Item 7. Management’s Discussion and Analysis
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in understanding our results of operations and our current financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K contain additional information that should be referred to when reviewing this material.
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 (“U.S.”). Our properties and drilling activities are currently focused in the Delaware Basin of West Texas, where we have an extensive drilling inventory that we believe offers attractive economics.
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, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is 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 2024 Amended Term Loan Agreement and extend, on a rolling basis, for the next four years. These limitations result in our liquidity being susceptible to commodity price declines. Additionally, while intended to reduce the effects of volatile commodity prices, derivative transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.
Recent Developments
Term Loan Credit Facility
On December 26, 2024, we and our wholly-owned subsidiary Halcón Holdings, LLC entered into the 2024 Term Loan Agreement with Fortress Credit Corp., as administrative agent, and certain other financial institutions party thereto, as lenders. Pursuant to the 2024 Term Loan Agreement, the lenders agreed to provide us with (i) an initial term loan facility in the aggregate principal amount of $162.0 million, funded on December 26, 2024 and (ii) an incremental term loan facility in the aggregate principal amount of up to $63.0 million, of which such incremental borrowings in the amount of $63.0 million were incurred on January 9, 2025 pursuant to the First Amendment to our 2024 Term Loan Agreement. The 2024 Amended Term Loan Agreement matures on December 26, 2028.
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.
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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, and subsequently on the amount of the loans outstanding on the Initial Closing Date plus the Incremental Term Loans, commencing with the fiscal quarter ending June 30, 2025. Under the 2024 Amended Term Loan Agreement, we must make scheduled amortization payments in the aggregate amount of $16.9 million in 2025 and $22.5 million in 2026.
For the year ended December 31, 2024, we recognized a loss on extinguishment of debt in the amount of $7.5 million resulting from the credit agreement refinancing on December 26, 2024 which includes a $3.6 million non-cash write-off of deferred financing costs, original issue discounts and embedded derivatives associated with the extinguished debt and $3.9 million in fees and debt issuance costs paid for the new debt.
Merger with Fury Resources
On December 14, 2023, we entered into the Merger Agreement with Parent and Merger Sub, a Delaware corporation and a direct, wholly owned subsidiary of Parent.
The Merger Agreement provided, that upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub would merge with and into us, with us surviving as a wholly owned subsidiary of Parent. Subject to the terms and conditions set forth in the Merger Agreement, at the effective time of the Merger, each of our issued and outstanding shares of Common Stock, par value $0.0001 per share (“Common Stock”) were to be converted into the right to receive cash, without interest, and such shares would cease to be outstanding, would automatically be canceled and retired and cease to exist; and each outstanding share of redeemable convertible preferred stock would be contributed to Parent in exchange for new preferred shares of Parent, or sold to Parent for cash, in each case at valuation based on the conversion or redemption value of such preferred stock.
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If the Merger was consummated, our shares of Common Stock would no longer trade on the NYSE American and would be deregistered under the Securities Exchange Act of 1934, as amended. As a result, we would have become a private company.
On January 24, 2024, Parent and we agreed to cause an amount equal to $10.0 million to be distributed from the escrow account to the Company. The distribution was initially recorded as a deposit liability in “Other” long-term liabilities on the consolidated balance sheet. Upon termination of the Merger, the $10.0 million was recognized as “Other income” on the consolidated statement of operations for the year ended December 31, 2024.
Subsequent to several amendments to the Merger Agreement and upon failure of Parent to meet the funding and closing requirements of the Merger Agreement, we terminated the Merger Agreement on December 20, 2024.
We incurred approximately $5.5 million as of December 31, 2024, in costs and expenses, including fees for professional services and other transaction costs, in connection with the terminated Merger.
Preferred Stock Equity Issuance
During the third quarter of 2023, we obtained a support letter from the Investors to purchase additional preferred equity securities in an amount up to $55.0 million over the next 12 months and an aggregate of 35,000 shares of preferred stock were sold on December 15, 2023 under such support letter to the Investors for proceeds of $34.1 million, net of $0.9 million of original issue discount. At December 31, 2023, $20.0 million remained available for issuance under the support letter from the Investors.
