Annual Report for Fiscal Year Ending December 31, 2025 (Form 10-K)

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with Part I, Item 1. Business, Item 1A. Risk Factors, Item 2. Properties and Item 7A. Quantitative and Qualitative Disclosures About Market Risk and with Part II, Item 8. Financial Statements and Supplementary Data and other financial information appearing elsewhere in this 2025 Form 10-K. The following discussion and analysis includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those anticipated in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this Form 10-K, particularly in Part I, Item 1A. Risk Factors.

This section primarily discusses 2025 and 2024 items and comparisons between 2025 and 2024. Discussions of 2024 items and comparisons between 2024 and 2023 that are not included in this Form 10-K are incorporated by reference to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2024.

Business Overview

We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of America. As of December 31, 2025, we held working interests in 49 offshore producing fields in federal and state waters (which include 42 fields in federal waters and seven in state waters). We currently have under lease approximately 624,700 gross acres (490,200 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 5,600 gross acres in Alabama state waters, 477,200 gross acres on the conventional shelf and approximately 141,900 gross acres in the deepwater. A majority of our daily production is derived from wells we operate. Our interests in fields, leases, structures and equipment are primarily owned by our wholly-owned subsidiaries and through our proportionately consolidated interest in Monza Energy LLC.

In managing our business, we are focused on optimizing production and making profitable investments, pursuing high rate of return projects and developing oil and natural gas resources in a manner that allows us to grow our production, reserves and cash flow in a capital efficient manner, organically enhancing the value of our assets.

Significant Developments

Receipt of Insurance Proceeds

In January 2025, we received $58.5 million related to the settlement of claims related to the Mobile Bay plant turnaround in February 2023. During the turnaround, the MB 78-1 well was shut-in and did not return to production following completion of the planned maintenance. We filed a claim under our Energy Package Policy and in December 2024, we and the underwriters of the Energy Package Policy agreed to a settlement of claims.

Issuance of 10.75% Notes and Related Transactions

On January 28, 2025, we issued $350.0 million of 10.75% Notes. The 10.75% Notes were issued at par and mature on February 1, 2029. The net proceeds from the issuance of the 10.75% Notes along with cash on hand were used to (i) purchase for cash pursuant to a tender offer (the "Tender Offer"), such of our 11.75% Senior Second Lien Notes due 2026 (the "11.75% Notes") that were validly tendered (and not validly withdrawn) pursuant to the Tender Offer, (ii) on or after August 1, 2025, redeem in full any remaining 11.75% Notes not validly tendered and accepted for purchase in the Tender Offer and, pending such redemptions, satisfy and discharge the indenture governing the 11.75% Notes; (iii) repay outstanding amounts under the credit agreement of certain of our indirect, wholly-owned subsidiaries (the "Term Loan"), and (iv) pay any premiums, fees and expenses relating to these transactions.

Termination of Legacy Credit Agreement and Entry into Credit Agreement

On January 28, 2025, in conjunction with the issuance of the 10.75% Notes, we terminated our Sixth Amended and Restated Credit Agreement (the "Legacy Credit Agreement") and entered into the Credit Agreement which provides us a revolving credit and letter of credit facility with initial bank lending commitments of $50.0 million with a letter of credit sublimit of $10.0 million. The Credit Agreement matures on July 28, 2028.

Appeal with the Office of Natural Resources Revenue

On August 26, 2025, the United States District Court for the Eastern District of Louisiana issued a favorable order on the Company's motion for summary judgment regarding the disallowance of allowable reduction of cash payments for royalties owed to the ONRR. On December 15, 2025 and December 16, 2025, the ONRR released the Company's administrative appeal bonds. The Company remains in discussions with the ONRR regarding the related litigation bond and the amount, if any, to be refunded or credited to the Company. As a result of the order, the Company reversed its $5.3 million accrual related to this matter.

