BATTALION OIL CORP
For the period ended Dec 31, 2025. Filed Mar 23, 2026.
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A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Mar 23, 2026
BATL$0.75+2.8%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-03-31.
0001558370-25-004183
ITEM 7. Management’s discussion and analysis of financial condition and results of operationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-03-23.
0001104659-26-033373
ITEM 7. Management’s discussion and analysis of financial condition and results of operationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 108 previous paragraphs and 99 current paragraphs.
48 unchanged; 30 reworded; 18 added; 23 removed; 7 previous and 3 current paragraphs rearranged.
Tables are not compared: 14 previous and 13 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (18)
Current report
Monument Draw Acquisition
Current report
On March 10, 2026, we entered into a purchase and sale agreement to acquire certain oil and natural gas assets, comprising 7,090 net acres located in Ward County, Texas, from RoadRunner Resource Holding LLC (formerly, Sundown Energy LP) (“RoadRunner”), effective March 1, 2026, in an all-stock transaction. Under the terms of the agreement, upon closing on March 19, 2026, we issued 485,000 shares of our common stock to RoadRunner in exchange for the assets. The acquired acreage is directly adjacent to our existing Monument Draw acreage. The transaction is subject to customary post-closing adjustments.
Current report
Private Placement Equity Offering
Current report
On March 3, 2026, we entered into a definitive agreement to sell in a private placement to an institutional investor 1,800,000 shares of our common stock and 927,273 prefunded warrants for the purchase of common stock at $5.50 per share for total proceeds of $15.0 million. The offering closed on March 4, 2026, on satisfaction of customary closing
Current report
conditions. We intend to use the net proceeds received from the offering for working capital and general corporate purposes.
Current report
West Quito Divestiture
Current report
On December 18, 2025, we entered into an agreement of sale and purchase with MCM Delaware Resources, LLC (“MCM”) to sell substantially all of our oil and natural gas properties and related assets in the West Quito Draw area located in the Southern Delaware Basin in Ward County, Texas (the “West Quito Assets”) for a total sales price of approximately $62.6 million, subject to adjustment for accounting between the effective date of December 1, 2025 and the closing date and other customary adjustments (the “West Quito Divestiture”). The West Quito Divestiture closed on February 24, 2026 for an adjusted sales price of $60.1 million. The West Quito Assets include approximately 6,100 net acres in Ward County, Texas and proved reserves for these properties accounted for approximately 6.0 MMboe, or approximately 10%, of our proved reserves at December 31, 2025. We used $45.6 million of the net proceeds from closing to repay amounts outstanding under the 2024 Amended Term Loan Agreement on February 24, 2026 - $40.0 million pursuant to the Third Amendment and prepayment of $5.6 million for the scheduled quarterly amortization payment for the quarterly period ending March 31, 2026. Pursuant to the Third Amendment, $12.9 million of Reinvestment Proceeds are to be used to acquire additional contiguous non-operated oil and natural gas properties consisting of proved developed reserves in Ward and Winkler Counties, Texas, to fund permitted capital expenditures in the Monument Draw area and/or to fund the drilling and completion of two Monument Draw wells within 180 days after receipt. Should such funds have not been spent within the 180-day period, the Reinvestment Proceeds shall be used to prepay borrowings outstanding under the 2024 Amended Term Loan Agreement.
Current report
On February 24, 2026, we entered into the Third Amendment to our 2024 Amended Term Loan Agreement. Pursuant to the Third Amendment, among other changes specified therein, (a) the lenders consented to the transactions contemplated by the West Quito Divestiture sale agreement; and (b) we were required, upon receipt of the net cash proceeds from the West Quito Divestiture, to prepay the outstanding principal amount of the 2024 Amended Term Loan Agreement borrowings in an aggregate amount equal to $40.0 million. We may retain the remaining net cash proceeds received from the West Quito Divestiture, subject to certain reinvestment requirements, set forth in the Third Amendment
Current report
After significant complications and delays, the AGI Facility began processing gas on March 9, 2024 and treated volumes from March 2024 to August 11, 2025. In addition to general facility downtime, the AGI Facility experienced interruptions in processing due to failure to complete necessary improvement and maintenance projects, including pump and other facility equipment replacement. The AGI Facility processed over 9.3 Bcf of natural gas before ceasing operations. On August 11, 2025, we received notice from WAT that it was ceasing taking deliveries of natural gas and was ceasing operations effective immediately. In response, we temporarily shut-in a portion of our Monument Draw field production while management actively worked to identify and execute on a plan for long-term alternative gas processing. During the fourth quarter of 2025, we concluded that the fair value of our equity method investment in WAT was less than the carrying value of the investment in unconsolidated affiliate asset recorded on our consolidated balance sheet and recorded an impairment of $1.1 million to reduce the carrying value of the investment in unconsolidated affiliate asset to zero as of December 31, 2025.