On March 27, 2024, we sold, in a private placement, the remaining 20,000 shares of preferred stock under the commitment letter received during the third quarter of 2023 to certain funds managed by Luminus Management, LLC, Oaktree Capital Management, LP, and LSP Investment Advisors, LLC, who represent our largest three existing stockholders (the “Investors”). We received $19.5 million in proceeds, net of $0.5 million in original issue discount.
On May 13, 2024, we sold, in a private placement, an aggregate of 20,000 shares of preferred stock to the Investors for $19.5 million in proceeds, net of $0.5 million in original issue discount, and such proceeds were used to make a $17.3 million prepayment of outstanding borrowings under the 2021 Amended Term Loan Agreement to cure noncompliance of the Total Net Leverage Ratio as of March 31, 2024.
During the third quarter of 2024, we obtained support letters from the Investors to purchase up to $30.0 million of additional preferred equity securities on or before August 29, 2025 and all remain undrawn.
The issuances of preferred stock were approved by our board of directors upon recommendation by a special committee of disinterested directors that was established to evaluate the proposed terms of the preferred stock. For a further discussion of the redemption and conversion provisions associated with the preferred stock The issuances of preferred stock were approved by our board of directors upon recommendation by a special committee of disinterested directors that was established to evaluate the proposed terms of the preferred stock.
Holders have no voting rights with respect to the shares of preferred stock. The preferred stock receives annual dividends, paid either in cash at a fixed rate of 14.5% annually or accrued at a fixed rate of 16.0% annually (“PIK accrual”) at our option. Currently, our Amended Term Loan Agreement prohibits the payment of cash dividends. Paid-in-kind (“PIK”) dividends are cumulative, compound and accrue quarterly in arrears and are added to the Liquidation Preference.
Shares of preferred stock will be convertible, subject to conversion ratios and prices stipulated in the agreement, at any time by the holders and by Battalion after meeting certain other agreement requirements. Battalion will also have the right to redeem the preferred stock in cash at an amount equal to between 100-120% of the Liquidation Preference ($1,000 per share, increased for any PIK accruals) determined according to the redemption date. Additionally, in the event of a change of control, holders have the right to receive, (i) at any time on or prior to 150 days following the closing date, and at the election of the Company, a cash payment equal to the Liquidation Preference or equity
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consideration equal to the 107.5% of the Liquidation Preference, or (ii) at any time after 150 days following the closing date, a cash payment equal to between 100-120% of the Liquidation Preference determined by the redemption date or conversion into common stock. Consistent with the terms of the 2021 Amended Term Loan Agreement, an election of the cash payment option by holders in a change of control scenario is not permitted until (i) a termination of or certain amendments to the 2024 Amended Term Loan Agreement or (ii) one year past the maturity date of the 2024 Amended Term Loan Agreement. For additional information, see Item 8. Consolidated Financial Statements and Supplementary Date – Note 12, Redeemable Convertible Preferred Stock.
H 2 S Treating Joint Venture
In May 2022, we entered into a joint venture agreement with Caracara to develop the AGI Facility in Winkler County, Texas. The joint venture, operating as WAT, also entered into a GTA with us for natural gas production from our Monument Draw area. In exchange for contributing to the joint venture a wellbore with an approved permit for the injection of acid gas and surface land , we retained a 5% equity interest in WAT, an unconsolidated subsidiary. Caracara provided the initial capital for the construction of the Facility, which is expected to have an initial capacity of approximately 30 MMcf per day, and a design capacity to treat up to 10% combined concentrations for H 2 S and CO 2 . We initially expected the AGI facility to be mechanically complete in early April 2023 and the facility to be in service in the second quarter of 2023. However, d uring commissioning and initial operations, it was determined that additional pressure was required to initiate gas injection. To correct this issue, a positive displacement pump was ordered and installed. The AGI Facility’s injection well also experienced pressure communication between the tubing and annular space after an injection procedure. We commenced workover operations to remediate this issue.