Bonding Disputes

On June 14, 2025, we entered into the USSIC Settlement Agreement and, on June 15, 2025, we entered into the PIIC Settlement Agreement to dismiss all claims with the applicable parties related to the Sureties Litigation without prejudice. Pursuant to the applicable Settlement Agreement, USSIC and PIIC agree that: (i) there will be no change to the 2024 premium rates paid by us or any of its affiliates, subsidiaries or joint venture entities, for any currently existing surety bond executed by USSIC or PIIC until after December 31, 2026, at the earliest, (ii) USSIC and PIIC withdraw all demands for collateral and agree not to request, demand, or otherwise insist on collateral, whether related to a surety bond or pursuant to the indemnity agreements, until after December 31, 2026, at the earliest; provided that such restriction shall not apply if (a) we do not pay premiums owed to USSIC or PIIC when due; (b) a claim is made by a third party against any bond issued by USSIC or PIIC to us or its affiliates or subsidiaries; (c) there is an initiation of an insolvency proceeding for us or any of its affiliates, subsidiaries or joint venture entities, whether voluntary or involuntary; (d) there is an uncured event of default under the indenture governing our second lien notes due 2029 that results in an acceleration, in whole or in part, of the indebtedness thereunder; or (e) we or our affiliates or subsidiaries initiate a lawsuit against USSIC or PIIC. Each of the Settlement Agreements also provides that, in the event that we enter into an agreement to provide collateral to another party in settlement of the Sureties Litigation on bonds existing as of the date of the Settlement Agreement, we shall, on a pro rata basis, provide substantially similar collateral to USSIC or PIIC as it does to such other party. The entry into the Settlement Agreements resulted in the withdrawal of approximately $94 million in collateral demands.

On June 30, 2025, we announced that the presiding judge in the Sureties Litigation recommended denying the requests for preliminary injunction submitted by two surety providers. The preliminary injunction would have required us to immediately post $105 million of collateral. The recommendation would effectively nullify all current collateral requests related to the surety litigation by the surety providers and we will not be required to post collateral (if at all) until a determination on the merits of the Sureties Litigation with the remaining surety providers.

All of the remaining parties to the Sureties Litigation previously agreed to mediate the case until the mediator declares an impasse. Mediation is no longer active as the mediator has declared an impasse with respect to the surety providers that did not enter into the Settlement Agreements. We continue to evaluate potential avenues for resolution of the remaining related premium and collateral-related matters.

First Quarter 2026 Dividend

On March 5, 2026, we declared a first quarter dividend of $0.01 per share. We expect to pay the dividend on March 26, 2026 to stockholders of record on March 19, 2026.

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Business Outlook

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production. Changes in the prices that we receive for our production impact all aspects of our business; most notably our cash flows from operations, revenues, capital allocation and budgeting decisions and our reserves volumes. Prices of oil, NGLs and natural gas have historically been volatile and can fluctuate significantly over short periods of time for many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, domestic production activities and political issues, and international geopolitical and economic events.

The EIA published its latest Short-Term Energy Outlook in January 2026. The EIA expects oil prices to decline in 2026, as global oil production exceeds global oil demand, causing inventories to rise. The EIA forecasts that the spot price for WTI oil will average $52.25 per barrel in 2026, 20% less than the average price of $65.46 per barrel in 2025 and then average $50.33 per barrel in 2027. The unwinding of OPEC+ production cuts and strong growth in oil production outside of OPEC+ results in global oil production growing in the EIA forecast. Although the EIA is forecasting OPEC+ will increase production, they expect the group will produce less oil than stated in its most recent production target in an effort to avoid significant inventory builds.

The EIA expects the spot prices for Henry Hub natural gas to average $3.46 per MMBtu in 2026, down 2% from the 2025 average of $3.53 per MMBtu, and average $4.59 per MMBtu in 2027. The EIA expects wholesale natural gas prices to increase due to growth in demand, led by expanding liquified natural gas exports, and more natural gas consumption in the electric power sector from growing demand for power in the commercial and industrial sectors.

