What changed in this filing

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Item 2. Management’s Discussion and Analysis

2026-05-13 compared with 2025-11-13 · 106 added, 146 removed, 114 unchanged (69% of the section changed)

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

The following discussion is intended to assist in understanding our results of operations for the three and nine months ended September 30, 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 following discussion is intended to assist in understanding our results of operations for the three months ended March 31, 2026 and 2025 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, 2025.

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

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Recent Developments

At the Market Sales Offering

On May 5, 2026, we entered into a sales agreement with Roth Capital Partners, LLC (the “Agent”) (the “Sales Agreement”) pursuant to which we may issue and sell, from time to time, up to $150.0 million of shares of our common stock, through or to the Agent, acting as agent or principal, under the Sales Agreement in at-the-market transactions (the “ATM Agreement”).

For the period May 6, 2026 to May 8, 2026, we sold and issued 550,013 shares of our common stock under the ATM Agreement for net proceeds of $1.6 million.

Preferred Stock Conversion

On March 30, 2026, we issued 1,800,000 shares of our common stock to Luminus Energy Partners Master Fund, Ltd.

(“Luminus”) upon the conversion of 7,803 shares of our Series A-2 Redeemable Convertible Preferred Stock (the

“Series A-2 Preferred Stock”).

The conversion was calculated in accordance with the terms of the Series A-2 Preferred Stock, including adjustments provided in respect of any Unpaid Dividend Accrual (as defined in the Company’s Certificate of Incorporation, as amended) and using a conversion price of $6.21 per share.

Monument Draw Acquisition

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.

Private Placement Equity Offering

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 used the net proceeds received from the offering for working capital and general corporate purposes.

The warrants were exercised on April 7, 2026 and accordingly, upon exercise, we issued 927,273 shares of common stock.

West Quito Divestiture

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, reflecting adjustment for accounting effective date of December 1, 2025 and other customary adjustments.

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, on February 24, 2026, $12.9 million of Reinvestment Proceeds were held in a reinvestment account 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.

At March 31, 2026, $7.9 million of Reinvestment Proceeds remained and was recorded as restricted cash.

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

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

≤ 2.50 to 1.00

> 2.50 to 1.00 ≤ 3.00 to 1.00

> 3.00 to 1.00 ≤ 3.25 to 1.00

> 3.25 to 1.00

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

Fiscal quarter ending September 30, 2025

Fiscal quarter ending December 31, 2025

Fiscal quarter ending March 31, 2026

Fiscal quarter ending June 30, 2026

Fiscal quarter ending September 30, 2026

Fiscal quarter ending December 31, 2026

Fiscal quarter ending March 31, 2027

Fiscal quarter ending June 30, 2027

Fiscal quarter ending September 30, 2027 and each fiscal quarter thereafter

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

Each fiscal quarter thereafter

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.

● 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;

● 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;

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 .

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.

We recorded a loss on extinguishment of debt in the amount of $0.9 million to write-off the proportionate amount of deferred financing costs and debt discount associated with the February 24, 2026 principal prepayment and deferred an

additional $0.6 million of deferred financing costs at March 31, 2026 in conjunction with entry into the Third Amendment.

Capital Resources and Liquidity

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

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

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.

We generated a net loss of $56.5 million for the three months ended March 31, 2026 and had negative working capital of $9.1 million as of March 31, 2026.

As of March 31, 2026, we had $46.4 million of cash and cash equivalents, no additional borrowing capacity under the 2024 Amended Term Loan Agreement (as defined in Note 5, “ Debt ” to the unaudited condensed consolidated financial statements) and a total of $22.5 million in debt repayments due through March 2027 under our 2024 Amended Term Loan Agreement .

As of March 31, 2026, $30.0 million remained available for issuance on or before August 31, 2026 under a support letter from our 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 including $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, remaining proceeds from the sale after related expenses (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.

At March 31, 2026, $7.9 million of Reinvestment Proceeds remained and was recorded as restricted cash.

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.

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 the private 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 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 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.

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

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

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

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

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

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

We have been exploring, 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.

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.

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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.

We reported stockholders’ equity of $157.1 million at March 31, 2026 resulting from the reclassification of our preferred stock from temporary to permanent equity 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.

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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.

We must make a total of $22.5 million in debt repayments through March 2027 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.

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

Nine Months Ended

September 30,

Three Months Ended

Cash flows provided by operating activities

Cash flows used in investing activities

Cash flows provided by (used in) financing activities

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

Cash flows provided by (used in) investing activities

Cash flows (used in) provided by financing activities

Net increase in cash, cash equivalents and restricted cash

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.

Net cash flows provided by operating activities for the three months ended March 31, 2026 and 2025, were $2.1 million and $12.7 million, respectively.

Items impacting the decrease in operating cash flows were primarily driven by changes in working capital for the three months ended March 31, 2026 compared to the three months ended March 31, 2025.

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.

Net cash flows provided by investing activities for the three months ended March 31, 2026 were approximately $56.4 million primarily from proceeds received from sales of oil and natural gas assets compared to net cash flows used in investing activities for the three months ended March 31, 2025 of $20.1 million primarily for drilling and completion activities.

During the three months ended March 31, 2026, we spent $3.6 million on oil and natural gas capital expenditures, of which $2.6 million related to drilling and completion costs and $0.8 million related to the development of our treating equipment and gathering support infrastructure.

During the three months ended March 31, 2025, we spent $19.8 million on oil and natural gas capital expenditures, of which $17.4 million related to drilling and completion costs and $2.1 million related to the development of our treating equipment and gathering support infrastructure.