During the third quarter of 2023, additional complications were encountered with the workover operation at the AGI Facility causing higher than expected costs. To fund this workover operation, we advanced capital contributions totaling approximately $18.5 million to date as of September 30, 2024 on behalf of our joint venture partner in WAT. Pursuant to the terms of the agreement governing the joint venture, we believe we have multiple remedies to recover such advance, including (1) declaring such payment a loan, which pursuant to the agreement would have an interest rate of the lesser of 15% or the maximum rate permitted by law, (2) recoupment from distributions from the joint venture and (3) reallocation of equity of the joint venture based on the relative level of total capital contributions by the parties after taking into account the advance. Pursuant to such, we initially recorded the advanced amount as a contract asset. During the fourth quarter of 2024, Caracara delivered a demand notice disputing our claims, indicating that the carrying value of the contract asset may not be recoverable and as a result, we recognized $18.5 million of impairment of charges to reduce the carrying value of the contract asset to zero at December 31, 2024.
The AGI Facility has been processing gas since March 9, 2024 and continues to process gas currently. In addition to general facility downtime, the AGI Facility has experienced interruption in processing due to the completion of improvement and maintenance projects, including pump and other facility equipment replacement. The continued processing delays and interruptions in 2024 have resulted in higher processing fees than forecasted as we pay higher processing rates with other service providers.
Under the GTA, we pay a treating rate that varies based on volumes delivered to the AGI Facility and have a minimum volume commitment of 20 MMcf per day. The GTA has a tiered-rate structure based on actual volumes delivered. Our current estimates of future treating fee reductions are subject to various operational and other risk factors, some of which are beyond our control, which could impact the timing and extent of these estimates.
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 a net loss of $64.1 million for the year ended December 31, 2024 and had negative working capital of $23.6 million as of December 31, 2024. As of December 31, 2024, we had $19.7 million of cash and cash equivalents, $63.0 million of Incremental Term Loans borrowing capacity remaining under our 2024 Amended
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Term Loan Agreement (see Item 8. Consolidated Financial Statements and Supplementary Date – Note 7, Debt ) and a total of $12.2 million in debt repayments due under our 2024 Term Loan Agreement through December 2025. During January 2025, in conjunction with the entry into the Incremental Term Loans, the required repayments under our 2024 Amended Term Loan Agreement increased to a total of $16.9 million due through December 31, 2025. At December 31, 2024, $30.0 million remained available for issuance on or before August 29, 2025 under a support letter from the Investors.
Our 2024 Amended Term Loan Agreement contains certain restrictive covenants as well as a mandatory repayment schedule. We are required to make scheduled quarterly amortization payments in an aggregate principal amount equal to 2.50% of the aggregate principal amount of the loans outstanding commencing with the fiscal quarter ending June 30, 2025.
We continued to execute on a plan to reduce operating and capital costs to improve cash flow, including the issuance of preferred stock totaling $134.6 million during the years ended December 31, 2024 and 2023 and entry into our 2024 Amended Term Loan Agreement. We believe that, based upon our operational forecasts, cash and cash equivalents on hand and cost reduction measures, it is probable that we will have sufficient liquidity to fund our operations, meet our debt requirements and maintain compliance with our future debt covenants as described in Item 8. Consolidated Financial Statements and Supplementary Date – Note 7, Debt for the next 12 months from the issuance of these consolidated financial statements. We will, however, continue to consider alternative liquidity sources which could include entering into other financing arrangements (e.g. future equity raises), a sale of a portion of our non-core assets, seeking capital partners for our drilling program, pursuing strategic merger opportunities or joint ventures, the sale of the Company, or pursuing additional general and administrative or other cost reduction opportunities. Our estimates and forecasts are based upon assumptions that may prove to be incorrect due to many factors that are currently unknown, such as prevailing economic conditions, many of which are beyond our control. In the event the assumptions underlying our estimates and forecasts prove to be incorrect, our operating plans, capital requirements, and covenant compliance may be adversely impacted.