Current report
We terminated the GTA with WAT on January 19, 2026.
Current report
Following termination of the GTA, we entered into an agreement with a publicly traded large-cap midstream provider to process our natural gas production at an alternative facility. This processing provider has the ability to process substantially all of our natural gas production from Monument Draw.
Current report
On May 30, 2025, we received written notice (the “Notice”) on behalf of the NYSE American indicating that we are no longer in compliance with NYSE American’s continued listing standards. Specifically, the letter stated that we are not in compliance with the continued listing standards set forth in Sections 1003(a)(i) and 1003(a)(ii) of the NYSE American Company Guide (the “Company Guide”). Section 1003(a)(i) requires a listed company to have stockholders’ equity of $2.0 million or more if the listed company has reported losses from continuing operations and/or net losses in two of its three most recent fiscal years. Section 1003(a)(ii) requires a listed company to have stockholders’ equity of $4.0 million or more if the listed company has reported losses from continuing operations and/or net losses in three of its four most recent fiscal years. Our noncompliance resulted from our reporting stockholders’ equity of $(1.8) million as of March 31, 2025, and losses from continuing operations and/or net losses in three of our four most recent fiscal years ended December 31, 2024. We continue to report negative stockholders’ equity at December 31, 2025 of $(32.8) million and additional losses from continuing operations. The Notice further provided that we must submit a plan of compliance (the “Plan”) by June 30, 2025 addressing how we intend to regain compliance with the continued listing standards by November 30, 2026. Such Plan was submitted by the required deadline and our Plan was accepted by the NYSE. The Notice has no immediate impact on the listing of our shares of common stock, which will continue to be listed and traded under the symbol “BATL” on the NYSE American during this period, subject to our compliance with the other listing requirements of the NYSE American. The notice does not affect our ongoing business operations or our reporting requirements with the Securities and Exchange Commission.
Current report
On November 12, 2025, we entered into the Second Amendment, which amended the Applicable Margin (as defined in the 2024 Amended Term Loan Agreement) to be the rate per annum set forth below under the caption “SOFR Loans Spread” or “ABR Loans Spread”, as the case may be, based on the Total Net Leverage Ratio; provided that (a) until the Adjustment Date (the date of delivery of financial statements pursuant to the 2024 Amended Term Loan Agreement) following the Second Amendment effective date, the Applicable Margin shall be the applicable rate per annum set forth below in Category 1 and (b) the Applicable Margin shall be the applicable rate per annum set forth in Category 4 below at any time that an Event of Default (as defined in the 2024 Amended Term Loan Agreement) exists:
Current report
The Second Amendment provides that we shall not permit the Total Net Leverage Ratio, as of the last day of each fiscal quarter (commencing with the fiscal quarter ending March 31, 2025), to be greater than the levels set forth in the following table for the applicable quarter:
Current report
Additionally, the Second Amendment provides that we shall not permit the Asset Coverage Ratio, as of the last day of any fiscal quarter (commencing with the fiscal quarter ending March 31, 2025) to be less than the applicable level set forth in the following table for the applicable fiscal quarter:
Current report
On February 24, 2026, we entered into the Third Amendment to our 2024 Amended Term Loan Agreement. Pursuant to the Third Amendment, among other changes specified therein, (a) the lenders consented to the transactions contemplated by the West Quito Divestiture sale agreement; and (b) we were required, upon receipt of the net cash proceeds from the West Quito Divestiture, to prepay the outstanding principal amount of the 2024 Amended Term Loan Agreement borrowings in an aggregate amount equal to $40.0 million. We may retain the remaining net cash proceeds received from the West Quito Divestiture, subject to certain reinvestment requirements, set forth in the Third Amendment
Current report
The Company’s purchaser, gathering and/or processing, or transportation contracts have no net settlement provisions and no market mechanism to facilitate net settlement. As such, those contracts qualify for the normal purchase and normal sale exception under ASC 815.
