W&T Offshore Inc: Form 10-Q for the period ended Jun 30, 2025

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the unaudited condensed consolidated financial statements and the related notes included in Part I, Item 1. Financial Statements, of this Quarterly Report, as well as our audited consolidated financial statements and the notes thereto in the 2024 Annual Report and the related MD&A included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, of our 2024 Annual Report. Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we” and “our” are to W&T Offshore, Inc. and its wholly owned subsidiaries.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information in this Quarterly Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. These forward-looking statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Although we believe that these forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. When used in this Quarterly Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast,” “may,” “objective,” “plan,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We assume no obligation, nor do we intend, to update these forward-looking statements, unless required by law.

The information included in this Quarterly Report includes forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations as to our future financial position, liquidity, cash flows, results of operations and business strategy, potential acquisition opportunities, other plans and objectives for operations, capital for sustained production levels, expected production and operating costs, reserves, hedging activities, capital expenditures, return of capital, improvement of recovery factors and other guidance. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Known material risks that may affect our financial condition and results of operations are discussed in Part I, Item 1A. Risk Factors, and market risks are discussed in Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, of our 2024 Annual Report, and may be discussed or updated from time to time in subsequent reports filed with the SEC.

Reserve engineering is a process of estimating underground accumulations of crude oil, NGLs and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and the price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing, and production activities, or changes in commodity prices, may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of crude oil, NGLs and natural gas that are ultimately recovered.

All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

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 June 30, 2025, we hold working interests in 50 producing offshore fields in federal and state waters (which include 43 fields in federal waters and seven in state waters). We currently have under lease approximately 629,700 gross acres (491,900 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, 482,200 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.

Recent Developments

On June 14, 2025, we entered into the Settlement Agreements, by and between us and PIIC to dismiss all claims 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 our 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 our affiliates or subsidiaries; (c) there is an initiation of an insolvency proceeding for us or any of our 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.

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, which is expected to be upheld, would effectively nullify all current collateral requests 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.

For additional information about the bonding dispute and the associated Sureties Litigation, see Part I, Item 1. Financial Statements – Note 5 – Commitments and Contingencies of this Quarterly Report and Part II, Item 8. Financial Statements and Supplementary Data, in our 2024 Annual Report.

On July 4, 2025, the OBBBA was signed into law which, among other things, modified tax legislation affecting bonus depreciation rules and interest deductions. Specifically, the OBBBA provides for 100% bonus depreciation for property acquired and placed in service after January 19, 2025, and the use of earnings before income taxes, depreciation and amortization, rather than earnings before income taxes, with no phase-out for purposes of calculating the interest limitation for taxable years beginning after 2024. The OBBBA has multiple effective dates, with certain provisions effective in 2025 and others implemented through 2027. We are currently evaluating the effects of these changes and other provisions of this legislation on our condensed consolidated financial statements, and we currently expect that the OBBBA will have a favorable impact our current tax expense and valuation allowance positions due to the increased depreciation and interest expense deductions allowed under the OBBBA.

On August 4, 2025, we declared a regular quarterly dividend of $0.01 per share for the third quarter of 2025. We expect to pay the dividend on August 25, 2025 to stockholders of record as of the close of business on August 18, 2025.

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 Energy Information Administration (“EIA”) published its latest Short Term Energy Outlook in July 2025. The EIA is expecting rising global oil inventories will cause oil prices to fall from an average of $64.63 per barrel for the second quarter of 2025 to an average of $62.33 per barrel for the remainder of 2025 and then continue to fall to an average of $54.83 per barrel in 2026. The EIA is also forecasting that Henry Hub spot prices are expected to average $3.68 per MMBtu for the remainder of 2025 and $4.41 per MMBtu in 2026. The EIA is expecting that natural gas production will fall slightly in 2026, while liquified natural gas (“LNG”) exports will continue to increase, driven primarily by an increase in LNG exports as two new LNG export facilities ramp up operations.

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. 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 2025.

