1 million net realized gain on settled contracts). For the six months ended June 30, 2024, we recorded a net derivative loss of $22.9 million ($15.3 million net losson unsettled contracts and $7.6 million net realized loss on settled contracts). For the six months ended June 30, 2023, we recorded a net derivative gain of $23.9 million ($23.3 million net gainon unsettled contractsand $0.6 million net realized gain on settled contracts). At June 30, 2024, we had a $10.5 million derivative asset ($5.9 million current) and a $45.2 million derivative liability ($25.6 million current).

Previous wording

Interest Expense and Other. 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.

Current wording

Interest Expense and Other. Interest expense and other was $6.5 million and $9.5 million for the three months ended June 30, 2024 and 2023, respectively, and $13.5 million and $17.3 million for the six months ended June 30, 2024 and 2023, respectively. Interest expense and other primarily decreased in the current year periods compared to the same periods 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 12.95% for the quarter ended June 30, 2024 and 12.97% for the six months ended June 30, 2024. For the third quarter of 2024, our interest rate will be approximately 12.98% on outstanding borrowings.