Current report
*Asset impairment.*Asset impairment totaled $1.1 million and $18.5 million for the years ended December 31, 2025 and 2024, respectively. During the fourth quarter of 2025, we concluded that the fair value of our equity method investment in WAT was less than the carrying value of the investment in unconsolidated affiliate asset recorded on our consolidated balance sheet and recorded an impairment of $1.1 million to reduce the carrying value of the investment in unconsolidated affiliate asset to zero as of December 31, 2025. During the fourth quarter of 2024, Caracara delivered ademand notice disputing our claims, indicating that the carrying value of the previously recorded contract asset may not be recoverable and as a result, we recognized $18.5 million of impairment of charges to reduce the carrying value of the contract asset to zero as of December 31, 2024.
Removed paragraphs (23)
Previous report
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 on the Initial Closing Date, and subsequently on the amount of the loans outstanding on the Initial Closing Date plus the Incremental Term Loans, commencing with the fiscal quarter ending June 30, 2025. Under the 2024 Amended Term Loan Agreement, we must make scheduled amortization payments in the aggregate amount of $16.9 million in 2025 and $22.5 million in 2026.
Previous report
For the year ended December 31, 2024, we recognized a loss on extinguishment of debt in the amount of $7.5 million resulting from the credit agreement refinancing on December 26, 2024 which includes a $3.6 million non-cash write-off of deferred financing costs, original issue discounts and embedded derivatives associated with the extinguished debt and $3.9 million in fees and debt issuance costs paid for the new debt.
Previous report
Merger with Fury Resources
Previous report
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 report
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 report
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 report
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 report
Subsequent to several amendments to the Merger Agreement and upon failure of Parent to meet the funding and closing requirements of the Merger Agreement, we terminated the Merger Agreement on December 20, 2024.
Previous report
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 report
Preferred Stock Equity Issuance
Previous report
*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 report
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 report
On May 13, 2024, we sold, in a private placement, an aggregate of 20,000 shares of preferred stock to the Investors for $19.5 million in proceeds, net of $0.5 million in original issue discount, and such proceeds were used to make a $17.3 million prepayment of outstanding borrowings under the 2021 Amended Term Loan Agreement to cure noncompliance of the Total Net Leverage Ratio as of March 31, 2024.
Previous report
During the third quarter of 2024, weobtained support letters from the Investors to purchase up to $30.0 million of additional preferred equity securities on or before August 29, 2025 and all remain undrawn.
Previous report
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 report
Holders have no voting rights with respect to the shares of preferred stock. The preferred stock receives annual dividends, paid either in cash at a fixed rate of 14.5% annually or accrued at a fixed rate of 16.0% annually (“PIK accrual”) at our option. Currently, our Amended Term Loan Agreement prohibits the payment of cash dividends. Paid-in-kind (“PIK”) dividends are cumulative, compound and accrue quarterly in arrears and are added to the Liquidation Preference.
Previous report
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 report
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. Consistent with the terms of the 2021 Amended Term Loan Agreement, an election of the cash payment option by holders in a change of control scenario is not permitted until (i) a termination of or certain amendments to the 2024 Amended Term Loan Agreement or (ii) one year past the maturity date of the 2024 Amended Term Loan Agreement. For additional information, see Item 8.* Consolidated Financial Statements and Supplementary Date – Note 12, Redeemable Convertible Preferred Stock.*
Previous report
The AGI Facility has been processing gas since March 9, 2024 and continues to process gas currently. In addition to general facility downtime, the AGI Facility has experienced interruption in processing due to the completion of improvement and maintenance projects, including pump and other facility equipment replacement. The continued processing delays and interruptions in 2024 have resulted in higher processing fees than forecasted as we pay higher processing rates with other service providers.
Previous report
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 report
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 report
Impairment of contract asset. We had advanced total capital contributions of approximately $18.5 million on behalf of our joint venture partner in WAT to fund a workover operation on the AGI Facility, of which $15.1 million was incurred during 2023 and the remaining $3.4 million during 2024. Pursuant to the terms of the agreement governing the joint venture, we have multiple remedies to recover such advance, including (1) declaring such payment a loan, which pursuant to the agreement would have an interest rate of the 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 advances, none of which would occur until the expiration of the current tolling agreement between the parties. Pursuant to such, we initially recorded the advance as a Contract asset in the Consolidated Balance Sheet and assessed the fair value of the contract asset on a quarterly basis for possible impairment. During the fourth quarter of 2024, Caracara delivered a demand notice disputing our claims, indicating that the carrying value of the contract asset may not be recoverable and as a result, we recognized $18.5 million of impairment of charges to reduce the carrying value of the contract asset to zero as of December 31, 2024.