In the first three months of 2025, we ran one operated rig in the Delaware Basin, drilled and cased four gross (4.0 net) operated wells, and did not complete and put online any operated wells.

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.

Net cash flows used in financing activities for the three months ended March 31, 2026 were $32.3 million compared to net cash flows provided by financing activities for the three months ended March 31, 2025 of $61.2 million.

During the three months ended March 31, 2026, we repaid $45.6 million under our 2024 Amended Term Loan Agreement and issued $14.0 million in common stock.

During the three months ended March 31, 2025, we received net proceeds of $61.3 million from the incurrence of the Incremental Term Loans on January 9, 2025.

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.

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.

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Three Months Ended

Nine Months Ended

September 30,

In thousands (except per unit and per Boe amounts)

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Other income (expenses):

Net gain on derivative contracts

Net (loss) gain on derivative contracts

Interest expense and other

Loss on extinguishment of debt

Net (loss) income

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Stock-based compensation

(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.

(1) Determined using a ratio of six 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.

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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.

Oil, natural gas and NGLs revenues were $39.1 million and $47.4 million for the three months ended March 31, 2026 and 2025, respectively.

The decrease in revenues is primarily attributable to a decrease in average realized prices for oil, natural gas and NGLs.

We realized negative natural gas pricing for the quarter ended March 31, 2026 whereby costs and differentials exceeded the sales price for natural gas and resulted in us as seller paying the purchaser to take the natural gas.

Average realized prices (excluding the effects of hedging arrangements) decreased approximately $9.73 per Boe for three months ended March 31, 2026 when compared with the same period in 2025.

Production averaged 12,578 Boe per day for the three months ended March 31, 2026 compared to 11,900 Boe per day for the three months ended March 31, 2025 due to more consistent and reliable processing during the first quarter of 2026 compared to the first quarter of 2025.

West Quito area production averaged approximately 1,045 Boe per day of the Company’s total production for the quarter ended March 31, 2026 compared to 1,751 Boe per day for the quarter ended March 31, 2025.

We completed the West Quito Divestiture on February 24, 2026.

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.

Lease operating expenses were $10.1 million and $10.4 million for the three months ended March 31, 2026 and 2025, respectively.

On a per unit basis, lease operating expenses were $8.92 per Boe and $9.67 per Boe for the three months ended March 31, 2026 and 2025, respectively.

The decrease in lease operating expenses per Boe for the three months ended March 31, 2026 compared to the same period of 2025 is primarily a result of increased average daily production volumes.

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.

Workover and other expenses were $1.0 million and $1.4 million for the three months ended March 31, 2026 and 2025, respectively.

On a per unit basis, workover and other expenses were $0.90 per Boe and $1.34 per Boe for the three months ended March 31, 2026 and 2025, respectively.

The decrease in workover and other expenses for the three months ended March 31, 2026 compared to the same period in 2025 is the result of less workover activity during the first quarter of 2026.

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.

Taxes other than income were $2.3 million and $2.8 million for the three months ended March 31, 2026 and 2025, 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.

On a per unit basis, taxes other than income were $2.05 per Boe and $2.61 per Boe for the three months ended March 31, 2026 and 2025, 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 were $11.3 million and $12.0 million for the three months ended March 31, 2026 and 2025, 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

$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.

On a per unit basis, gathering and other expenses were $9.94 per Boe and $11.20 per Boe for the three months ended March 31, 2026 and 2025, respectively.

The decrease in gathering and other expenses per Boe for the three months ended March 31, 2026 compared to the same period of 2025 is primarily related to realized savings from capital project returns and more reliable throughput resulting from entry into a long-term processing agreement with a publicly traded large-cap midstream provider in January 2026.

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.

General and administrative expense was $4.3 million and $4.4 million for the three months ended March 31, 2026 and 2025, respectively.

On a per unit basis, general and administrative expenses were $3.76 per Boe and $4.08 per Boe for the three months ended March 31, 2026 and 2025, respectively.

The decrease in general and administrative expense per Boe for the three months ended March 31, 2026 compared with the same prior year periods is primarily due to increased average daily production.

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.

Depletion expense was $12.1 million and $12.7 million for the three months ended March 31, 2026 and 2025, respectively.

On a per unit basis, depletion expense was $10.68 per Boe and $11.83 per Boe for the three months ended

March 31, 2026 and 2025, respectively.

The decrease in our depletion rate per Boe is primarily due to a period over period decrease in net oil and natural gas properties resulting from the sale of our West Quito Assets combined with the associated period over period decrease in proved reserves.

Net (loss) 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).

For the three months ended March 31, 2026, we recorded a net derivative loss of $48.0 million ($47.0 million net unrealized loss on unsettled contracts and a $1.0 million net realized loss on settled contracts).

For the three months ended March 31, 2025, we recorded a net derivative gain of $9.3 million ($11.8 million net gain on unsettled contracts and a $2.5 million net realized loss on settled contracts).

At March 31, 2026, we had a $9.4 million derivative asset ($7.4 million current) and a $35.2 million derivative liability ($24.6 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 .

Interest expense and other totaled $5.5 million and $6.7 million for the three months ended March 31, 2026 and 2025, respectively.

Our weighted average interest rate was approximately 11.57% and 12.21% for the three months ended March 31, 2026 and 2025, respectively .

For the second quarter of 2026, our interest rate will be approximately 11.60% on outstanding borrowings .

Loss on extinguishment of debt.

We recorded a loss on extinguishment of debt in the amount of $0.9 million for the quarter ended March 31, 2026 to write-off the proportionate amount of deferred financing costs and debt discount associated with the February 24, 2026 principal prepayment.

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

What changed 10-Q

Item 2. Management’s Discussion and Analysis