Item 2. Management’s Discussion and Analysis
ITEM 2. MANAGEMENT’S DISCUSSION A ND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in understanding our results of operations for the three and nine months ended September 30, 2025 and 2024 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2024. The results presented in this Form 10-Q are not necessarily indicative of future operating results.
Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. For more information, see “ Special note regarding forward-looking statements .”
Overview
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. Our properties and drilling activities are currently focused in the Delaware Basin, where we have an extensive drilling inventory that we believe offers attractive long-term economics.
Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. 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, attempts by foreign oil and natural gas producers to control the global supply, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding, developing and producing oil and natural gas reserves at economical costs are critical to our long-term success.
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 a limited period of time (generally, 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.
Recent Developments
Term Loan Credit Facility. On December 26, 2024 (the “Initial Closing Date”), we and our wholly-owned subsidiary Halcón Holdings, LLC entered into the Second Amended and Restated Senior Secured Credit Agreement (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 (the “Incremental Term Loans”), of which such incremental borrowings in the amount of $63.0 million were incurred on January 9, 2025 pursuant to a first amendment to our 2024 Term Loan Agreement (as amended, the “2024 Amended Term Loan Agreement”). The 2024 Amended Term Loan Agreement matures on December 26, 2028.
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
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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.
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 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%.
On November 12, 2025, we entered into the Second Amendment to the Second Amended and Restated Senior Secured Credit Agreement (the “Second Amendment”), effective November 12, 2025, 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 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 rate per annum set forth below in Category 1:
Total Net Leverage Ratio
SOFR Loans Spread
ABR Loans Spread
Category 1
≤ 2.50 to 1.00
7.75%
6.75%
Category 2
> 2.50 to 1.00 ≤ 3.00 to 1.00
8.00%
7.00%
Category 3
> 3.00 to 1.00 ≤ 3.25 to 1.00
8.25%
7.25%
Category 4
> 3.25 to 1.00
8.50%
7.50%
The Applicable Margin shall be adjusted quarterly on a prospective basis on each Adjustment Date based upon the Total Net Leverage Ratio in accordance with the table above.
The Second Amendment provides that the Borrower 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 fiscal quarter:
Fiscal Quarter
Total Net Leverage Ratio
Fiscal quarters ending March 31, 2025 through and including June 30, 2025
2.75 to 1.00
Fiscal quarter ending September 30, 2025
2.50 to 1.00
Fiscal quarter ending December 31, 2025
3.20 to 1.00
Fiscal quarter ending March 31, 2026
3.25 to 1.00
Fiscal quarter ending June 30, 2026
3.40 to 1.00
Fiscal quarter ending September 30, 2026
3.50 to 1.00
Fiscal quarter ending December 31, 2026
3.40 to 1.00
Fiscal quarter ending March 31, 2027
3.25 to 1.00
Fiscal quarter ending June 30, 2027
3.00 to 1.00
Fiscal quarter ending September 30, 2027 and each fiscal quarter thereafter
2.50 to 1.00
Additionally, the Second Amendment provides that the Borrower 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:
Fiscal Quarter
Asset Coverage Ratio
Fiscal quarters ending March 31, 2025 through and including December 31, 2026
1.85 to 1.00
Each fiscal quarter thereafter
2.00 to 1.00
The 2024 Amended Term Loan agreement contains certain financial covenants (as defined in the 2024 Term Loan Agreement and as amended in the Second Amendment), including maintenance of the following ratios.
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● Asset Coverage Ratio not to fall below 1.85x as of September 30, 2025 through and including December 31, 2026 and 2.00x for each fiscal quarter thereafter, determined as of the last day of each fiscal quarter;
● Total Net Leverage Ratio not to exceed 2.50x as of September 30, 2025 and not to exceed the levels set forth in the table above for each fiscal quarter thereafter, determined as of the last day of each fiscal quarter;
● Current Ratio not to fall below 1.00x, determined on the last day of each calendar month commencing with the calendar month ending March 31, 2025; and
● Liquidity not to fall below the greater of (x) $10,000,000 and (y) the amount equal to the scheduled principal and interest payments for the immediately succeeding three-month period, determined as of the last day of any fiscal quarter.
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.
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 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 $5.6 million for the remainder of 2025 and $22.5 million in 2026. During the quarter and nine months ended September 30, 2025, we made scheduled amortization payments in the amount of $5.6 million and $11.3 million, respectively.