Previous report
*Loss on extinguishment of debt.*On December 26, 2024, we entered into the 2024 Amended Term Loan Agreement to fully refinance and repay our 2021 Amended Term Loan Agreement and recognized a $7.5 million loss on extinguishment of debt, which includes a $3.6 million non-cash write-off of deferred financing costs, original issue discounts and embedded derivatives associated with the extinguished debt and $3.9 million in fees and debt issuance costs paid for the new debt.
Reworded paragraphs (30)
Previous 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.
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. Under the GTA, we were to pay a treating rate that varied based on volumes delivered to the AGI Facility and we had a minimum volume commitment of 20 MMcf per day. The GTA had a tiered-rate structure based on actual volumes delivered. 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 was 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. Workover operations commenced 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 September 30, 2024 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. Pursuant to such, we initially recorded the advanced amount as a contract asset. During the fourth quarter of 2024, Caracara delivered a demand notice disputing our claims, indicating that the carrying value of the contract asset may not be recoverable and as a result, we recognized $18.5 million of impairment of charges to reduce the carrying value of the contract asset to zero at December 31, 2024.
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 September 30, 2024 on behalf of our joint venture partner in WAT. Pursuant to the terms of the agreement governing the joint venture, we believed that we had 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)
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. 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
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 available to common stockholders of $36.8 million for the year ended December 31, 2025 and had negative working capital of $6.5 million as of December 31, 2025. As of December 31, 2025, we had $28.0 million of cash and cash equivalents, no borrowing capacity remaining under our 2024 Amended Term Loan Agreement (see Item 8.Consolidated Financial Statements and Supplementary Date – Note 6, Debt) and a total of $22.5 million in debt repayments due under our 2024 Term Loan Agreement through December 2026. At December 31, 2025, $30.0 million remained available for issuance on or before August 31, 2026 under a support letter from the Investors. We closed on the sale of our West Quito Assets on February 24, 2026 for net proceeds of $60.1 million, of which $45.6 million was used to repay a portion of outstanding borrowings under our 2024 Amended Term Loan Agreement - $40.0 million pursuant to the Third Amendment and prepayment of $5.6 million for the scheduled quarterly amortization payment for the quarterly period ending March 31, 2026. Pursuant to the Third Amendment, $12.9 million of proceeds from the sale (the “Reinvestment Proceeds”) are to be used to acquire additional contiguous non-operated oil and natural gas properties consisting of proved developed reserves in Ward and Winkler Counties, Texas, to fund permitted capital expenditures in the Monument Draw area and/or to fund the drilling and completion of two Monument Draw wells within 180 days after receipt. Should such funds have not been spent within the 180-day period, the Reinvestment Proceeds shall be used to prepay borrowings outstanding under the 2024 Amended Term Loan Agreement. On March 3, 2026, we entered into a definitive agreement to sell in a private placement to an institutional investor 1,800,000 shares of our common stock and 927,273 prefunded warrants for the purchase of common stock at $5.50 per share for total proceeds of $15.0 million. The offering closed on March 4, 2026, on satisfaction of customary closing conditions. We intend to use the net proceeds received from the offering for working capital and general corporate purposes.
Previous wording
Our 2024 Amended Term Loan Agreement contains certain restrictive covenants as well as a mandatory repayment schedule. 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.
Current wording
Our 2024 Amended Term Loan Agreement contains certain restrictive covenants as well as a mandatory repayment schedule. 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 total loans outstanding.
Previous 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.
Current wording
We continue to execute on a plan to reduce operating and capital costs to improve cash flow. We believe that, based upon our operational forecasts, cash and cash equivalents on hand, proceeds from the sale of our West Quito Assets and from theprivate placement equity offering, 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 6 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 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. 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. 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
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.
Current wording
Capital Expenditures. During 2025, we spent approximately $74.6 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs. During 2025, we ran one operated rig in the Delaware Basin. We drilled and cased 6.0 gross (5.6 net) operated wells, completed 6.0 gross (5.6 net), and put online 6.0 gross (5.6 net) operated wells during the year.