Our average realized sales price for oil and natural gas differs from the WTI average price and the NYMEX Henry Hub average price, respectively, primarily due to premiums or discounts, quality adjustments, location adjustments and volume weighting (collectively referred to as differentials). Oil price differentials primarily represent the transportation costs in moving produced oil at the wellhead to a refinery and are based on the availability of pipeline, rail and other transportation. Natural gas price differentials are strongly impacted by local market fundamentals, availability of transportation capacity from producing areas and seasonal impacts. Prices and differentials for NGLs are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products which are used as feedstock.

We are also monitoring the impact of the tariffs announced by the United States federal government in 2025 and 2026. While there is significant uncertainty as to the duration of these and any further tariffs, and the impacts these tariffs and any corresponding retaliatory tariffs will have on the oil and gas industry and on commodity prices, we do not currently expect that the financial impact of the tariffs will be material to capital expenditures or operating expenses in 2026.

Key Challenges and Uncertainties

In addition to general market conditions and competition in the oil and natural gas industry, we believe the following represent the key challenges and uncertainties we will face in the future.

Commodity Prices

A prolonged period of weak commodity prices may create uncertainties in our financial condition and results of operations. Such uncertainties may include:

Deferred Production

Our oil, NGLs and natural gas production can be significantly affected by both planned and unplanned production downtime caused by events such as planned repairs and upgrades, third-party downtime associated with non-operated properties and the transportation, gathering or processing of production and weather events. For 2025, we estimate deferred production was approximately 2.5 MMBoe.

BOEM Matters

The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations and provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities in the OCS. In April 2024, BOEM released a final rule that changed the way BOEM evaluates the financial health of companies and offshore assets in setting financial assurance requirements. Under the new rule, BOEM revised the criteria for determining whether OCS oil and natural gas lessees and grant holders are required to provide supplemental financial assurance to backstop their decommissioning obligations. On April 8, 2025, pursuant to directives from the Trump administration, the DOI, through a joint filing in the U.S. District Court for the Western District of Louisiana (Case no. 2:24-cv-00820), indicated that it will not seek supplemental financial assurance in the Gulf of America except in the case of (a) sole liability properties and (b) certain non-sole liability properties that do not have a financially strong

co-owner or predecessor in title and meet other conditions. Further, in May 2025, the DOI announced its intent to revise the rule, and in March 2026, BOEM published a proposed rule setting forth amendments to the existing financial assurance regulatory framework. The proposed rule would, among other things, (i) permit BOEM to consider the financial strength of predecessors with joint and several liability when determining whether supplemental financial assurance is required, (ii) revise the level of BSEE probabilistic estimates of decommissioning cost used for determining the amount of supplemental financial assurance required from P70 to P50, (iii) provide BOEM with discretion, in circumstances where decommissioning is scheduled to occur within one year of a supplemental financial assurance demand, to accept third-party decommissioning contracts or decommissioning schedules in lieu of requiring new supplemental financial assurance, (iv) eliminate the requirement that a lessee challenging a supplemental financial assurance demand post an appeal bond equal to the amount of the demand in order to obtain a stay pending appeal, and (v) explicitly recognize dual-obligee bonds (which identify multiple obligees) as an acceptable form of financial assurance. The proposed rule is subject to a 60-day public comment period, which is expected to end on May 8, 2026.

The substance and timing of such legal and regulatory actions cannot be predicted at this time. The future cost of compliance with respect to supplemental financial assurances, including the obligations imposed on us, whether as current or predecessor lessee or grant holder in respect of BOEM's final rule or any new, more stringent, rules related to supplemental financial assurances could materially and adversely affect our financial condition, cash flows, liquidity and results of operations. Additionally, regardless of the final rule, BOEM has the right to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder's decommissioning liabilities. For more information on the BOEM and financial assurance obligations to that agency, see Business - Environmental, Health and Safety Matters and Government Regulations - Other Regulation of the Oil and Natural Gas Industry under Part I, Item 1 of this Form 10-K.

Bonding

In prior years, some of the sureties, which provided us surety bonds that we use for supplemental financial assurance purposes, requested and received collateral from us. Pursuant to the terms of our agreement with various sureties under our existing bonding arrangements, we may be required to post collateral. These sureties may request additional collateral from us in the future, which could be significant and could materially impact our liquidity.