We recognized a loss on extinguishment of debt for the year ended December 31, 2024 in the amount of $7.5 million resulting from the credit agreement refinancing on December 26, 2024 which included 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. Additionally, the Company deferred $4.3 million of original issue discount and financing costs on the unaudited condensed consolidated balance sheet at December 31, 2024 in conjunction with entry into the 2024 Term Loan Agreement and deferred an additional $1.8 million of original issue discount and financing costs on the unaudited condensed consolidated balance sheet in conjunction with the issuance of the Incremental Term Loans in January 2025.
H 2 S Treating Joint Venture. The acid gas injection facility (“AGI Facility”) to which we are a party to a joint venture has been processing gas since March 9, 2024. On August 11, 2025, we received notice from WAT that it decided to cease taking deliveries of gas and to cease operations effective immediately. In response, we temporarily shut-in a portion of our Monument Draw field production. As of September 30, 2025 and as of the date of this filing, the WAT facility remains out of service. The cessation of operations has increased processing costs as we pay higher processing rates with other service providers and resulted in decreased production and revenue for the quarter ended September 30, 2025. Management continues to actively work to identify and execute on a plan for alternative gas processing.
Under a gas treating agreement (“GTA”) with the AGI Facility, we paid a treating rate that varied based on volumes delivered to the AGI Facility and had a minimum volume commitment of 20 MMcf per day. The GTA has a tiered-rate structure based on actual volumes delivered .
Capital Resources and Liquidity
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 net income of $10.1 million for the nine months ended September 30, 2025 and had negative working capital of $3.9 million at September 30, 2025. At September 30, 2025, we had $50.5 million of cash and cash equivalents, no additional borrowing capacity under the 2024 Amended Term Loan Agreement (as defined in
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Note 5, “ Debt ” to the unaudited condensed consolidated financial statements) and a total of $22.5 million in debt repayments due through September 2026 under our 2024 Amended Term Loan Agreement . At September 30, 2025, $30.0 million remained available for issuance on or before August 31, 2026 under a support letter from our investors.
We continue to execute on a plan to reduce operating and capital costs to improve cash flows. Changes to our current business estimates and forecasts, based primarily on recent commodity prices and modifications to our planned drilling schedule to achieve better overall well economics, indicate that we are at risk of potential non-compliance with our debt covenant requirements for the next 12 months from the issuance of these unaudited condensed consolidated financial statements. In response to these events and conditions, we have continued to execute on a plan to reduce operating and capital costs to improve cash flows. The Company also continues to have a support letter from its three largest current related party investors to purchase additional preferred equity securities in an amount up to $30.0 million on or before August 31, 2026. We believe that, based upon our operational forecasts, cash and cash equivalents on hand, cost reduction measures, and the support letter for the sale of $30.0 million in additional preferred equity, it is probable that we will have sufficient liquidity to maintain compliance with our future debt covenants as described in Note 5, “ Debt, ” for the next 12 months from the issuance of these unaudited condensed consolidated financial statements. We will, however, continue to consider alternative liquidity sources which could include 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. In the event our cash flows are materially less than anticipated or our costs are materially greater than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may be required to curtail drilling, development, land acquisitions and other activities to reduce our capital spending. However, significant or prolonged reductions in capital spending will adversely impact our production and may negatively affect our future cash flows.
We continuously monitor changes in market conditions and will continue to adapt our operational plans as necessary to strive to maintain sufficient liquidity, facilitate drilling on our undeveloped acreage position and permit us to selectively expand our acreage, as well as meet our debt obligations and restrictive covenants. We continue to explore strategic transactions to address these concerns, while also looking at opportunities to significantly reduce expenses in the near term. In this regard, we 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.
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 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 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 September 30, 2025 of $(20.3) 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
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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.
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.
Additionally, in periods of increasing commodity prices, we continue to be at risk to supply chain issues, including, but not limited to, labor shortages, pipe restrictions and potential delays in obtaining frac and/or drilling related equipment that could impact our business. During these periods, the costs and delivery times of rigs, equipment and supplies may also be substantially greater. The unavailability or high cost of drilling rigs and/or frac crews, pressure pumping equipment, tubulars and other supplies, and of qualified personnel can materially and adversely affect our operations and profitability.
Lastly, actual or anticipated declines in domestic or foreign economic activity or growth rates, regional or worldwide increases in tariffs or other trade restrictions, turmoil affecting the United States or global financial system and markets and a severe economic contraction either regionally or worldwide, resulting from international conflicts, efforts to contain 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.