RESULTS OF OPERATIONS

Three Months Ended June 30, 2025 Compared to the Three Months Ended June 30, 2024

Revenues

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 the periods presented and corresponding changes (in thousands, except average realized sales prices data):

(1) MBbls — thousands of barrels of oil, condensate or NGLs

(2) MMcf — million cubic feet

(3) MBoe — thousand barrels of oil equivalent

Changes in average sales prices and production volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended June 30, 2025 and 2024 (in thousands):

Production volumes decreased by 125 MBoe to 3,052 MBoe during the three months ended June 30, 2025 compared to the same period in 2024 primarily related to low gas availability in one of our fields, a shut-in of another field due to solids production in one of the wells and a temporary curtailment of some of our Mobile Bay field for unplanned pipeline maintenance, partially offset by restoring production at our West Delta 73, Main Pass 98 and Main Pass 108 fields.

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, except average data):

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 by $2.9 million during the three months ended June 30, 2025 compared to the same period in 2024. On a component basis, base lease operating expenses increased $2.2 million, workover expenses increased $1.8 million and facilities maintenance expense decreased $1.1 million.

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 the restart of production in our West Delta 73, Main Pass 98 and Main Pass 108 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 increase in workover expenses and the decrease in facilities maintenance expenses were due to the timing and mix of projects undertaken.

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 $3.1 million for the three months ended June 30, 2025 compared to the three months ended June 30, 2024 primarily due to a decrease of $3.3 million in gathering and transportation expenses offset by an increase of $0.2 million in production taxes. Gathering and transportation expenses decreased primarily due to lower production volumes in the three months ended June 30, 2025 and 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 in the three months ended June 30, 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 $10.2 million for the three months ended June 30, 2025 as compared to the three months ended June 30, 2024 primarily due to decreases of $9.1 million from the decrease in the depletion rate per Mcfe and $1.1 million for the decrease in production. The DD&A rate per Boe decreased to $8.67 per Boe for the three months ended June 30, 2025 from $11.55 per Boe for the three months ended June 30, 2024. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs, a lower depreciable base and 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 as a 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 was relatively flat in the three months ended June 30, 2025 compared to the same period in 2024.

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. G&A expenses decreased $3.7 million for the three months ended June 30, 2025 compared to the three months ended June 30, 2024. The decrease is primarily due to a decrease of $4.7 million in non-recurring legal and professional fees, partially offset by an increase of $1.5 million in share-based compensation costs.

Other Income and Expense Items

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

Interest expense, net – Interest expense, net, decreased $1.2 million for the three months ended June 30, 2025 compared to the same period in 2024 primarily due to a decrease of $10.9 million from the redemption of the 11.75% Notes and the repayment of the Term Loan in late January 2025, partially offset by $9.9 million incurred on the 10.75% Notes issued in late January 2025.

Derivative (gain) loss, net – During the three months ended June 30, 2025, we recorded a $12.0 million derivative gain for our derivative contracts consisting of $2.5 million of unrealized gain from the increase in the fair value of our open contracts and $9.5 million of realized gains, which included $4.3 million related to the monetization of our natural gas put contracts. During the three months ended June 30, 2024, we recorded a $2.4 million derivative loss for our natural gas derivative contracts consisting of $2.7 million of unrealized loss from the decrease in the fair value of our open natural gas contracts offset by $0.3 million of realized gains.

Other expense, net – Other expense, net increased $12.2 million for the three months ended June 30, 2025 compared to the same period in 2024 primarily related to an increase in the accrual of additional expenses for net abandonment obligations related to the Company’s assumption of decommissioning obligations when certain counterparties in past divestiture transactions or third parties in existing leases have filed for bankruptcy protection or may not be able to perform required abandonment obligations.

Income tax benefit – Our effective tax rates for the three months ended June 30, 2025 and 2024 was 10.2% and 23.1%, respectively. The difference between the effective tax rate and the federal statutory rate was primarily due to the impact of nondeductible compensation and adjustments to the valuation allowance.

