BATTALION OIL CORP

Previous wording

We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. During 2017, we acquired certain properties in the Delaware Basin and divested our assets located in the Williston Basin in North Dakota and in the El Halcón area of East Texas. As a result, our properties and drilling activities are currently focused in the Delaware Basin, where we have an extensive drilling inventory that we believe offers attractive economics.

Current wording

We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States (“U.S.”). Our properties and drilling activities are currently focused in the Delaware Basin of West Texas, where we have an extensive drilling inventory that we believe offers attractive economics.

Previous wording

When commodity prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. While we use derivative instruments to provide partial protection against declines in oil and natural gas prices, the total volumes we hedge are less than our expected production, vary from period to period based on our view of current and future market conditions, remain consistent with the requirements in effect under our Amended Term Loan Agreement and extend, on a rolling basis, for the next four years. These limitations result in our liquidity being susceptible to commodity price declines. Additionally, while intended to reduce the effects of volatile commodity prices, derivative transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

Current wording

When commodity prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. While we use derivative instruments to provide partial protection against declines in oil and natural gas prices, the total volumes we hedge are less than our expected production, vary from period to period based on our view of current and future market conditions, remain consistent with the requirements in effect under our 2024 Amended Term Loan Agreement and extend, on a rolling basis, for the next four years. These limitations result in our liquidity being susceptible to commodity price declines. Additionally, while intended to reduce the effects of volatile commodity prices, derivative transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

Previous wording

The Amended Term Loan Agreement also contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.

Current wording

Under the 2024 Amended Term Loan Agreement, we are required to hedge approximately 85% to 50% of our anticipated oil and natural gas production, in varying percentages by year, on a rolling basis for the next four years. The 2024 Amended Term Loan Agreement also contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.

Previous wording

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.

Current wording

On December 14, 2023, we entered into the Merger Agreement with Parent and Merger Sub, a Delaware corporation and a direct, wholly owned subsidiary of Parent.

Previous wording

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. 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

Current wording

The Merger Agreement provided, that upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub would merge with and into us, 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”) were to be converted into the right to receive cash, without interest, and such shares would cease to be outstanding, would automatically be canceled and retired and cease to exist; and each outstanding share of redeemable convertible preferred stock would 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.

Previous wording

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.

Current wording

If the Merger was consummated, our shares of Common Stock would no longer trade on the NYSE American and would be deregistered under the Securities Exchange Act of 1934, as amended. As a result, we would have become a private company.

Previous wording

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.

Current wording

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. The distribution was initially recorded as a deposit liability in “Other” long-term liabilities on the consolidated balance sheet. Upon termination of the Merger, the $10.0 million was recognized as “Other income” on the consolidated statement of operations for the year ended December 31, 2024.

Previous wording

We have incurred approximately $3.2 million as of March 20, 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 incurred approximately $5.5 million as of December 31, 2024, in costs and expenses, including fees for professional services and other transaction costs, in connection with the terminated Merger.

Previous wording

*Preferred Stock Equity Issuance.*During the third quarter of 2023, we obtained an additional support letter from the Investors to purchase additional preferred equity securities in an amount up to $55.0 million over the next 12 months and an aggregate of 35,000 shares of preferred stock were sold on December 15, 2023 under such support letter to the Investors for proceeds of $34.1 million, net of $0.9 million of original issue discount.

Current wording

*During the third quarter of 2023, we obtained a support letter from the Investors to purchase additional preferred equity securities in an amount up to $55.0 million over the next 12 months and an aggregate of 35,000 shares of preferred stock were sold on December 15, 2023 under such support letter to the Investors for proceeds of $34.1 million, net of $0.9 million of original issue discount. At December 31, 2023, $20.0 million remained available for issuance under the support letter from the Investors.

Previous wording

On March 27, 2024, we sold, in a private placement, the remaining 20,000 shares under the support letter to the Investors for proceeds of $19.5 million, net of $0.5 million of original issue discount.

Current wording

On March 27, 2024, we sold, in a private placement, the remaining 20,000 shares of preferred stock under the 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.

Previous wording

At December 31, 2023, $20.0 million remained available for issuance under the support letter from the Investors. 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.