To the extent we are unable to provide collateral or provide an adequate alternative, including financing, we may be forced to reduce our capital expenditures in the current year or future years, may be unable to execute our ARO plan or may be unable to comply with our existing debt instruments.

To the extent that the Sureties succeed in forcing us to fulfill the Demanded Collateral, or in the event that other surety entities attempt to do the same, the fulfilment of such demands could be significant and our liquidity position could be negatively impacted, and we may be required to seek alternative financing.

For more information on risks associated with our bonding, please see Risk Factors under Part I, Item 1A of this Form 10-K.

RESULTS OF OPERATIONS

Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs. Our oil, NGL and natural gas revenues do not include the effects of derivatives, which are reported in Derivative gain, netin our Consolidated Statements of Operations.

The following table presents information regarding our revenues, production volumes and average realized sales prices (which exclude the effect of hedging unless otherwise stated) for 2025 and 2024 (in thousands, except average realized sales prices data):

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Changes in average sales prices and production volumes caused the following changes to our oil, NGL and natural gas revenues between 2025 and 2024 (in thousands):

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Production volumes increased by 219 MBoe to 12,402 MBoe during 2025 compared to the same period in 2024, primarily due to restoring production at our West Delta 73, MO 916 and Main Pass 108 fields and increased production at our Mobile Bay fields due to well stimulation work and reduced downtime, partially offset by unplanned third party pipeline outages and the shut-in of a well due to solids production.

Operating Expenses

The following table presents information regarding costs and expenses and selected average costs and expenses per Boe sold for the periods presented and corresponding changes (in thousands):

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Lease operating expenses

Lease operating expenses include the expense of operating and maintaining our wells, platforms and other infrastructure primarily in the Gulf of America. These operating costs are comprised of several components including direct or base lease operating expenses, insurance premiums, workover costs and facility maintenance expenses. Our lease operating costs, which depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties, increased $17.3 million to $298.8 million in 2025 compared to $281.5 million in 2024. On a per Boe basis, lease operating expenses increased to $24.09 per Boe during 2025 compared to $23.10 per Boe during 2024. On a component basis, base lease operating expenses increased $10.0 million, workover expenses increased $5.6 million and facility maintenance expenses increased $2.7 million. These increases were partially offset by a decrease of $1.0 million in hurricane repairs.

Expenses for direct labor, materials, supplies, repair, third-party costs and insurance comprise the most significant portion of our base lease operating expense. Base lease operating expenses increased primarily due to fields brought online during 2025 and increased repairs and maintenance in various fields, partially offset by a full year of a cost sharing agreement that began in mid-2024, cost reductions in several fields and reduced expenses from the abandonment work to shutdown certain of our fields.

Workover and facilities maintenance expenses consist of costs associated with major remedial operations on completed wells to restore, maintain or improve the well's production. Since these remedial operations are not regularly scheduled, workover and maintenance expense are not necessarily comparable from period to period. The increases in workover expenses and facilities maintenance expenses were due to the timing and mix of projects undertaken.

Hurricane expenses consist of costs for minor repairs and restoring production, as well as evacuating employees and contractors incurred as a result of Hurricanes Francine, Helene and Rafael during 2024.

Gathering, transportation and production taxes

Gathering and transportation consist of costs incurred in the post-production shipping of oil, NGLs, and natural gas to the point of sale. Production taxes consist of severance taxes levied by the Alabama Department of Revenue, the Louisiana Department of Revenue and the Texas Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of each state. Gathering, transportation and production taxes decreased to $25.7 million in 2025 compared to $28.2 million in 2024, primarily due to higher processing fees for our Mobile Bay production that had to be re-routed to a different processing plant due to the shut-in of our Mobile Bay processing plant during 2024.