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 have been, and continue to, explore strategic transactions to address these concerns, while also looking at opportunities to significantly reduce expenses in the near term. In this regard, we have considered whether it is advisable to continue to bear the ongoing costs of the listing of our common stock on the NYSE American and of being a reporting Company under the Securities Exchange Act of 1934. We believe that we currently qualify to suspend these obligations should we elect to do so. While such a determination has not yet been made, we expect that the cost savings, particularly over the longer term, would be significant. Accordingly, we will continue to consider the matter while we simultaneously pursue strategic and financial alternatives that may render it unnecessary. However, there can be no assurance that, absent additional capital, reducing costs or other material favorable developments, the company will not experience liquidity and covenant compliance issues in the future.
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.
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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 U.S. or global financial system and markets and a severe economic contraction either regionally or worldwide, resulting from international conflicts, efforts to contain pandemics or other factors, could materially affect our business and financial condition and impact our ability to finance operations by worsening the actual or anticipated future drop in worldwide oil demand, negatively impacting the price received for oil and natural gas production or adversely impacting our ability to comply with covenants in our 2024 Amended Term Loan Agreement. Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our vendors and suppliers or cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations. All of the foregoing may adversely affect our business, financial condition, results of operations, cash flows and, potentially, compliance with the covenants contained in our 2024 Amended Term Loan Agreement.
Capital Expenditures . During 2024, we spent approximately $64.6 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs. During 2024, we ran one operated rig in the Delaware Basin. We drilled and cased 4.0 gross (3.95 net) operated wells, completed 4.0 gross (3.95 net), and put online 4.0 gross (3.88 net) operated wells during the year.
Debt Obligations . On December 26, 2024 (the “Initial Closing Date”), we and our wholly-owned subsidiary Halcón Holdings, LLC (the “Borrower”), entered into the 2024 Term Loan Agreement. Pursuant to the 2024 Term Loan Agreement, the lenders party thereto agreed to provide the Borrower 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 to be made available to the Borrower from January 3, 2025 until the date that is the earliest to occur of (x) the date on which such incremental term facility is fully drawn, (y) the date on which such incremental term facility is terminated and (z) January 11, 2025, subject to the satisfaction of certain conditions. On January 9, 2025, the Borrower entered into the First Amendment to its 2024 Term Loan Agreement. Pursuant to the First Amendment, the Borrower incurred $63.0 million of Incremental Term Loans.
The maturity date of the 2024 Amended Term Loan Agreement is 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 bear interest at a rate per annum equal to a forward-looking term rate based on SOFR for a tenor of three months (with a credit spread adjustment of 0.15% per annum) (or another applicable reference rate, as determined pursuant to the terms of the 2024 Amended Term Loan Agreement) plus an applicable margin of 7.75%.
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We may elect, at our option, to prepay any borrowing outstanding under the 2024 Amended Term Loan Agreement. Such voluntary prepayments, certain mandatory prepayments and change of control prepayments are subject to the following prepayment premium, as applicable:
Period
Premium
Months 0 - 12
Make-whole amount equal to 12 months of interest plus 4.00%
Months 13 - 30
2.00%
Thereafter
0.00%
In the event we shall receive a disapproval notice (as defined in the 2024 Term Loan Agreement) from the required lenders under the 2024 Amended Term Loan Agreement rejecting or otherwise disqualifying a proposed buyer in connection with a permitted change in control thereunder to be consummated within 12 months following the Initial Closing Date, such voluntary prepayments, certain mandatory prepayments and change of control prepayments are subject to the following prepayment premium, as applicable:
Period
Premium
Months 0 - 9
Make-whole amount equal to 9 months of interest plus 2.00%
Months 10 - 30
2.00%
Thereafter
0.00%
We may be required to make mandatory prepayments of the loans under the 2024 Amended Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales and with excess cash on hand in excess of certain maximum levels. We are required to make scheduled quarterly amortization payments in an aggregate principal amount equal to 2.50% of the aggregate principal amount of the loans outstanding commencing with the fiscal quarter ending June 30, 2025.
Amounts outstanding under the 2024 Amended Term Loan Agreement are guaranteed by certain of our direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Borrower and such direct and indirect subsidiaries, and of the equity interests of the Borrower held by the Company.