Current wording

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. For a further discussion of the redemption and conversion provisions associated with the preferred stock 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.

Previous wording

Shares of preferred stock will be convertible, subject to conversion ratios and prices stipulated in the agreement, at any time by the holders and by Battalion after meeting certain other agreement requirements. Battalion will also have 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, increased for any PIK accruals) determined according to the redemption date. Additionally, in the event of a change of control, holders 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 Item 8.* Consolidated Financial Statements and Supplementary Date – Note 11, Redeemable Convertible Preferred Stock.*

Current wording

Shares of preferred stock will be convertible, subject to conversion ratios and prices stipulated in the agreement, at any time by the holders and by Battalion after meeting certain other agreement requirements. Battalion will also have 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, increased for any PIK accruals) determined according to the redemption date. Additionally, in the event of a change of control, holders 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

Previous wording

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. We initially expected the AGI facility to be mechanically complete in early April 2023 and the facility 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 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 Facility causing higher than expected costs. To fund this workover operation, we advanced capital contributions totaling approximately $15.1 million during the year ended December 31, 2023 on behalf of our joint venture partner in WAT. Pursuant to the terms of the agreement governing the joint venture, we believe 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. We advanced additional capital contributions on behalf of our joint venture partner during the first quarter of 2024 of approximately $3.0 million to fund WAT with the necessary capital required to complete the sidetrack of the AGI well.

Current wording

*In May 2022, we entered into a joint venture agreement with Caracara to develop the AGI Facility in Winkler County, Texas. The joint venture, operating as WAT, also entered into a GTA with us for natural gas production from our Monument Draw area. In exchange for contributing to the joint venturea 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 H 2 S and CO 2. We initially expected the AGI facility to be mechanically complete in early April 2023 and the facility 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

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 pay a treating rate that varies based on volumes delivered to the AGI Facility and have a minimum volume commitment of 20 MMcf per day. The GTA has a tiered-rate structure based on actual volumes delivered. Our current estimates of 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.

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 December 31, 2023, we had $57.5 million of cash and cash equivalents, no additional borrowing capacity under our Amended Term Loan Agreement (in Item 8.Consolidated Financial Statements and Supplementary Date – Note 6, Debt) and a total of $50.0 million in debt repayments due under our Amended Term Loan Agreement through December 2024. At December 31, 2023, $20.0 million remained available for issuance under the support letter from the Investors.

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 $64.1 million for the year ended December 31, 2024 and had negative working capital of $23.6 million as of December 31, 2024. As of December 31, 2024, we had $19.7 million of cash and cash equivalents, $63.0 million of Incremental Term Loans borrowing capacity remaining under our 2024 Amended

Previous wording

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 $95.6 million during 2023. On March 27, 2024, we completed the sale of the additional $19.5 million of available preferred equity securities under the support letter from the Investors received in November 2023. 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, the March 2024 sale of $19.5 million in additional preferred equity and continued 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 Item 8.Consolidated Financial Statements and Supplementary Date – Note 6, Debt for the next 12 months from the issuance of these 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. 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.

Current wording

We continued to execute on a plan to reduce operating and capital costs to improve cash flow, including the issuance of preferred stock totaling $134.6 million during the years ended December 31, 2024 and 2023 and entry into our 2024 Amended Term Loan Agreement. We believe that, based upon our operational forecasts, cash and cash equivalents on hand 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 Item 8.Consolidated Financial Statements and Supplementary Date – Note 7, Debt for the next 12 months from the issuance of these consolidated financial statements. We will, however, continue to consider 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. 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.

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

Previous wording

affected the oil and natural gas industry. 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.

Current wording

*Other Risks and Uncertainties.*Our ability to complete transactions and maintain or increase our liquidity is subject to a number of variables, including our level of oil and natural gas production, proved reserves and commodity prices, the amount and cost of our indebtedness, as well as various economic and market conditions that have historically affected the oil and natural gas industry. 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.

Previous wording

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 U.S. 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. All of the foregoing may adversely affect our business, financial condition, results of operations, cash flows and, potentially, compliance with the covenants contained in our Amended Term Loan Agreement.