Depreciation, depletion and amortization

Depreciation, depletion and amortization expense ("DD&A") is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities. DD&A decreased $26.6 million for 2025 compared to 2024 primarily due to $28.6 million from a decrease in the depletion rate per Mcfe offset by $2.0 million from the increase in production for 2025 compared with 2024. The DD&A rate decreased to $9.39 per Boe in 2025 from $11.74 per Boe in 2024. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs and a lower depreciable base, partially offset by decreased proved reserves. The lower depreciable base is due to the $58.5 million in insurance proceeds and $11.9 million of proceeds from the sale of oil and natural gas properties that were included in our full cost pool.

Asset retirement obligations accretion expense

Accretion expense is the expensing of the changes in value of our ARO asa result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values. Accretion expense increased to $33.4 million in 2025 compared to $32.4 million in 2024 primarily due to the increase in our ARO liability as a result of revisions to the estimates used in calculating the liability.

General and administrative expenses

General and administrative ("G&A") expenses generally consist of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, share-based compensation costs, audit and other fees for professional services and legal compliance. For 2025, G&A expenses were $80.0 million compared to $82.4 million in 2024. The decrease is primarily due to a decrease of $4.6 million in non-recurring legal and professional fees, partially offset by a $2.0 million increase in share-based compensation costs.

Other Income and Expense

The following table presents the components of other income and expense for the periods presented and corresponding changes (in thousands):

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Interest expense, net

Interest expense, net of interest income, decreased $4.0 million for 2025 compared with 2024 primarily due to a decrease of $42.3 million from the redemption of the 11.75% Notes and the repayment of the Term Loan in late January 2025, partially offset by $37.3 million incurred on the 10.75% Notes issued in late January 2025.

Loss on extinguishment of debt

During 2025, we recorded a loss on extinguishment of debt related to our January 2025 refinancing. The loss consisted of (i) $9.8 million of premiums paid on the redemption of the tendered 11.75% Notes; (ii) $4.6 million related to the write-off of unamortized debt issuance costs; (iii) $0.5 million of fees related to the refinancing; and (iv) $0.2 million related to the legal defeasance of the untendered 11.75% Notes.

Derivative gain, net

Unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Consolidated Statements of Operations at the end of each month. During 2025, the $13.6 million derivative gain consisted of $16.3 million of realized gains on settled contracts offset by a $2.7 million unrealized loss from the decrease in the fair value of the open contracts. During 2024, the $3.6 million derivative gain consisted of $2.9 million of realized gains on settled contracts and $0.7 million of unrealized gain, net, from the increase in the fair value of the open contracts.

Other expense, net

During 2025, other expense, net, was $8.4 million, compared to $18.1 million for 2024. The decrease in other expense, net was primarily due to (i) the release of an accrual of $5.3 million related to our dispute with the ONRR, (ii) a $3.4 million decrease in the accrual of additional expenses for net abandonment obligations related to our assumption of decommissioning obligations when certain counterparties in past divestiture transactions or third parties in existing leases have filed for bankruptcy protection or have been unable to perform required abandonment obligationsand (iii) an increase of $1.9 million in income from unconsolidated affiliates in 2025.

Income tax expense (benefit)

Our effective tax rate for 2025 was not meaningful and differed from the federal statutory rate primarily due to the recording of a $71.2 million valuation allowance in 2025 against our net deferred tax assets as it is more likely than not that our deferred tax assets in excess of our deferred tax liabilities will currently not be utilized. Our effective tax rate for 2024 was 10.3% and differed from the federal statutory rate primarily due to the impact of state income taxes, non-deductible compensation and adjustments to the valuation allowance on our deferred tax assets.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Overview

Our primary liquidity needs are to fund capital and operating expenditures and strategic acquisitions to allow us to replace our oil and natural gas reserves, repay and service outstanding borrowings, operate our properties and satisfy our ARO. We have funded such activities in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank and other borrowings, and expect to continue to do so in the future.