The 2024 Amended Term Loan agreement contains certain financial covenants (as defined in the 2024 Term Loan Agreement), including the 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.
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
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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.
The results presented in this Form 10-K are not necessarily indicative of future operating results. For further information regarding these risks and uncertainties on us, see “Risk Factors” in Item 1A of this Annual Report on Form 10-K.
Cash Flow . Net (decrease) increase in cash, cash equivalents and restricted cash is summarized as follows for the periods presented (in thousands):
Years Ended December 31,
2024
2023
Cash flows provided by operating activities
$
35,355
$
17,589
Cash flows used in investing activities
(65,443)
(51,845)
Cash flows (used in) provided by financing activities
(7,728)
59,059
Net (decrease) increase in cash, cash equivalents and restricted cash
$
(37,816)
$
24,803
Operating Activities. Net cash flows provided by operating activities for the years ended December 31, 2024 and 2023 were $35.4 million and $17.6 million, respectively. Operating cash flows for the year ended December 31, 2024 increased from the prior year primarily due to lower gathering and transportation expense, decreased interest expense associated with lower outstanding debt balance during the year, the inclusion of the merger termination payment of $10.0 million and changes in working capital. The increase in operating cash flows in 2024 were partially offset by decreased oil and natural gas revenues as a result of lower realized commodity prices and lower production volumes than the comparable prior year period.
Investing Activities. Net cash flows used in investing activities for the years ended December 31, 2024 and 2023 were approximately $65.4 million and $51.8 million, respectively.
During the year ended December 31, 2024, we spent $64.6 million on oil and natural gas capital expenditures, of which $57.8 million related to drilling and completion costs and $5.7 million related to the development of our treating equipment and gathering support infrastructure.
During the year ended December 31, 2023, we spent $46.3 million on oil and natural gas capital expenditures, of which $40.4 million related to drilling and completion costs and $4.7 million related to the development of our treating equipment and gathering support infrastructure.
Financing Activities. Net cash flows used in financing activities for the year ended December 31, 2024 were $7.7 million compared to net cash flows provided by financing activities for the year ended December 31, 2023 of $59.1 million. During the year ended December 31, 2024, prior to the refinancing transaction, we made principal payments of $52.4 million under our 2021 Amended Term Loan Agreement. On December 26, 2024, we entered into the 2024 Term Loan Agreement, incurring $162.0 million in borrowings, which such proceeds were used to repay all amounts outstanding under the 2021 Amended Term Loan Agreement in the amount of $147.7 million. Additionally, we incurred $8.2 million of debt issuance costs related to the new credit agreement. We received $38.8 million in proceeds from the sales and issuance of preferred stock during the year ended December 31, 2024.
During the year ended December 31, 2023, we received $95.6 million in proceeds from the sales and issuance of preferred stock and we made $35.0 million of repayments under our 2021 Amended Term Loan Agreement.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable
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likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under U.S. GAAP. We also describe the significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with our audit committee. See Item 8. Consolidated Financial Statements and Supplementary Data —Note 1, “ Summary of Significant Events and Accounting Policies,” for a discussion of additional accounting policies and estimates made by management.
Oil and Natural Gas Activities
Full Cost Method
We use the full cost method of accounting for our oil and natural gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized into a cost center (the amortization base or full cost pool). Such amounts include the cost of drilling and equipping productive wells, treating equipment and gathering support facilities costs, dry hole costs, lease acquisition costs and delay rentals. All general and administrative costs unrelated to drilling activities are expensed as incurred. The capitalized costs of our evaluated oil and natural gas properties, plus an estimate of our future development and abandonment costs, are amortized on a unit-of-production method based on our estimate of total proved reserves. Our financial position and results of operations could have been significantly different had we used the successful efforts method of accounting for our oil and natural gas activities.
Proved Oil and Natural Gas Reserves
Estimates of our proved reserves included in this report are prepared in accordance with U.S. GAAP and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation and accretion expense and the full cost ceiling test limitation. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under defined economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.