Previous wording
Borrowings under the 2024 Amended Term Loan Agreement bear interest at a rate per annum equal to a forward-looking term rate based on SOFR for a tenor of three months (with a credit spread adjustment of 0.15% per annum) (or another applicable reference rate, as determined pursuant to the terms of the 2024 Amended Term Loan Agreement) plus an applicable margin of 7.75%.
Current wording
Borrowings under the 2024 Amended Term Loan Agreement initially bore interest at a rate per annum equal to a forward-looking term rate based on SOFR for a tenor of three months (with a credit spread adjustment of 0.15% per annum) (or another applicable reference rate, as determined pursuant to the terms of the 2024 Amended Term Loan Agreement) plus an applicable margin of 7.75%.
Previous 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.
Current wording
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. 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. Subsequent to the closing of the West Quito Divestiture on February 24, 2026, we used $40.0 million of the net proceeds as prepayment of the loan per the terms of the Third Amendment.
Previous wording
Operating Activities. Net cash flows provided by operating activities for the years ended December 31, 2024 and 2023 were $35.4 million and $17.6 million, respectively. Operating cash flows for the year ended December 31, 2024 increased from the prior year primarily due to lower gathering and transportation expense, decreased interest expense associated with lower outstanding debt balance during the year, the inclusion of the merger termination payment of $10.0 million and changes in working capital. The increase in operating cash flows in 2024 were partially offset by decreased oil and natural gas revenues as a result of lower realized commodity prices and lower production volumes than the comparable prior year period.
Current wording
Operating Activities. Net cash flows provided by operating activities for the years ended December 31, 2025 and 2024 were $39.1 million and $35.4 million, respectively. Operating cash flows for the year ended December 31, 2025 increased from the prior year primarily due to lower gathering and transportation expense and changes in working capital. The increase in operating cash flows in 2025 were partially offset by decreased oil and natural gas revenues as a result of lower realized commodity prices and lower production volumes than the comparable prior year period.
Previous 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.
Current wording
Investing Activities. Net cash flows used in investing activities for the years ended December 31, 2025 and 2024 were approximately $75.0 million and $65.4 million, respectively.
Previous wording
During the year ended December 31, 2023, we spent $46.3 million on oil and natural gas capital expenditures, of which $40.4 million related to drilling and completion costs and $4.7 million related to the development of our treating equipment and gathering support infrastructure.
Current wording
During the year ended December 31, 2025, we spent $74.6 million on oil and natural gas capital expenditures, of which $61.7 million related to drilling and completion costs and $11.4 million related to the development of our treating equipment and gathering support infrastructure.
Previous wording
Financing Activities. Net cash flows used in financing activities for the year ended December 31, 2024 were $7.7 million compared to net cash flows provided by financing activities for the year ended December 31, 2023 of $59.1 million. During the year ended December 31, 2024, prior to the refinancing transaction, we made principal payments of $52.4 million under our 2021 Amended Term Loan Agreement. On December 26, 2024, we entered into the 2024 Term Loan Agreement, incurring $162.0 million in borrowings, which such proceeds were used to repay all amounts outstanding under the 2021 Amended Term Loan Agreement in the amount of $147.7 million. Additionally, we incurred $8.2 million of debt issuance costs related to the new credit agreement. We received $38.8 million in proceeds from the sales and issuance of preferred stock during the year ended December 31, 2024.
Current wording
During the year ended December 31, 2024, prior to the refinancing transaction, we made principal payments of $52.4 million under our 2021 Amended Term Loan Agreement. On December 26, 2024, we entered into the 2024 Term Loan Agreement, incurring $162.0 million in borrowings, which such proceeds were used to repay all amounts outstanding under the 2021 Amended Term Loan Agreement in the amount of $147.7 million. Additionally, we incurred $8.2 million of debt issuance costs related to the new credit agreement. We received $38.8 million in proceeds from the sales and issuance of preferred stock during the year ended December 31, 2024.
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 U.S. (“U.S. GAAP”). 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
Current 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 U.S. (“U.S. GAAP”). 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
Previous 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.
Current wording
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, “Financial Statement Presentation and Summary of Significant Accounting Policies,” for a discussion of additional accounting policies and estimates made by management.
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, 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.
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, 2025, a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.52 per Boe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.56 per Boe.
Previous 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.