Six Months Ended June 30, 2025 Compared to the Six Months Ended June 30, 2024

Revenues

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 the periods presented and corresponding changes (in thousands, except average realized sales prices data):

Changes in average sales prices and production volumes caused the following changes to our oil, NGL and natural gas revenues between the six months ended June 30, 2025 and 2024 (in thousands):

Production volumes decreased by 580 MBoe to 5,796 MBoe during the six months ended June 30, 2025 compared to the same period in 2024 primarily related to low gas availability in one of our fields, a shut-in of another field due to solids production in one of the wells and deferred production at our Mobile Bay properties related to freezing weather and compressor issues, partially offset by restoring production at our West Delta 73, Main Pass 98 and Main Pass 108 fields.

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, except average data):

Lease operating expenses – 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 $3.1 million during the six months ended June 30, 2025 compared to the same period in 2024. On a per Boe basis, lease operating expenses increased to $25.52 per Boe during the six months ended June 30, 2025 compared to $22.71 per Boe during the six months ended June 30, 2024. On a component basis, base lease operating expenses decreased $1.2 million, workover expenses increased $0.8 million and facilities maintenance expense increased $3.5 million.

Base lease operating expenses increased primarily due to the restart of production in our West Delta 73, Main Pass 98 and Main Pass 108 fields partially offset by higher contract processing credits at Heidelberg due to a new platform processor.

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.

Gathering, transportation and production taxes – Gathering, transportation and production taxes decreased $5.0 million for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 primarily due to a decrease of $5.0 million in gathering and transportation expenses. Gathering and transportation expenses decreased primarily due to lower production volumes in the six months ended June 30, 2025 and 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 in the six months ended June 30, 2024.

Depreciation, depletion and amortization – D&A decreased $11.3 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024 primarily due to decreases of $5.8 million from the decrease in production and $5.5 million from the decrease in the depletion rate per Mcfe. The DD&A rate decreased to $10.24 per Boe for the six months ended June 30, 2025 from $11.07 per Boe for the six months ended June 30, 2024. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs, a lower depreciable base and 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 increased $0.7 million in the six months ended June 30, 2025 compared to the same period 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 – G&A expenses decreased $4.0 million for the six months ended June 30, 2025 compared to the six months ended June 30, 2024. The decrease is primarily due to decreases of $3.7 million in non-recurring legal and professional fees and $1.7 million in employee benefit costs due to lower medical claims costs, partially offset by a $0.5 million increase in share-based compensation costs.

Other Income and Expense Items

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

Interest expense, net – Interest expense, net, decreased $1.7 million for the six months ended June 30, 2025 compared to the same period in 2024 primarily due to a decrease of $18.2 million from the redemption of the 11.75% Notes and the repayment of the Term Loan in late January 2025, partially offset by $16.5 million incurred on the 10.75% Notes issued in late January 2025.

Loss on extinguishment of debt – During the six months ended June 30, 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) loss, net – During the six months ended June 30, 2025, we recorded a $9.3 million derivative gain for our derivative contracts consisting of $3.4 million of unrealized gain from the increase in the fair value of our open natural gas contracts and $5.9 million of realized gains, which included $4.3 million related to the monetization of our natural gas put contracts. During the six months ended June 30, 2024, we recorded a $2.5 million derivative gain for our natural gas derivative contracts consisting of $1.6 million of unrealized loss from the decrease in the fair value of our open natural gas contracts offset by $4.1 million of realized gains.

Other expense, net – Other expense, net increased $6.7 million for the three months ended June 30, 2025 compared to the same period in 2024 primarily related to an increase in the accrual of additional expenses for net abandonment obligations related to the Company’s assumption of decommissioning obligations when certain counterparties in past divestiture transactions or third parties in existing leases have filed for bankruptcy protection or may not be able to perform required abandonment obligations.

Income tax benefit – Our effective tax rates for the six months ended June 30, 2025 and 2024 was 12.0% and 11.8%, respectively. The difference between the effective tax rate and the federal statutory rate was primarily due to the impact of nondeductible compensation and adjustments to the valuation allowance.