Current wording

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 U.S. 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 2024 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. All of the foregoing may adversely affect our business, financial condition, results of operations, cash flows and, potentially, compliance with the covenants contained in our 2024 Amended Term Loan Agreement.

Previous wording

Capital Expenditures. During 2023, we spent approximately $46.6 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs. During 2023, we ran one operated rig in the Delaware Basin. We drilled and completed 2 gross (2 net) operated wells and put online 3 gross (3 net) operated wells during the year.

Current wording

Capital Expenditures. During 2024, we spent approximately $64.6 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs. During 2024, we ran one operated rig in the Delaware Basin. We drilled and cased 4.0 gross (3.95 net) operated wells, completed 4.0 gross (3.95 net), and put online 4.0 gross (3.88 net) operated wells during the year.

Previous wording

As of December 31, 2023, we had $200.0 million of indebtedness outstanding and approximately $0.3 million of letters of credit outstanding under the Amended Term Loan Agreement. We currently, as of March 25, 2024, have $4.7 million available for the issuance of letters of credit. The maturity date of the Amended Term Loan Agreement is November 24, 2025.

Current wording

The maturity date of the 2024 Amended Term Loan Agreement is December 26, 2028.

Previous wording

We may elect, at our option, to prepay any borrowing outstanding under the Amended Term Loan Agreement subject to the following prepayment premiums:

Current wording

We may elect, at our option, to prepay any borrowing outstanding under the 2024 Amended Term Loan Agreement. Such voluntary prepayments, certain mandatory prepayments and change of control prepayments are subject to the following prepayment premium, as applicable:

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, and 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 the 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. As of December 31, 2023, the Consolidated Cash Balance, as defined in the Amended Term Loan Agreement, did not exceed $20.0 million when considering forecasted APOD capital expenditures and cash held in unrestricted subsidiaries; therefore, no mandatory prepayment was necessary.

Current wording

We may be required to make mandatory prepayments of the loans under the 2024 Amended Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales and with excess cash on hand in excess of certain maximum levels. We are required to make scheduled quarterly amortization payments in an aggregate principal amount equal to 2.50% of the aggregate principal amount of the loans outstanding commencing with the fiscal quarter ending June 30, 2025.

Previous wording

We are required to make scheduled amortization payments in the aggregate amount of $85.0 million from the fiscal quarter ending March 31, 2024 through the fiscal quarter ending September 30, 2025 with $10.0 million due at the end of the first quarter of 2024, $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. 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 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

Amounts outstanding under the 2024 Amended Term Loan Agreement are guaranteed by certain of our 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 of the equity interests of the Borrower held by the Company.

Previous wording

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 to address any such issues ahead of time.

Current wording

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

Previous wording

Cash Flow. Net increase (decrease) in cash, cash equivalents and restricted cash is summarized as follows for the periods presented (in thousands):

Current wording

Cash Flow. Net (decrease) increase in cash, cash equivalents and restricted cash is summarized as follows for the periods presented (in thousands):

Previous wording

Investing Activities. Net cash flows used in investing activities for the years ended December 31, 2023 and 2022 were approximately $51.8 million and $126.1 million, respectively.

Current wording

Investing Activities. Net cash flows used in investing activities for the years ended December 31, 2024 and 2023 were approximately $65.4 million and $51.8 million, respectively.

Previous wording

During the year ended December 31, 2022, we spent $125.5 million on oil and natural gas capital expenditures, of which $108.3 million related to drilling and completion costs and $13.7 million related to the development of our treating equipment and gathering support infrastructure.

Current wording

During the year ended December 31, 2024, we spent $64.6 million on oil and natural gas capital expenditures, of which $57.8 million related to drilling and completion costs and $5.7 million related to the development of our treating equipment and gathering support infrastructure.

Previous wording

Financing Activities. Net cash flows provided by financing activities for the years ended December 31, 2023 and 2022 were approximately $59.1 million and $31.8 million, respectively. During the year ended December 31, 2023, we received $95.6 million in proceeds from the sales and issuance of preferred stock and we made $35.0 million of repayments under our Amended Term Loan Agreement.