Current wording
Using the first-day-of-the-month average for the 12-months ended December 31, 2025 of the WTI crude oil spot price of $66.01 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, 2025 of the Henry Hub natural gas price of $3.39 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, 2025, holding all other inputs and factors constant. Based on SEC prices as of March 1, 2026, the prices utilized in the first quarter 2026 full cost ceiling test limitation calculation will be $63.80 per barrel of oil and $3.72 per MMBtu of natural gas. Applying these first quarter 2026 prices and holding all other inputs constant to those used in the calculation of our December 31, 2025 ceiling test, no full cost ceiling limitation impairment is indicated for March 31, 2026. 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, 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.
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, 2025, a five percent increase in future development and abandonment costs would increase the depletion rate by approximately $0.25 per Boe and a five percent decrease in future development and abandonment costs would decrease the depletion rate by $0.26 per Boe.
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 $317.4 million has been applied against our deferred tax asset balance as of December 31, 2024.
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 $316.4 million has been applied against our deferred tax asset balance as of December 31, 2025.
Previous 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.
Current wording
Operating Revenues. Oil, natural gas and NGLs revenues were $165.0 million and $193.2 million for the years ended December 31, 2025 and 2024, respectively. The decrease of $28.3 million in revenue is primarily attributable to a $19.6 million decrease resulting from lower average realized prices and an $8.7 million decrease due to lower production volumes in 2025 compared to 2024. 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, 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.
Current wording
Production for the years ended December 31, 2025 and 2024 averaged 12,096 Boe/d and 12,667 Boe/d, respectively. Production is lower in 2025 compared with 2024 in total due largely to natural production declines on our existing producing wells and curtailed production resulting from the AGI Facility complications. In 2025, we put online 6.0 gross (5.6 net) operated wells while in 2024 we put online 4.0 gross (3.88 net) operated wells.
Previous 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.
Current wording
Lease Operating Expenses. Lease operating expenses were $44.8 million and $45.3 million for the years ended December 31, 2025 and 2024, respectively. On a per unit basis, lease operating expenses were $10.15 per Boe and $9.77 per Boe for the years ended December 31, 2025 and 2024, 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.
Previous wording
Workover and Other Expenses. Workover and other expenses were $5.2 million and $7.2 million for the years ended December 31, 2024 and 2023, respectively. On a per unit basis, workover and other expenses were $1.12 per Boe and $1.42 per Boe for the years ended December 31, 2024 and 2023, respectively. The decreased workover and other expenses in 2024 relate to fewer significant workover projects undertaken in the current year compared to 2023.
Current wording
Workover and Other Expenses. Workover and other expenses were $6.5 million and $5.2 million for the years ended December 31, 2025 and 2024, respectively. On a per unit basis, workover and other expenses were $1.46 per Boe and $1.12 per Boe for the years ended December 31, 2025 and 2024, respectively. The increased workover and other expenses in 2025 compared to 2024 relate to increased workover activity during 2025 and includes costs related to a non-recurring well cleanout program that meaningfully increased production on wells in which workovers were completed combined with a higher volume of electric submersible pump (or “ESP”) maintenance during the year.
Previous wording
Taxes Other than Income. Taxes other than income were $11.2 million and $11.9 million for the years ended December 31, 2024 and 2023, respectively. Most production taxes are based on production volumes and realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease, as such, taxes other than income decreased due to the decrease in revenues. On a per unit basis, taxes other than income were $2.42 per Boe and $2.37 per Boe for the years ended December 31, 2024 and 2023, respectively.
Current wording
Taxes Other than Income. Taxes other than income were $9.8 million and $11.2 million for the years ended December 31, 2025 and 2024, respectively. Most production taxes are based on production volumes and realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease, as such, taxes other than income decreased due to the decrease in production volumes and revenues. On a per unit basis, taxes other than income were $2.23 per Boe and $2.42 per Boe for the years ended December 31, 2025 and 2024, respectively.
Previous wording
Gathering and Other Expenses. Gathering and other expenses were $54.1 million and $63.6 million for the years ended December 31, 2024 and 2023, respectively. On a per unit basis, gathering and other expenses were $11.67 per Boe and $12.64 per Boe for the years ended December 31, 2024 and 2023, respectively. 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 the AGI Facility or through third parties. For the year ended December 31, 2024, overall natural gas production volumes decreased compared to 2023 in addition to cost savings realized with the AGI Facility coming online.