We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of December 31, 2025, we had $140.6 million of available cash on hand and $43.9 million available under our Credit Agreement, based on a borrowing base of $50.0 million and $6.1 million of letters of credit outstanding. We also have up to approximately $83.0 million of availability through our "at-the-market" equity offering program, pursuant to which we may offer and sell shares of our common stock from time to time. Based on our current financial condition and current expectations of future market conditions, we believe our cash on hand, cash flows from operating activities and access to the equity markets from our "at-the-market" equity offering program will provide us with additional liquidity to continue our growth to take advantage of the current commodity environment and will allow us to meet our cash requirements for at least the next 12 months and beyond.

We continuously review our liquidity and capital resources. If market conditions were to change, for instance, due to uncertainty created by geopolitical events, a pandemic or a significant prolonged decline in oil and natural gas prices, and our revenue was reduced significantly or operating costs were to increase significantly, our cash flows and liquidity could be negatively impacted.

Cash Flow Information

The following table summarizes cash flows provided by (used in) each type of activity for the following periods (in thousands):

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Operating activities

Our largest source of operating cash is collecting cash from customers and joint interest partners from sales of our products. The primary use of operating cash is to pay our suppliers, employees and others for a wide range of goods and services.

Net cash provided by operating activities for 2025 was $77.2 million, increasing $17.7 million from 2024. This was primarily due to an increase of $29.6 million from changes in operating assets and liabilities offset by a decrease of $11.9 million in net loss adjusted for certain non-cash items. The increase in operating assets and liabilities is primarily related to lower accounts receivable balances due to decreased revenues partially offset by higheraccounts payable and accrued liabilities balances in the current period. The decrease in net loss adjusted for certain non-cash items was primarily related to a $23.8 million decrease in revenues and increases in cash operating expenses, partially offset by a $10.1 million increase in derivative cash receipts.

Investing activities

Our principal recurring investing activity is the funding of acquisitions and investments in oil and natural gas properties to support and generate revenues from operations. Net cash provided by investing activities for 2025 increased $140.0 million compared to 2024. During 2025, we received $58.5 million in insurance proceeds and $11.9 million in proceeds from the sale of oil and natural gas properties. As we use the full cost method of accounting for our oil and natural gas properties, these proceeds were recorded in our full cost pool. This increase in cash flows and a $79.9 million decrease in acquisition of property interests was partially offset by an $11.3 million increase in investments in oil and natural gas properties.

Financing activities

Net cash used in financing activities during 2025 increased by $60.5 million compared to 2024. In connection with our debt refinancing in January 2025, we received $350.0 million in proceeds from the issuance of our 10.75% Notes and used these proceeds, along with cash on hand, to (i) purchase for cash, pursuant to the Tender Offer, $269.8 million of our 11.75% Notes; (ii) repay $114.2 million of amount outstanding under our Term Loan; (iii) purchase $5.3 million of government securities to be used in the legal defeasance of the remaining principal of our 11.75% Notes not validly tendered and accepted for purchase in the Tender Offer; and (iv) pay $21.8 million in premiums, fees and debt issuance costs.

Capital Expenditures

The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors including the prices of oil, NGLs and natural gas, acquisition opportunities, liquidity and financing options and the results of our exploration and development activities.

The following table presents our investments in oil and gas properties and equipment for exploration, development, acquisitions and other leasehold costs (in thousands):

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Our preliminary capital expenditure budget for 2026 has been established in the range of $19.5 million to $24.5 million, which excludes acquisitions. In our view of the outlook for 2026, we believe this level of capital expenditure will enhance our liquidity capacity throughout 2026 and beyond while providing liquidity to make strategic acquisitions. At current pricing levels, we expect our cash flows to cover our liquidity requirements, and we expect additional financing sources to be available if needed. If our liquidity becomes stressed from significant or prolonged reductions in realized prices, we have flexibility in our capital expenditure budget to reduce investments. We strive to maintain flexibility in our capital expenditure projects and if commodity prices improve, we may increase our investments.

Acquisitions

We have grown by making strategic acquisitions of producing properties in the Gulf of America. We seek opportunities where we can exploit additional drilling projects and reduce costs. Any future acquisitions are subject to the completion of satisfactory due diligence, the negotiation and resolution of significant legal issues, the negotiation, documentation and completion of mutually satisfactory definitive agreements among the parties, the consent of our lenders, our ability to finance the acquisition and approval of our board of directors. We cannot guarantee that any such potential transaction would be completed on acceptable terms, if at all.