Current wording

During the year ended December 31, 2023, we received $95.6 million in proceeds from the sales and issuance of preferred stock and we made $35.0 million of repayments under our 2021 Amended Term Loan Agreement.

Previous wording

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States. We also describe the significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with our audit committee. See Item 8.Consolidated Financial Statements and Supplementary Data—Note 1, “Summary of Significant Events and Accounting Policies,” for a discussion of additional accounting policies and estimates made by management.

Current wording

likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under U.S. GAAP. We also describe the significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with our audit committee. See Item 8.Consolidated Financial Statements and Supplementary Data—Note 1, “Summary of Significant Events and Accounting Policies,” for a discussion of additional accounting policies and estimates made by management.

Previous wording

Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation and accretion expense and the full cost ceiling test limitation. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under defined economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

Current wording

Estimates of our proved reserves included in this report are prepared in accordance with U.S. GAAP and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation and accretion expense and the full cost ceiling test limitation. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under defined economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

Previous wording

Our rate of recording depletion expense is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record depletion expense would increase, reducing net income. Such a reduction in reserves may result from calculated lower market prices, which may make it non-economic to drill for and produce higher cost reserves. At December 31, 2023, a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.50 per Boe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.56 per Boe.

Current wording

Our rate of recording depletion expense is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record depletion expense would increase, reducing net income. Such a reduction in reserves may result from calculated lower market prices, which may make it non-economic to drill for and produce higher cost reserves. At December 31, 2024, a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.54 per Boe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.61 per Boe.

Previous wording

Using the first-day-of-the-month average for the 12-months ended December 31, 2023 of the WTI crude oil spot price of $78.21 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended December 31, 2023 of the Henry Hub natural gas price of $2.64 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation would not have generated an impairment at December 31, 2023, holding all other inputs and factors constant. Additionally, a 10% reduction in respective commodity prices at December 31, 2023, while all other factors remained constant, would not have generated an impairment.

Current wording

Using the first-day-of-the-month average for the 12-months ended December 31, 2024 of the WTI crude oil spot price of $76.32 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended December 31, 2024 of the Henry Hub natural gas price of $2.13 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation did not generate an impairment at December 31, 2024, holding all other inputs and factors constant. Based on SEC prices as of March 1, 2025, the prices utilized in the first quarter 2025 full cost ceiling test limitation calculation will be $75.33 per barrel of oil and $2.44 per MMBtu of natural gas. Applying these first quarter 2025 prices and holding all other inputs constant to those used in the calculation of our December 31, 2024 ceiling test, no full cost ceiling limitation impairment is indicated for March 31, 2025. However, a full cost ceiling limitation impairment may still be realized in the future based on the outcome of numerous other factors such as declines in the actual trailing twelve-month SEC prices, production, lower commodity prices, changes in estimated future development costs and operating expenses, and other revisions to our proved reserves. Any such ceiling test impairments in the future could be material to our net earnings.

Previous wording

Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production facilities, gathering systems and related structures and restoration costs. We develop estimates of these costs for each of our properties based upon their geographic location, type of production facility, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis. At December 31, 2023, a five percent increase in future development and abandonment costs would increase the depletion rate by approximately $0.31 per Boe and a five percent decrease in future development and abandonment costs would decrease the depletion rate by $0.31 per Boe.

Current wording

Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production facilities, gathering systems and related structures and restoration costs. We develop estimates of these costs for each of our properties based upon their geographic location, type of production facility, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis. At December 31, 2024, a five percent increase in future development and abandonment costs would increase the depletion rate by approximately $0.34 per Boe and a five percent decrease in future development and abandonment costs would decrease the depletion rate by $0.33 per Boe.

Previous wording

We account for our derivative activities under the provisions of the Financial Accounting Standards Board’s (the “FASB”) Accounting Standards Codification (“ASC” Topic 815,Derivatives and Hedging (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, in accordance with our policy, we may hedge a portion of our

Current wording

We account for our derivative activities under the provisions of the Financial Accounting Standards Board’s (the “FASB”) Accounting Standards Codification (“ASC” Topic 815,Derivatives and Hedging (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, in accordance with our policy, we may hedge a portion of our forecasted oil and natural gas production. We elected to not designate any of our positions for hedge accounting. Accordingly, we record the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in*“Net gain (loss) on derivative contracts”* on the consolidated statements of operations.

