BATTALION OIL CORP 10-Q

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 months ended March 31, 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. 24 Table of Contents 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 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%. The 2024 Amended Term Loan agreement contains certain financial covenants (as defined in the 2024 Term Loan Agreement), including maintenance of the following ratios. ● Asset Coverage Ratio not to fall below 1.70x as of March 31, 2025 through and including June 30, 2025, 1.85x as of September 30, 2025 through and including December 31, 2025 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 2.75x as of March 31, 2025 through and including June 30, 2025 and 2.50x 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 $16.9 million and $22.5 million in 2025 and 2026, 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 condensed consolidated balance sheet at December 31, 2024 in conjunction with entry into the 2024 Term Loan Agreement and deferred an additional $1.7 million of original issue discount and financing costs on the condensed consolidated balance sheet at March 31, 2025 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 and continues to process gas currently. In addition to general facility downtime, the AGI Facility has experienced interruptions in processing due to the completion of improvement and maintenance projects, including pump and other facility equipment replacement. The continued processing delays and interruptions have resulted in higher processing fees than forecasted as we pay higher processing rates with other service providers. 25 Table of Contents Under a gas treating agreement (“GTA”) with the AGI Facility, 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 . 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 $6.0 million for the three months ended March 31, 2025 and had working capital of $15.4 million at March 31, 2025. At March 31, 2025, we had $73.6 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 2026 . At March 31, 2025, $30.0 million remained available for issuance on or before August 29, 2025 under a support letter from our investors. 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. 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 26 Table of Contents 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 and such payments total $22.5 million through March 2026. 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. Cash Flow Net decrease in cash and cash equivalents is summarized as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended ​ ​ March 31, ​ 2025 ​ 2024 ​ ​ ​ ​ ​ ​ ​ Cash flows provided by operating activities ​ $ 12,731 ​ $ 3,916 Cash flows used in investing activities ​ ​ (20,112) ​ ​ (31,848) Cash flows provided by financing activities ​ ​ 61,237 ​ ​ 19,345 Net increase (decrease) in cash, cash equivalents and restricted cash ​ $ 53,856 ​ $ (8,587) Operating Activities . Net cash flows provided by operating activities for the three months ended March 31, 2025 and 2024, were $12.7 million and $3.9 million, respectively. Items impacting the increase in operating cash flows were primarily driven by a decrease in operating expenses coupled with changes in working capital for the three months ended March 31, 2025 compared to the three months ended March 31, 2024. Investing Activities. Net cash flows used in investing activities for the three months ended March 31, 2025 and 2024 were approximately $20.1 million and $31.8 million, respectively, primarily for drilling and completion activities. 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. 27 Table of Contents During the three months ended March 31, 2024, we spent $31.8 million on oil and natural gas capital expenditures, of which $23.7 million related to drilling and completion costs, $7.2 million related to AGI Facility expenditures which were initially recorded as a contract asset and $0.5 million related to the development of our treating equipment and gathering support infrastructure. In the first three months of 2024, we ran one operated rig in the Delaware Basin and drilled and cased two gross (2.0 net) operated wells. Financing Activities. Net cash flows provided by financing activities for the three months ended March 31, 2025 and 2024 were $61.2 million and $19.3 million, respectively. 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. During the three months ended March 31, 2024, we received $19.5 million from our preferred stock equity issuance and repaid $10.0 million under our 2021 Amended Term Loan Agreement. Our net cash flows provided by financing activities during the three months ended March 31, 2024 also reflect the receipt of $10.0 million distributed from escrow to the Company in accordance with the terms of a merger agreement that was subsequently terminated on December 20, 2024. 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. ​ 28 Table of Contents Results of Operations The table below sets forth financial information for the periods presented. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended ​ ​ ​ March 31, In thousands (except per unit and per Boe amounts) ​ 2025 ​ 2024 Operating revenues: ​ ​ ​ ​ ​ ​ ​ Oil ​ ​ $ 39,700 ​ $ 42,429 Natural gas ​ ​ ​ 2,823 ​ ​ 2,047 Natural gas liquids ​ ​ ​ 4,862 ​ ​ 5,056 Other ​ ​ ​ 90 ​ ​ 338 Operating expenses: ​ ​ ​ ​ ​ ​ ​ Production: ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ ​ 10,358 ​ ​ 11,586 Workover and other ​ ​ ​ 1,433 ​ ​ 888 Taxes other than income ​ ​ ​ 2,800 ​ ​ 2,991 Gathering and other ​ ​ ​ 12,000 ​ ​ 17,286 General and administrative: ​ ​ ​ ​ ​ ​ ​ General and administrative ​ ​ ​ 4,365 ​ ​ 3,972 Stock-based compensation ​ ​ ​ 48 ​ ​ 99 Depletion, depreciation and accretion: ​ ​ ​ ​ ​ ​ ​ Depletion – Full cost ​ ​ ​ 12,674 ​ ​ 12,629 Depreciation – Other ​ ​ ​ 134 ​ ​ 162 Accretion expense ​ ​ ​ 272 ​ ​ 234 Other income (expenses): ​ ​ ​ ​ ​ ​ ​ Net gain (loss) on derivative contracts ​ ​ ​ 9,302 ​ ​ (24,187) Interest expense and other ​ ​ ​ (6,670) ​ ​ (7,039) Net income (loss) ​ ​ $ 6,023 ​ $ (31,203) ​ ​ ​ ​ ​ ​ ​ ​ Production: ​ ​ ​ ​ ​ ​ ​ Oil – MBbls ​ ​ ​ 569 ​ ​ 566 Natural Gas - MMcf ​ ​ ​ 1,799 ​ ​ 2,180 Natural gas liquids – MBbls ​ ​ ​ 202 ​ ​ 253 Total MBoe (1) ​ ​ ​ 1,071 ​ ​ 1,182 Average daily production – Boe (1) ​ ​ ​ 11,900 ​ ​ 12,989 ​ ​ ​ ​ ​ ​ ​ ​ Average price per unit (2) : ​ ​ ​ ​ ​ ​ ​ Oil price - Bbl ​ ​ $ 69.77 ​ $ 74.96 Natural gas price - Mcf ​ ​ ​ 1.57 ​ ​ 0.94 Natural gas liquids price - Bbl ​ ​ ​ 24.07 ​ ​ 19.98 Total per Boe (1) ​ ​ ​ 44.24 ​ ​ 41.91 ​ ​ ​ ​ ​ ​ ​ ​ Average cost per Boe: ​ ​ ​ ​ ​ ​ ​ Production: ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ $ 9.67 ​ $ 9.80 Workover and other ​ ​ ​ 1.34 ​ ​ 0.75 Taxes other than income ​ ​ ​ 2.61 ​ ​ 2.53 Gathering and other ​ ​ ​ 11.20 ​ ​ 14.62 General and administrative: ​ ​ ​ ​ ​ ​ ​ General and administrative ​ ​ ​ 4.08 ​ ​ 3.36 Stock-based compensation ​ ​ ​ 0.04 ​ ​ 0.08 Depletion ​ ​ ​ 11.83 ​ ​ 10.68 (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. (2) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting. 29 Table of Contents Operating Revenues. Oil, natural gas and NGLs revenues were $47.4 million and $49.5 million for the three months ended March 31, 2025 and 2024. The decrease in revenues is primarily attributable to a decrease in production volumes in 2025 compared to 2024. Production averaged 11,900 Boe per day for the three months ended March 31, 2025 compared to 12,989 Boe per day for the three months ended March 31, 2024. Production was lower in the first quarter period of 2025 compared to the same period in 2024 due largely to the timing new wells coming online as no new wells came online during the first quarter of 2025. Average realized prices (excluding the effects of hedging arrangements) increased approximately $2.33 per Boe for three months ended March 31, 2025 when compared with the same period in 2024. Lease Operating Expenses. Lease operating expenses were $10.4 million and $11.6 million for the three months ended March 31, 2025 and 2024, respectively. On a per unit basis, lease operating expenses were $9.67 per Boe and $9.80 per Boe for the three months ended March 31, 2025 and 2024, respectively. The decrease in lease operating expenses on a per unit basis in the first quarter of 2025 compared to the first quarter of 2024 is primarily a result of lower water production and reduced repairs and maintenance costs. Workover and Other Expenses. Workover and other expenses were $1.4 million and $0.9 million for the three months ended March 31, 2025 and 2024, respectively. On a per unit basis, workover and other expenses were $1.34 per Boe and $0.75 per Boe for the three months ended March 31, 2025 and 2024, respectively. The increase in workover and other expenses for the first quarter 2025 compared to the same period in 2024 relates to slightly higher workover activity during the first quarter of 2025. Taxes Other than Income. Taxes other than income were $2.8 million and $3.0 million for the three months ended March 31, 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 $2.61 per Boe and $2.53 per Boe for the three months ended March 31, 2025 and 2024, respectively. Gathering and Other Expenses. Gathering and other expenses were $12.0 million and $17.3 million for the three months ended March 31, 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 $11.20 per Boe and $14.62 per Boe for the three months ended March 31, 2025 and 2024, respectively. The decrease in gathering and other expenses per Boe for the three months ended March 31, 2025 compared to the same period in 2024 is primarily related to a full quarter of volumes being treated by the AGI facility during 2025. The AGI facility did not come online until March 2024. General and Administrative Expense. General and administrative expense was $4.4 million and $4.0 million for the three months ended March 31, 2025 and 2024, respectively. On a per unit basis, general and administrative expenses were $4.08 per Boe and $3.36 per Boe for the three months ended March 31, 2025 and 2024, respectively. The increase in general and administrative expense for the three months ended March 31, 2025 compared with the same prior year period is primarily due to higher payroll and benefits 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 $12.7 million and $12.6 million for the three months ended March 31, 2025 and 2024, respectively. On a per unit basis, depletion expense was $11.83 per Boe and $10.68 per Boe for the three months ended March 31, 2025 and 2024, respectively. The increase in our depletion rate per Boe is primarily due to a period over period increase in future development costs associated with proved reserves combined with the associated period over period decrease in proved reserves. 30 Table of Contents Net gain (loss) 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 March 31, 2025, we recorded a net derivative gain of $9.3 million ($11.8 million net gain on unsettled contracts and $2.5 million net realized loss on settled contracts). For the three months ended March 31, 2024, we recorded a net derivative loss of $24.2 million ( $19.8 million net loss on unsettled contracts and $4.4 million net realized loss on settled contracts ). At March 31, 2025, we had a $24.5 million derivative asset ($15.7 million current) and a $21.0 million derivative liability ($14.7 million current). Interest Expense and Other. Interest expense and other totaled $6.7 million and $7.0 million for the three months ended March 31, 2025 and 2024, respectively. Interest expense and other primarily decreased in the current year periods compared to the same periods in the prior year due to a lower weighted average interest rate for the quarter ended March 31, 2025 on borrowings associated with our 2024 Amended Term Loan Agreement compared to the weighted average interest rate for the quarter ended March 31, 2024 on borrowings associated with our 2021 Amended Term Loan Agreement. Our weighted average interest rate was approximately 12.21% for the quarter ended March 31, 2025 . For the second quarter of 2025, our interest rate will be approximately 12.20% on outstanding borrowings .