Asset Retirement Obligations

We have obligations to plug and abandon wells, remove platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. During 2025, we paid $36.8 million related to these obligations. Our ARO estimates as of December 31, 2025 and 2024 were $561.9 million and $548.8 million, respectively. As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one-to-many years in the future, the timing and amount of actual expenditures could be substantially different than our estimates. See Part I, Item 1A. Risk Factorsand Financial Statements and Supplementary Data - Note 3 - Asset Retirement Obligations under Part II, Item 8 in this Form 10-K for additional information regarding our ARO.

Debt

As of December 31, 2025, we have $358.8 million in aggregate principal amount of long-term debt outstanding, with $8.8 million in aggregate principal amount coming due over the next twelve months.

For additional information about our long-term debt, see Part II, Item 8. Financial Statements and Supplementary Data - Note 4 - Debt of this Annual Report.

Dividends

During 2025, we declared cash dividends totaling approximately $6.4 million to holders of our common stock. The amount and frequency of future dividends is subject to the discretion of our board of directors and primarily depends on earnings, capital expenditures, debt covenants and various other factors. For additional information about our dividends, see Part II, Item 8. Financial Statements and Supplementary Data - Note 6 - Stockholders' Equity and Note 18 - Subsequent Events of this Annual Report.

Contractual Obligations and Commitments

Our material cash commitments from known contractual and other obligations consist primarily of obligations for debt and related interest, operating leases, ARO and other obligations as part of normal operations. Certain amounts included in our contractual obligations as of December 31, 2025 are based on our estimates and assumptions about these obligations, including their duration, anticipated actions by third parties and other factors.

See Financial Statements and Supplementary Data - Note 4 - Debt under Part II, Item 8 in this 10-K for information regarding scheduled maturities of our debt. See Financial Statements and Supplementary Data - Note 9 - Leases under Part II, Item 8 in this 10-K for information regarding scheduled maturities of our operating leases.

As of December 31, 2025, we have expected cash payments for estimated interest on our long-term debt of $37.8 million payable within the next twelve months and $78.4 million payable through the maturity dates of our long-term debt.

As of December 31, 2025, we had obligations for estimated fees for surety bonds related to obligations under certain purchase and sale agreements and for supplemental bonding for plugging and abandonment of $7.1 million payable in the next twelve months and $88.1 million through the estimated timing of the plugging and abandonment obligation occurs. The amounts are based on current market rates and conditions for these types of bonds and are subject to change. Excluded are potential increases in surety bond requirements which cannot be determined.

Additionally, we have obligations related to estimates of minimum quantities obligations for certain pipeline contracts which were assumed in conjunction with the purchase of an interest in the Heidelberg field of $0.4 million in the next twelve months and $0.4 million through the term of the contracts.

We have obligations under joint interest arrangements related to commitments that have not yet been incurred. In these instances, we are obligated to pay, according to our interest ownership, a portion of exploration and development costs, and operating costs, which potentially could be offset by our interest in future revenue from these non-operated properties. We also have obligations to plug and abandon well bores, remove platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations for future commitments cannot be determined due to the variability of factors involved.

CRITICAL ACCOUNTING ESTIMATES

An accounting policy is deemed to be critical if the nature of the estimate or assumption it incorporates is subject to a material level of judgment related to matters that are highly uncertain and changes in those estimates and assumptions are reasonably likely to materially impact our consolidated financial statements. These estimates reflect our best judgment about current, and for some estimates, future, economic and market conditions and their potential effects based on information available as of the date of these financial statements. Our most significant accounting policies are discussed in Financial Statements and Supplementary Data - Note 1 - Basis of Presentation and Significant Accounting Policies under Part II, Item 8 in this Form 10-K.