Previous wording

Our provision for taxes includes both state and federal taxes. We account for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. We classify all deferred tax assets and liabilities, along with any related valuation allowance, as noncurrent on the consolidated balance sheets.

Current wording

Our provision for income taxes includes both state and federal taxes. We account for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. We classify all deferred tax assets and liabilities, along with any related valuation allowance, as noncurrent on the consolidated balance sheets.

Previous wording

In assessing the need for a valuation allowance on our deferred tax assets, we consider possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. We consider all available evidence (both positive and negative) in determining whether a valuation allowance is required. Based upon the evaluation of available evidence, a valuation allowance of $425.0 million has been applied against our deferred tax asset balance as of December 31, 2023.

Current wording

In assessing the need for a valuation allowance on our deferred tax assets, we consider possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. We consider all available evidence (both positive and negative) in determining whether a valuation allowance is required. Based upon the evaluation of available evidence, a valuation allowance of $317.4 million has been applied against our deferred tax asset balance as of December 31, 2024.

Previous wording

Operating Revenues. Oil, natural gas and natural gas liquids revenues were $218.5 million and $357.4 million for the years ended December 31, 2023 and 2022, respectively. The decrease of $138.9 million in revenue is primarily attributable to a decrease in average realized prices and lower production volumes in 2023 compared to 2022. The decrease is comprised of $38.3 million due to lower production volumes and $100.6 million due to lower average realized prices. 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

Operating Revenues. Oil, natural gas and NGLs revenues were $193.2 million and $218.5 million for the years ended December 31, 2024 and 2023, respectively. The decrease of $25.3 million in revenue is primarily attributable to a $7.6 million decrease resulting from lower average realized prices and a $17.7 million decrease due to lower production volumes in 2024 compared to 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 for the years ended December 31, 2023 and 2022 averaged 13,784 Boe/d and 15,438 Boe/d, respectively. Production is lower in 2023 compared with 2022 in total due largely to the timing of capital expenditures spent to bring new wells online and natural production declines on our existing producing wells. In 2023, we have put online 3 gross (3 net) operated wells while in 2022 we put online 9 gross (8.5 net) operated wells. In addition, 2 of the 3 operated wells we put online in 2023 were put online at the end of December. As such, these wells had minimal impact on 2023 productions. Also impacting 2023 production volumes was curtailment in Monument Draw in the second half of the year due to downstream throughput limitations.

Current wording

Production for the years ended December 31, 2024 and 2023 averaged 12,667 Boe/d and 13,784 Boe/d, respectively. Production is lower in 2024 compared with 2023 in total due largely to the timing of capital expenditures spent to bring new wells online and natural production declines on our existing producing wells. In 2024, we put online 4.0 gross (3.88 net) operated wells while in 2023 we put online 3.0 gross (3.00 net) operated wells. However, two of the four operated wells placed online in 2024 were put online during the fourth quarter. As such, these wells had minimal impact on 2024 production.

Previous wording

Lease Operating Expenses. Lease operating expenses were $44.9 million and $48.1 million for the years ended December 31, 2023 and 2022, respectively. On a per unit basis, lease operating expenses were $8.92 per Boe and $8.54 per Boe for the years ended December 31, 2023 and 2022, respectively. The decrease in lease operating expenses in 2023 results primarily from lower production in 2023 compared to 2022 while the increase year over year in lease operating expenses on a per unit basis is primarily a result of an inflationary market increase in maintenance, power, and chemical costs.

Current wording

Lease Operating Expenses. Lease operating expenses were $45.3 million and $44.9 million for the years ended December 31, 2024 and 2023, respectively. On a per unit basis, lease operating expenses were $9.77 per Boe and $8.92 per Boe for the years ended December 31, 2024 and 2023, respectively. The increase year over year in lease operating expenses and on a per unit basis is primarily a result of an inflationary market increase in maintenance, power, and chemical costs.