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 June 30, 2025, we had $120.7 million of unrestricted cash on hand and $50.0 million available under our New Credit Agreement. 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 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 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) by type of activity for the following periods (in thousands):

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 decreased $24.3 million in the six months ended June 30, 2025 compared to the corresponding period in 2024. This was primarily due to a decrease of $33.2 million in net loss adjusted for certain noncash items offset by an increase of $8.9 million in operating cash flows from changes in operating assets and liabilities. The decrease in net loss adjusted for certain noncash items was primarily related to a $31.3 million decrease in revenues and a $2.0 million unfavorable change in derivative settlements and receipts, partially offset by decreases in cash operating expenses. The decrease in operating assets and liabilities is primarily related to higher ARO settlements and unfavorable changes in accounts payable and accrued liabilities offset by favorable changes in accounts receivable.

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. Cash flows provided by (used in) investing activities were $52.5 million and $(94.4) million, respectively. During the six months ended June 30, 2024, we paid $80.6 million related to our January 2024 acquisition and our September 2023 acquisition. Investments in oil and natural gas properties were $17.1 million and $13.7 million during the six months ended June 30, 2025 and 2024, respectively. During the six months ended June 30, 2025, we also 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.

Financing Activities

Cash flows used in financing activities were $65.6 million and $4.7 million for the six months ended June 30, 2025 and 2024, respectively. 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 $5.9 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 $21.3 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 capital expenditures for exploration, development, acquisitions and other leasehold costs (in thousands):

(1) Includes exploration and development capital expenditures in Alabama state waters.

As of June 30, 2025, we expect to incur an additional $15.0 million to $23.0 million of capital expenditures in the remainder of 2025, which excludes acquisitions. In our view of the outlook for the remainder of 2025, we believe this level of capital expenditure will leave us with sufficient liquidity to operate our business, 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. Through the six months ended June 30, 2025, we have paid $16.0 million related to these obligations. Our ARO estimates as of June 30, 2025 and December 31, 2024 were $556.8 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, actual expenditures could be substantially different than our estimates. See Part I, Item 1A. Risk Factors, of our 2024 Annual Report for additional information.

Debt

As of June 30, 2025, we have $359.4 million in aggregate principal amount of long-term debt outstanding, with $1.1 million in aggregate principal coming due over the next twelve months.

For additional information about our long-term debt, see Part I, Item 1. Financial Statements – Note 3 – Debt of this Quarterly Report and Part II, Item 8. Financial Statements and Supplementary Data, in our 2024 Annual Report.

Dividends

During the six months ended June 30, 2025, we paid cash dividends of $3.0 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.

Our major market risk exposure is the fluctuation of prices for oil, NGL and natural gas. These fluctuations have a direct impact on our revenues, earnings and cash flow. For example, assuming a 10% decline in our average realized oil, NGL and natural gas sales prices in the three and six months ended June 30, 2025 and assuming no other items had changed, our revenue would have decreased by approximately $11.9 million and $24.5 million in the three and six months ended June 30, 2025, respectively. This amount would be representative of the effect on operating cash flows under these price change assumptions.

We have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of natural gas production through the use of swaps, purchased calls and purchased puts. Our derivatives will not mitigate all the commodity price risks of our forecasted sales of natural gas production and, as a result, we will be subject to commodity price risks on our remaining forecasted production.

The following table summarizes the historical results of our natural gas derivatives:

Our exposure to interest rate risk has not changed materially from the disclosures in Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, of our 2024 Annual Report.

We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by Exchange Act Rule 13a-15(b), our CEO and CFO performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this Quarterly Report. Based on that evaluation, our CEO and CFO have each concluded that as of June 30, 2025, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended June 30, 2025, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

In addition to the information set forth in this Quarterly Report, investors should carefully consider the risk factors and other cautionary statements included under Part I, Item 1A. Risk Factors, in our 2024 Annual Report and in Part II, Item 1A. Risk Factors in our Quarterly Report for the quarter ended March 31, 2025 (the “q1 Report”), together with all of the other information included in this Quarterly Report, and in our other public filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

Notwithstanding the matters discussed herein, there have been no material changes in our risk factors as previously disclosed in Part I, Item 1A. Risk Factors in our 2024 Annual Report and in Part II, Item 1A Risk Factors in our Q1 Report.