Our estimated proved reserves for the years ended December 31, 2024 and 2023 were prepared by NSAI, an independent oil and natural gas reservoir engineering consulting firm. For more information regarding reserve estimation, including historical reserve revisions, refer to Item 8. Consolidated Financial Statements and Supplementary Data—“Supplemental Oil and Gas Information (Unaudited). ”
Depletion Expense
Our rate of recording depletion expense is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record depletion expense would increase, reducing net income. Such a reduction in reserves may result from calculated lower market prices, which may make it non-economic to drill for and produce higher cost reserves. At December 31, 2024, a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.54 per Boe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.61 per Boe.
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Full Cost Ceiling Test Limitation
Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write-down to the extent of such excess. If required, it would reduce earnings and impact stockholders’ equity in the period of occurrence and could result in lower amortization expense in future periods. The present value of our estimated proved reserves (discounted at 10%) is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that we use the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. If average oil and natural gas prices decline, it is possible that write-downs of our oil and natural gas properties could occur in the future. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.
Using the first-day-of-the-month average for the 12-months ended December 31, 2024 of the WTI crude oil spot price of $76.32 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended December 31, 2024 of the Henry Hub natural gas price of $2.13 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation did not generate an impairment at December 31, 2024, holding all other inputs and factors constant. Based on SEC prices as of March 1, 2025, the prices utilized in the first quarter 2025 full cost ceiling test limitation calculation will be $75.33 per barrel of oil and $2.44 per MMBtu of natural gas. Applying these first quarter 2025 prices and holding all other inputs constant to those used in the calculation of our December 31, 2024 ceiling test, no full cost ceiling limitation impairment is indicated for March 31, 2025. However, a full cost ceiling limitation impairment may still be realized in the future based on the outcome of numerous other factors such as declines in the actual trailing twelve-month SEC prices, production, lower commodity prices, changes in estimated future development costs and operating expenses, and other revisions to our proved reserves. Any such ceiling test impairments in the future could be material to our net earnings.
Future Development Costs
Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production facilities, gathering systems and related structures and restoration costs. We develop estimates of these costs for each of our properties based upon their geographic location, type of production facility, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis. At December 31, 2024, a five percent increase in future development and abandonment costs would increase the depletion rate by approximately $0.34 per Boe and a five percent decrease in future development and abandonment costs would decrease the depletion rate by $0.33 per Boe.
Accounting for Derivative Instruments and Hedging Activities
We account for our derivative activities under the provisions of the Financial Accounting Standards Board’s (the “FASB”) Accounting Standards Codification (“ASC” Topic 815, Derivatives and Hedging (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, in accordance with our policy, we may hedge a portion of our forecasted oil and natural gas production. We elected to not designate any of our positions for hedge accounting. Accordingly, we record the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.
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Income Taxes
Our provision for income taxes includes both state and federal taxes. We account for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. We classify all deferred tax assets and liabilities, along with any related valuation allowance, as noncurrent on the consolidated balance sheets.
In assessing the need for a valuation allowance on our deferred tax assets, we consider possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. We consider all available evidence (both positive and negative) in determining whether a valuation allowance is required. Based upon the evaluation of available evidence, a valuation allowance of $317.4 million has been applied against our deferred tax asset balance as of December 31, 2024.
ASC Topic 740, Income Taxes (“ASC 740”) creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows. The evaluation of a tax position in accordance with ASC 740 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.
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Results of Operations
Year Ended December 31, 2024 Compared to Year Ended December 31, 2023
The table below set forth financial information for the periods presented.