We believe that the following are the critical accounting estimates used in the preparation of our consolidated financial statements for the year ended December 31, 2025. There are other items within our consolidated financial statements that require estimation and judgment, but they are not deemed critical as defined above.

Accounting for Oil and Natural Gas Properties

We account for our oil and natural gas operations using the full cost method of accounting. Under this method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs, and capitalized interest. Under the full cost method, dry hole costs, geological and geophysical costs, and overhead costs directly related to these activities are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below.

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 for oil, NGLs and natural gas, which may make it non-economic to drill for and produce higher cost reserves. At December 31, 2025, a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.06 per Mcfe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.06 per Mcfe.

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 Consolidated 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 in the period of occurrence and could result in lower amortization expense in future periods.

The PV-10 of our estimated proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil, NGL 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, 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, 2025 of the WTI oil spot price of $66.01 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended December 31, 2025 of the Henry Hub natural gas price of $3.39 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation did not generate an impairment at December 31, 2025. Additionally, a 10% reduction in PV-10 at December 31, 2025, while all other factors remained constant, would also not have generated an impairment.

The policies discussed above impact the carrying value of our properties and involve significant judgments about the impact of future events on our estimated cash flows. Future events and circumstances currently unknown to us could require future impairments to our properties and materially change the carrying value of our properties.

Oil and Natural Gas Reserve Quantities

Proved oil, NGL and natural gas reserves are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board. The rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalation in future years except by contractual arrangements. Our reserve estimates are prepared by our reserve engineers and our independent petroleum consultant, NSAI.

Our reserve estimates are updated at least annually using geological and reserve data, as well as production performance data. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates, while decreases in recoverable economic volumes generally increase per unit depletion rates. A decline in proved reserves may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimate may impact the outcome of our assessment of oil and natural gas producing properties for impairment. We cannot predict what reserve revisions may be required in future periods.

We periodically reevaluate proved reserves along with estimates of future production rates, production costs and the timing of development expenditures. Future results of operations for any period could be materially affected by changes in our assumptions. Significant changes in these estimates could result in a change to our estimated reserves, which could lead to a material change to our production depletion expense.

Asset Retirement Obligations

We have significant obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We have obligations to plug and abandon all wells, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. Estimating the future restoration and removal cost requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Weaccrue a liability with respect to these obligations based on our estimates of the timing and the fair value of an obligation to replace, remove or retire the associated assets. After initial recording, the liability is accreted to its future estimated value using an assumed cost of funds.

In estimating the liability associated with our AROs, we utilize several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. To the extent future revisions to these estimates impact the value of our abandonment liability, a corresponding adjustment is made to our oil and natural gas property balance.

Income Taxes

Our income tax expense and deferred tax assets and liabilities reflect management's best assessment of estimated current and future taxes to be paid. Significant judgments and estimates are required in determining consolidated income tax expense.

Deferred income taxes arise from temporary differences between the book carrying amounts and the tax basis of assets and liabilities, which will result in taxable or deductible amounts in the future. In evaluating our ability to recover our deferred tax assets, we consider all available positive and negative evidence including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies and results of recent operations. In projecting future taxable income, we begin with historical results adjusted for changes in accounting policies and incorporate assumptions, including the amount of future U.S. federal and state pretax operating income, the reversal of temporary differences and the implementation of feasible and prudent tax-planning strategies. These assumptions require significant judgment about the forecasts of future taxable income and are consistent with the plans and estimates we use to manage the underlying business.

As of December 31, 2025, we have federal net operating loss ("NOL") carryforwards of $87.1 million that do not expire, state NOL carryforwards of $108.8 million that expire on various dates from 2038 through 2040 and interest expense limitation carryforwards of $117.5 million that do not expire. We believe that it is more likely than not that the benefit from certain of these carryforwards will not be realized. In recognition of this risk, we have provided a full

valuation allowance against the deferred tax assets related to these carryforwards. If our assumptions change and we determine that we will be able to realize these carryforwards, the tax benefits related to any reversal of the valuation allowance on deferred tax assets as of December 31, 2025 would be recognized as a reduction of income tax expense.