Debt Obligations. Under our 2024 Amended Term Loan, 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 must make a total of $22.5 million in debt repayments through September 2026 under our 2024 Amended Term Loan Agreement.
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 2024 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.
While we have largely been successful in obtaining modifications of our covenants as needed, there can be no assurance that we will be successful in the future. In the event we are not successful in obtaining covenant modifications, if needed, there is no assurance that we will be successful in implementing alternatives that allow us to maintain compliance with our covenants or that we will be successful in obtaining alternative financing that provides us with the liquidity that we need to operate our business. Even if successful, alternative sources of financing could prove more expensive than borrowings under our 2024 Amended Term Loan Agreement.
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Cash Flows
Net increase in cash and cash equivalents is summarized as follows (in thousands):
Nine Months Ended
September 30,
2025
2024
Cash flows provided by operating activities
$
50,909
$
28,669
Cash flows used in investing activities
(69,962)
(52,586)
Cash flows provided by (used in) financing activities
49,796
(3,777)
Net increase (decrease) in cash, cash equivalents and restricted cash
$
30,743
$
(27,694)
Operating Activities . Net cash flows provided by operating activities for the nine months ended September 30, 2025 and 2024, were $50.9 million and $28.7 million, respectively. Items impacting the increase in operating cash flows were primarily driven by changes in working capital for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024.
Investing Activities. Net cash flows used in investing activities for the nine months ended September 30, 2025 and 2024 were approximately $70.0 million and $52.6 million, respectively, primarily for drilling and completion activities.
During the nine months ended September 30, 2025, we spent $69.6 million on oil and natural gas capital expenditures, of which $59.9 million related to drilling and completion costs and $8.5 million related to the development of our treating equipment and gathering support infrastructure. In the first nine months of 2025, we ran one operated rig in the Delaware Basin, drilled, cased, completed and put online six gross (5.5 net) operated wells.
During the nine months ended September 30, 2024, we spent $51.8 million on oil and natural gas capital expenditures, of which $46.8 million related to drilling and completion costs and $4.1 million related to the development of our treating equipment and gathering support infrastructure. During the first half of 2024, our cash capital expenditures included amounts related to the drilling and completion activities that occurred in the fourth quarter of 2023. In the first nine months of 2024, we ran one 1 operated rig in the Delaware Basin, drilled and cased four 4 gross (3.73 net), and completed and put online two 2 gross (1.925 net) operated wells. We also received $7.0 million in proceeds from the sale of oil and natural gas assets that were deemed to be unnecessary for future operations.
Financing Activities. Net cash flows provided by financing activities for the nine months ended September 30, 2025 were $49.8 million compared to net cash flows used in financing activities for the nine months ended September 30, 2024 of $3.8 million. During the nine months ended September 30, 2025, we received net proceeds of $61.1 million from the incurrence of the Incremental Term Loans and repaid $11.3 million under our 2024 Amended Term Loan Agreement. During the nine months ended September 30, 2024, we repaid $52.3 million under our Amended Term Loan Agreement and received $38.8 million from our preferred stock equity issuances. Our net cash flows provided by financing activities during the nine months ended September 30, 2024 also reflect the receipt of the $10.0 million distributed from the Merger escrow account to the Company.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2024.
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Results of Operations
The table below sets forth financial information for the periods presented.