Years Ended
December 31,
In thousands (except per unit and per Boe amounts)
2024
2023
Operating revenues:
Oil
$
174,607
$
183,634
Natural gas
(2,213)
11,057
Natural gas liquids
20,822
23,814
Other
677
2,257
Total operating revenues
193,893
220,762
Operating expenses:
Production:
Lease operating
45,275
44,864
Workover and other
5,215
7,149
Taxes other than income
11,238
11,943
Gathering and other
54,117
63,575
General and administrative:
General and administrative
18,204
20,095
Stock-based compensation
152
(1,070)
Depletion, depreciation and accretion:
Depletion – Full cost
51,297
55,179
Depreciation – Other
638
652
Accretion expense
991
793
Impairment of contract asset
18,511
—
Other income (expenses):
Net gain on derivative contracts
2,308
12,689
Interest expense and other
(14,956)
(33,319)
Loss on extinguishment of debt
(7,489)
—
Net loss
$
(31,882)
$
(3,048)
Production:
Crude oil – MBbls
2,363
2,415
Natural gas – MMcf
7,814
8,718
Natural gas liquids – MBbls
971
1,163
Total MBoe (1)
4,636
5,031
Average daily production – Boe (1)
12,667
13,784
Average price per unit (2) :
Crude oil price - Bbl
$
73.89
$
76.04
Natural gas price - Mcf
(0.28)
1.27
Natural gas liquids price - Bbl
21.44
20.48
Total per Boe (1)
41.68
43.43
Average cost per Boe:
Production:
Lease operating
$
9.77
$
8.92
Workover and other
1.12
1.42
Taxes other than income
2.42
2.37
Gathering and other
11.67
12.64
General and administrative:
General and administrative
3.93
3.99
Stock-based compensation
0.03
(0.21)
Depletion
11.06
10.97
(1) Determined using a ratio of six Mcf of natural gas to one barrel of oil, condensate, or 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 $193.2 million and $218.5 million for the years ended December 31, 2024 and 2023, respectively. The decrease of $25.3 million in revenue is primarily attributable to a $7.6 million decrease resulting from lower average realized prices and a $17.7 million decrease due to lower production volumes in 2024 compared to 2023. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, quality of production, basis differentials and other factors.
Production for the years ended December 31, 2024 and 2023 averaged 12,667 Boe/d and 13,784 Boe/d, respectively. Production is lower in 2024 compared with 2023 in total due largely to the timing of capital expenditures spent to bring new wells online and natural production declines on our existing producing wells. In 2024, we put online 4.0 gross (3.88 net) operated wells while in 2023 we put online 3.0 gross (3.00 net) operated wells. However, two of the four operated wells placed online in 2024 were put online during the fourth quarter. As such, these wells had minimal impact on 2024 production.
Lease Operating Expenses . Lease operating expenses were $45.3 million and $44.9 million for the years ended December 31, 2024 and 2023, respectively. On a per unit basis, lease operating expenses were $9.77 per Boe and $8.92 per Boe for the years ended December 31, 2024 and 2023, respectively. The increase year over year in lease operating expenses and on a per unit basis is primarily a result of an inflationary market increase in maintenance, power, and chemical costs.
Workover and Other Expenses . Workover and other expenses were $5.2 million and $7.2 million for the years ended December 31, 2024 and 2023, respectively. On a per unit basis, workover and other expenses were $1.12 per Boe and $1.42 per Boe for the years ended December 31, 2024 and 2023, respectively. The decreased workover and other expenses in 2024 relate to fewer significant workover projects undertaken in the current year compared to 2023.
Taxes Other than Income . Taxes other than income were $11.2 million and $11.9 million for the years ended December 31, 2024 and 2023, respectively. Most production taxes are based on production volumes and realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease, as such, taxes other than income decreased due to the decrease in revenues. On a per unit basis, taxes other than income were $2.42 per Boe and $2.37 per Boe for the years ended December 31, 2024 and 2023, respectively.
Gathering and Other Expenses. Gathering and other expenses were $54.1 million and $63.6 million for the years ended December 31, 2024 and 2023, respectively. On a per unit basis, gathering and other expenses were $11.67 per Boe and $12.64 per Boe for the years ended December 31, 2024 and 2023, respectively. Our gathering and other expenses are primarily driven by the amount and location of natural gas production, the concentration of H 2 S in our sour gas produced and the amounts paid to treat our sour gas volumes, either through the AGI Facility or through third parties. For the year ended December 31, 2024, overall natural gas production volumes decreased compared to 2023 in addition to cost savings realized with the AGI Facility coming online .