Current wording
Gathering and Other Expenses. Gathering and other expenses were $43.7 million and $54.1 million for the years ended December 31, 2025 and 2024, respectively. On a per unit basis, gathering and other expenses were $9.91 per Boe and $11.67 per Boe for the years ended December 31, 2025 and 2024, respectively. 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. The decrease in gathering and other expenses in total and on a per unit basis for the year ended December 31, 2025 compared to the year ended December 31, 2024 is primarily related to progress made at the central production facilities yielding lower labor and repair costs as well as increased throughput and overall production volumes being treated by the AGI Facility during 2025. Although the AGI Facility ceased operations on August 11, 2025, we were able to secure favorable treating rates at alternative facilities. The AGI Facility treated natural gas production from March 2024 to August 11, 2025. In January 2026, we were able to secure long-term alternative processing for our high concentration H2S production.
Previous wording
General and Administrative Expense. General and administrative expense was $18.2 million and $20.1 million for the years ended December 31, 2024 and 2023, respectively. The decrease in general and administrative expense for 2024 is primarily associated with a decrease in payroll and employee benefits, partially offset by an increase in professional fees and nonrecurring costs related to the terminated merger. On a per unit basis, general and administrative expense were $3.93 per Boe and $3.99 per Boe for the years ended December 31, 2024 and 2023, respectively.
Current wording
General and Administrative Expense. General and administrative expense was $14.6 million and $18.2 million for the years ended December 31, 2025 and 2024, respectively. The decrease in general and administrative expense for 2025 compared to 2024 is primarily associated with a decrease in nonrecurring costs related to the terminated merger and lower professional fees offset by an increase payroll and employee benefits costs. On a per unit basis, general and administrative expense were $3.30 per Boe and $3.93 per Boe for the years ended December 31, 2025 and 2024, respectively.
Previous wording
*Depletion, Depreciation, and Amortization Expense.*Depletion expense was $51.3 million and $55.2 million for the years ended December 31, 2024 and 2023, respectively. On a per unit basis, depletion expense was $11.06 per Boe and $10.97 per Boe for the years ended December 31, 2024 and 2023, respectively. Depletion for oil and natural gas properties is calculated using the unit-of-production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. The decrease of $3.9 million in depletion expense for the year ended December 31, 2024 compared to 2023 is primarily due to the decrease in production when comparing 2024 to 2023. The increase in our depletion rate for the year ended December 31, 2024 compared to 2023 is primarily due to
Current wording
properties is calculated using the unit-of-production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. The decrease of $0.6 million in depletion expense for the year ended December 31, 2025 compared to 2024 is primarily due to the decrease in production. The increase in our depletion rate for the year ended December 31, 2025 compared to the year ended December 31, 2024 is primarily due to decreased proved reserves relative to the change in future development costs associated with those reserves when comparing 2025 to 2024.
Previous wording
Net gain on derivative contracts. We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes. Accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations. We recorded a net derivative gain of $2.3 million ($11.1 million net gain on unsettled contracts and $8.8 million net loss on settled contracts) for the year ended December 31, 2024 and a net derivative gain of $12.7 million ($21.9 million net gain on unsettled contracts and $9.2 million net loss on settled contracts) for the year ended December 31, 2023. At December 31, 2024, we had a $11.0 million derivative asset, $7.0 million of which was classified as current, and we had a $19.3 million derivative liability, $12.3 million of which was classified as current.
Current wording
Net gain on derivative contracts. We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes. Accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations. We recorded a net derivative gain of $45.3 million ($29.5 million net gain on unsettled contracts and $15.8 million net gain on settled contracts) for the year ended December 31, 2025 and a net derivative gain of $2.3 million ($11.1 million net gain on unsettled contracts and $8.8 million net loss on settled contracts) for the year ended December 31, 2024. At December 31, 2025, we had a $23.5 million derivative asset, $16.1 million of which was classified as current, and we had a $2.3 million derivative liability, $0.6 million of which was classified as current.
Previous wording
Interest Expense and Other. Interest expense and other was $15.0 million and $33.3 million for the years ended December 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 receipt of a $10.0 million payment for the merger termination combined with a $7.5 million decrease in interest expense resulting from lower average debt balances from repayment of borrowings associated with our 2021 Amended Term Loan Agreement. Our weighted average interest rate for the year ended December 31, 2024, was approximately 12.88%. For the first quarter of 2025, we anticipate our interest rate will be 12.23% on outstanding borrowings.