Three Months Ended
Nine Months Ended
September 30,
September 30,
In thousands (except per unit and per Boe amounts)
2025
2024
2025
2024
Operating revenues:
Oil
$
38,325
$
42,545
$
114,316
$
130,673
Natural gas
853
(2,588)
4,611
(2,660)
Natural gas liquids
4,208
5,145
14,420
15,704
Other
96
164
422
523
Operating expenses:
Production:
Lease operating
12,389
11,602
33,417
34,193
Workover and other
839
1,249
4,581
3,088
Taxes other than income
2,622
2,532
7,944
8,872
Gathering and other
10,199
12,442
33,157
41,854
General and administrative:
General and administrative
3,085
3,849
10,017
11,125
Stock-based compensation
—
5
48
140
Depletion, depreciation and accretion:
Depletion – Full cost
13,165
12,121
39,393
37,559
Depreciation – Other
69
163
310
486
Accretion expense
288
249
838
726
Other income (expenses):
Net gain on derivative contracts
5,180
26,896
26,030
3,932
Interest expense and other
(6,741)
(6,322)
(20,010)
(19,809)
Net (loss) income
$
(735)
$
21,628
$
10,084
$
(9,680)
Production:
Oil – MBbls
599
577
1,752
1,720
Natural Gas - MMcf
1,778
1,844
5,713
5,953
Natural gas liquids – MBbls
236
227
680
751
Total MBoe (1)
1,131
1,111
3,384
3,463
Average daily production – Boe (1)
12,293
12,076
12,396
12,639
Average price per unit (2) :
Oil price - Bbl
$
63.98
$
73.73
$
65.25
$
75.97
Natural gas price - Mcf
0.48
(1.40)
0.81
(0.45)
Natural gas liquids price - Bbl
17.83
22.67
21.21
20.91
Total per Boe (1)
38.36
40.60
39.41
41.50
Average cost per Boe:
Production:
Lease operating
$
10.95
$
10.44
$
9.88
$
9.87
Workover and other
0.74
1.12
1.35
0.89
Taxes other than income
2.32
2.28
2.35
2.56
Gathering and other
9.02
11.20
9.80
12.09
General and administrative:
General and administrative
2.73
3.46
2.96
3.21
Stock-based compensation
—
—
0.01
0.04
Depletion
11.64
10.91
11.64
10.85
(1) Determined using a ratio of nine Mcf of natural gas to one barrel of oil, condensate, or natural gas liquids (“NGLs”) based on approximate energy equivalency. This is an energy content correlation and does not reflect the value or price relationship between the commodities.
(2) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.
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Operating Revenues. Oil, natural gas and NGLs revenues were $43.4 million and $45.1 million for the three months ended September 30, 2025 and 2024, respectively. The decrease in revenues is primarily attributable to a decrease in average realized prices. Production averaged 12,293 Boe per day for the three months ended September 30, 2025 compared to 12,076 Boe per day for the three months ended September 30, 2024. Average realized prices (excluding the effects of hedging arrangements) decreased approximately $2.24 per Boe for three months ended September 30, 2025 when compared with the same period in 2024.
Oil, natural gas and NGLs revenues were $133.3 million and $143.7 million for the nine months ended September 30, 2025 and 2024, respectively. The decrease in revenues is primarily attributable to a combination of a decrease in our average realized prices and lower production volumes in 2025 compared to 2024. Production averaged 12,396 Boe per day for the nine months ended September 30, 2025 compared to 12,639 Boe per day for the nine months ended September 30, 2024. Average realized prices (excluding the effects of hedging arrangements) decreased approximately $2.09 per Boe for the nine months ended September 30, 2025 when compared with the same period in 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.
Lease Operating Expenses. Lease operating expenses were $12.4 million and $11.6 million for the three months ended September 30, 2025 and 2024, respectively, and $33.4 million and $34.2 million for the nine months ended September 30, 2025 and 2024, respectively. On a per unit basis, lease operating expenses were $10.95 per Boe and $10.44 per Boe for the three months ended September 30, 2025 and 2024, respectively, and $9.88 per Boe and $9.87 per Boe for the nine months ended September 30, 2025 and 2024, respectively. The increase in lease operating expenses for the three months ended September 30, 2025 compared to the same period of 2024 is primarily a result of increased water production from new wells yielding higher disposal costs. The decrease in lease operating expenses for the nine months ended September 30, 2025 compared to the same period in 2024 primarily results from contract negotiations with service providers in all fields resulting in lower water production costs, lower chemical costs and aggressive preventative maintenance programs yielding decreased reactive repairs and maintenance costs.
Workover and Other Expenses. Workover and other expenses were $0.8 million and $1.2 million for the three months ended September 30, 2025 and 2024, respectively, and $4.6 million and $3.1 million for the nine months ended September 30, 2025 and 2024, respectively. On a per unit basis, workover and other expenses were $0.74 per Boe and $1.12 per Boe for the three months ended September 30, 2025 and 2024, respectively, and $1.35 per Boe and $0.89 per Boe for the nine months ended September 30, 2025 and 2024, respectively. The decrease in workover and other expenses for the three months ended September 30, 2025 compared to the same period in 2024 is the result of less workover activity during the third quarter of 2025. The increase in workover and other expenses for the nine months ended September 30, 2025 compared to the same periods of 2024 relates to increased workover activity during 2025 and includes costs related to a non-recurring well cleanout program that meaningfully increased production combined with a higher volume of ESP maintenance.