General and Administrative Expense . General and administrative expense was $18.2 million and $20.1 million for the years ended December 31, 2024 and 2023, respectively. The decrease in general and administrative expense for 2024 is primarily associated with a decrease in payroll and employee benefits, partially offset by an increase in professional fees and nonrecurring costs related to the terminated merger. On a per unit basis, general and administrative expense were $3.93 per Boe and $3.99 per Boe for the years ended December 31, 2024 and 2023, respectively.
Depletion, Depreciation, and Amortization Expense. Depletion expense was $51.3 million and $55.2 million for the years ended December 31, 2024 and 2023, respectively. On a per unit basis, depletion expense was $11.06 per Boe and $10.97 per Boe for the years ended December 31, 2024 and 2023, respectively. Depletion for oil and natural gas properties is calculated using the unit-of-production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. The decrease of $3.9 million in depletion expense for the year ended December 31, 2024 compared to 2023 is primarily due to the decrease in production when comparing 2024 to 2023 . The increase in our depletion rate for the year ended December 31, 2024 compared to 2023 is primarily due to
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decreased proved reserves relative to the change in future development costs associated with those reserves when comparing 2024 to 2023.
Impairment of contract asset. We had advanced total capital contributions of approximately $18.5 million on behalf of our joint venture partner in WAT to fund a workover operation on the AGI Facility, of which $15.1 million was incurred during 2023 and the remaining $3.4 million during 2024. Pursuant to the terms of the agreement governing the joint venture, we have multiple remedies to recover such advance, including (1) declaring such payment a loan, which pursuant to the agreement would have an interest rate of the lesser of 15% or the maximum rate permitted by law, (2) recoupment from distributions from the joint venture and (3) reallocation of equity of the joint venture based on the relative level of total capital contributions by the parties after taking into account the advances, none of which would occur until the expiration of the current tolling agreement between the parties. Pursuant to such, we initially recorded the advance as a Contract asset in the Consolidated Balance Sheet and assessed the fair value of the contract asset on a quarterly basis for possible impairment. During the fourth quarter of 2024, Caracara delivered a demand notice disputing our claims, indicating that the carrying value of the contract asset may not be recoverable and as a result, we recognized $18.5 million of impairment of charges to reduce the carrying value of the contract asset to zero as of December 31, 2024.
Net gain on derivative contracts . We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes. Accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations. We recorded a net derivative gain of $2.3 million ($11.1 million net gain on unsettled contracts and $8.8 million net loss on settled contracts) for the year ended December 31, 2024 and a net derivative gain of $12.7 million ($21.9 million net gain on unsettled contracts and $9.2 million net loss on settled contracts) for the year ended December 31, 2023. At December 31, 2024, we had a $11.0 million derivative asset, $7.0 million of which was classified as current, and we had a $19.3 million derivative liability, $12.3 million of which was classified as current.
Interest Expense and Other. Interest expense and other was $15.0 million and $33.3 million for the years ended December 31, 2024 and 2023, respectively. Interest expense and other primarily decreased in the current year period compared to the same period in the prior year due to receipt of a $10.0 million payment for the merger termination combined with a $7.5 million decrease in interest expense resulting from lower average debt balances from repayment of borrowings associated with our 2021 Amended Term Loan Agreement . Our weighted average interest rate for the year ended December 31, 2024, was approximately 12.88%. For the first quarter of 2025, we anticipate our interest rate will be 12.23% on outstanding borrowings.
Loss on extinguishment of debt. On December 26, 2024, we entered into the 2024 Amended Term Loan Agreement to fully refinance and repay our 2021 Amended Term Loan Agreement and recognized a $7.5 million loss on extinguishment of debt, which includes a $3.6 million non-cash write-off of deferred financing costs, original issue discounts and embedded derivatives associated with the extinguished debt and $3.9 million in fees and debt issuance costs paid for the new debt.
Recently Issued Accounting Pronouncements
We discuss recently adopted and issued accounting standards in Item 8. Consolidated Financial Statements and Supplementary Data —Note 1, “ Summary of Significant Events and Accounting Policies .”