Current wording
Interest Expense and Other. Interest expense and other was $26.7 million and $15.0 million for the years ended December 31, 2025 and 2024, respectively. Interest expense and other was higher for the year ended December 31, 2025 compared to the year ended December 31, 2024 primarily due to interest expense and other including the receipt of a $10.0 million payment during 2024 for the merger termination. Our weighted average interest rate for the year ended December 31, 2025, was approximately 12.05%. For the first quarter of 2026, we anticipate our interest rate will be 11.57% on outstanding borrowings.
Previous wording
We discuss recently adopted and issued accounting standards in Item 8.* Consolidated Financial Statements and Supplementary Data*—Note 1, “Summary of Significant Events and Accounting Policies.”
Current wording
We discuss recently adopted and issued accounting standards in Item 8.* Consolidated Financial Statements and Supplementary Data*—Note 1, “Financial Statement Presentation and Summary of Significant Accounting Policies.”
Rearranged current paragraphs (3)
Current report — wording carried from elsewhere
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. Pursuant to such, we initially recorded the advanced amount as a contract asset. During the fourth quarter of 2024, Caracara delivered a demand notice disputing our claims, indicating that the carrying value of the contract asset may not be recoverable and as a result, we recognized $18.5 million of impairment of charges to reduce the carrying value of the contract asset to zero at December 31, 2024.
Current report — wording carried from elsewhere
Financing Activities. Net cash flows provided by financing activities for the year ended December 31, 2025 were $44.1 million compared to net cash flows used in financing activities for the year ended December 31, 2024 of $7.7 million. During the year ended December 31, 2025, we received net proceeds of $61.1 million from the incurrence of the Incremental Term Loans and repaid $16.9 million under our 2024 Amended Term Loan Agreement.
Current report — wording carried from elsewhere
*Depletion, Depreciation, and Amortization Expense.*Depletion expense was $50.7 million and $51.3 million for the years ended December 31, 2025 and 2024, respectively. On a per unit basis, depletion expense was $11.49 per Boe and $11.06 per Boe for the years ended December 31, 2025 and 2024, respectively. Depletion for oil and natural gas
Rearranged previous paragraphs (7)
Previous report — wording carried elsewhere
On December 26, 2024, we and our wholly-owned subsidiary Halcón Holdings, LLC entered into the 2024 Term Loan Agreement with Fortress Credit Corp., as administrative agent, and certain other financial institutions party thereto, as lenders. Pursuant to the 2024 Term Loan Agreement, the lenders agreed to provide us with (i) an initial term loan facility in the aggregate principal amount of $162.0 million, funded on December 26, 2024 and (ii) an incremental term loan facility in the aggregate principal amount of up to $63.0 million, of which such incremental borrowings in the amount of $63.0 million were incurred on January 9, 2025 pursuant to the First Amendment to our 2024 Term Loan Agreement. The 2024 Amended Term Loan Agreement matures on December 26, 2028.
Previous report — wording carried elsewhere
Borrowings under the 2024 Amended Term Loan Agreement bear interest at a rate per annum equal to a forward-looking term rate based on the SOFR for a tenor of three months (with a credit spread adjustment of 0.15% per annum) (or another applicable reference rate, as determined pursuant to the terms of the 2024 Amended Term Loan Agreement) plus an applicable margin of 7.75%.
Previous report — wording carried elsewhere
The 2024 Amended Term Loan agreement contains certain financial covenants (as defined in the 2024 Term Loan Agreement), including maintenance of the following ratios.
Previous report — wording carried elsewhere
Term Loan Agreement (see Item 8.Consolidated Financial Statements and Supplementary Date – Note 7, Debt) and a total of $12.2 million in debt repayments due under our 2024 Term Loan Agreement through December 2025. During January 2025, in conjunction with the entry into the Incremental Term Loans, the required repayments under our 2024 Amended Term Loan Agreement increased to a total of $16.9 million due through December 31, 2025. At December 31, 2024, $30.0 million remained available for issuance on or before August 29, 2025 under a support letter from the Investors.
Previous report — wording carried elsewhere
All obligations under the 2021 Amended Term Loan Agreement were refunded, refinanced and repaid in full by the loans under the 2024 Term Loan Agreement as the net proceeds of the 2024 Term Loan Agreement were used to repay all outstanding indebtedness under the 2021 Amended Term Loan Agreement in an aggregate amount of approximately $152.1 million, including accrued and unpaid interest, and to pay related fees and expenses related to the new credit agreement.
Previous report — wording carried elsewhere
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 report — wording carried elsewhere
decreased proved reserves relative to the change in future development costs associated with those reserves when comparing 2024 to 2023.