Taxes Other than Income. Taxes other than income were $2.6 million and $2.5 million for the three months ended September 30, 2025 and 2024, respectively, and $7.9 million and $8.9 million for the nine months ended September 30, 2025 and 2024, respectively. Severance taxes are based on realized prices and volumes at the wellhead, while ad valorem taxes are tied to the annual valuation of our properties. As revenues or volumes from oil and natural gas sales increase or decrease, severance taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $2.32 per Boe and $2.28 per Boe for the three months ended September 30, 2025 and 2024, respectively, and $2.35 per Boe and $2.56 per Boe for the nine months ended September 30, 2025 and 2024, respectively.
Gathering and Other Expenses. Gathering and other expenses were $10.2 million and $12.4 million for the three months ended September 30, 2025 and 2024, respectively, and $33.2 million and $41.9 million for the nine months ended September 30, 2025 and 2024, respectively. Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production and operating expenses of our gathering support infrastructure. Our gathering and other expenses are primarily driven by the amount and location of natural gas production, the concentration of H 2 S in our sour gas produced, and the amounts paid to treat our sour gas volumes, either through our own hydrogen sulfide treating plant or through third parties. On a per unit basis, gathering and other expenses were
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$9.02 per Boe and $11.20 per Boe for the three months ended September 30, 2025 and 2024, respectively, and $9.80 per Boe and $12.09 per Boe for the nine months ended September 30, 2025 and 2024, respectively. The decrease in gathering and other expenses per Boe for the three and nine months ended September 30, 2025 compared to the same periods of 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.
General and Administrative Expense. General and administrative expense was $3.1 million and $3.8 million for the three months ended September 30, 2025 and 2024, respectively, and $10.0 million and $11.1 million for the nine months ended September 30, 2025 and 2024, respectively. On a per unit basis, general and administrative expenses were $2.73 per Boe and $3.46 per Boe for the three months ended September 30, 2025 and 2024, respectively, and $2.96 per Boe and $3.21 per Boe for the nine months ended September 30, 2025 and 2024, respectively. The decrease in general and administrative expense for the three and nine months ended September 30, 2025 compared with the same prior year periods is primarily due to lower merger costs.
Depletion, Depreciation, and Amortization Expense. Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period.
Depletion expense was $13.2 million and $12.1 million for the three months ended September 30, 2025 and 2024, respectively, and $39.4 million and $37.6 million for the nine months ended September 30, 2025 and 2024, respectively. On a per unit basis, depletion expense was $11.64 per Boe and $10.91 per Boe for the three months ended September 30, 2025 and 2024, respectively, and $11.64 per Boe and $10.85 per Boe for the nine months ended September 30, 2025 and 2024, respectively. The increase in our depletion rate per Boe is primarily due to a period over period increase in net oil and natural gas properties combined with the associated period over period decrease in proved reserves.
Net gain on derivative contracts. We enter into derivative commodity instruments to hedge our exposure to price fluctuations on our anticipated oil, natural gas and NGLs production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the unaudited condensed consolidated statements of operations.
For the three months ended September 30, 2025, we recorded a net derivative gain of $5.2 million ($1.1 million net unrealized gain on unsettled contracts and $4.1 million net realized gain on settled contracts). For the three months ended September 30, 2024, we recorded a net derivative gain of $26.9 million ($28.1 million net gain on unsettled contracts and $1.2 million net realized loss on settled contracts). For the nine months ended September 30, 2025, we recorded a net derivative gain of $26.0 million ($20.1 million net unrealized gain on unsettled contracts and $5.9 million net realized gain on settled contracts). For the nine months ended September 30, 2024, we recorded a net derivative gain of $3.9 million ($12.7 million net gain on unsettled contracts and $8.8 million net realized loss on settled contracts). At September 30, 2025, we had a $18.5 million derivative asset ($15.1 million current) and a $6.6 million derivative liability ($1.9 million current).
Interest Expense and Other. Interest expense and other totaled $6.7 million and $6.3 million for the three months ended September 30, 2025 and 2024, respectively and $20.0 million and $19.8 million for the nine months ended September 30, 2025 and 2024, respectively. Our weighted average interest rate was approximately 12.19% and 12.20% for the three and nine months ended September 30, 2025, respectively . Comparatively, our weighted average interest rate was approximately 12.98% for the quarter ended September 30, 2024 and 12.97% for the nine months ended September 30, 2024. For the fourth quarter of 2025, our interest rate will be approximately 11.90% on outstanding borrowings .
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