W&T OFFSHORE INC

Previous wording

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 September 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 624,700 gross acres (486,900 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, 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.

Current wording

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 March 31, 2026, we hold working interests in 48 producing offshore fields in federal and state waters (which include 41 fields in federal waters and seven in state waters). We currently have under lease approximately 605,200 gross acres (471,300 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, 457,700 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.

Previous wording

On November 5, 2025, we declared a regular quarterly dividend of $0.01 per share for the fourth quarter of 2025. We expect to pay the dividend on November 26, 2025 to stockholders of record as of the close of business on November 19, 2025.

Current wording

On May 7, 2026, we declared a regular quarterly dividend of $0.01 per share of common stock for the second quarter of 2026. We expect to pay the dividend on May 28, 2026 to stockholders of record as of the close of business on May 21, 2026.

Previous wording

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.

Current wording

We are also monitoring the impact of the tariffs imposed by the United States federal government. 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 our capital expenditures or operating expenses in 2026.

Previous wording

Production volumes increased by 421 MBoe to 3,275 MBoe during the three months ended September 30, 2025 compared to the same period in 2024 primarily related to well stimulation work and reduced downtime at our Mobile Bay fields andrestoring production at our West Delta 73 and Main Pass 108 fields.

Current wording

Production volumes increased by 515 MBoe to 3,259 MBoe during the three months ended March 31, 2026 compared to the same period in 2025 primarily due to restoring production at our West Delta 73, MO 916 and Main Pass 108 fields and increased production from our Mobile Bay fields due to reduced downtime, partially offset by shut-ins at our SS 349 field for approximately five days.

Previous wording

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, workover costs, facility maintenance expenses and hurricane repairs. 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 $3.8 million during the three months ended September 30, 2025 compared to the same period in 2024. On a component basis, base lease operating expenses increased $3.9 million, workover expenses increased $1.7 million, facilities maintenance expense decreased $1.5 million and hurricane repairs decreased $0.3 million.

Current wording

Lease operating expenses* –*Lease operating expenses (“LOE”) 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. LOE, which depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties, decreased $4.9 million during the three months ended March 31, 2026 compared to the same period in 2025. On a per Boe basis, LOE decreased to $20.29 per Boe during the three months ended March 31, 2026 compared to $25.88 per Boe during the three months ended March 31, 2025. On a component basis, base LOE decreased $5.2 million, workover expenses decreased $0.7 million, facilities maintenance expense increased $1.1 million and hurricane repairs decreased $0.1 million.

Previous wording

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 field.

Current wording

Expenses for direct labor, materials, supplies, repair, third-party costs and insurance comprise the most significant portion of our base LOE. These costs decreased primarily due to lower costs overall, reflecting the success of our cost reduction efforts that began in the fourth quarter of 2025 and continued into the three months ended March 31, 2026.

Previous wording

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 $0.3 million for the three months ended September 30, 2025 compared to the three months ended September 30, 2024 primarilydue to a decrease of $0.7 million in gathering and transportation expenses offset by an increase of $0.4 million in production taxes.

Current wording

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 increased $3.0 million for the three months ended March 31, 2026 compared to the three months ended March 31, 2025 primarily due to the impact of the new NGL processing contract at Mobile Bay and higher production volumes in the three months ended March 31, 2026.

Previous wording

*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&Adecreased $5.6 million for the three months ended September 30, 2025 as compared to the three months ended September 30, 2024 primarily due to a decrease of $9.2 million from the decrease in the depletion rate per Mcfe offset by an increase of $3.6 million for the increase in production. The DD&A rate per Boedecreased to $8.73 per Boe for the three months ended September 30, 2025 from $11.99 per Boe for the three months ended September 30, 2024. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs and a lower depreciable base, 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.

Current wording

*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 $5.6 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025 primarily due to a decrease of $11.6 million from the decrease in the depletion rate per thousand cubic feet equivalent offset by an increase of $6.0 million from the increase in production. The DD&A rate decreased to $8.37 per Boe for the three months ended March 31, 2026 from $11.99 per Boe for the three months ended March 31, 2025. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs, partially offset by decreased proved reserves.

Previous wording

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 increased $1.8 million the three months ended September 30, 2025 compared to the three months ended September 30, 2024 primarily due to an increase of $1.6 million in share-based compensation costs.

Current wording

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 increased $4.7 million for the three months ended March 31, 2026 compared to the three months ended March 31, 2025 primarily due to an increase of $5.4 million in share-based compensation costs, partially offset by a $1.0 million decrease in employee payroll costs.

Previous wording

Derivative gain, net* –*During the three months ended September 30, 2025, we recorded a $4.1 million derivative gain for our derivative contracts consisting of $9.7 million of realized gains, which included$7.6 million related to the monetization of our natural gas costless collar offset by a$5.6 million of unrealized loss from the decrease in the fair value of our open contracts. During the three months ended September 30, 2024, we recorded a $3.2 million derivative gainfor our natural gas derivative contracts consisting of $1.8 million of unrealized gain from the increase in the fair value of our open contracts and $1.4 million of realized gains.

Current wording

Derivative loss, net* –*During the three months ended March 31, 2026, we recorded a $24.5 million derivative loss for our derivative contracts consisting of $2.7 million of realized losses and$21.8 million of unrealized loss from the decrease in the fair value of our open contracts. During the three months ended March 31, 2025, we recorded a $2.7 million derivative lossfor our natural gas derivative contracts consisting of $3.6 million of realized losses offset by $0.9 million of unrealized gain from the increase in the fair value of our open contracts.

Previous wording

Income tax expense (benefit)* –*Our effective tax rate for the three months ended September 30, 2025 was not meaningful and differed from the federal statutory rate primarily due to the recording of a $59.9 million valuation allowance against our net deferred tax assets as it is more likely than not that all the deferred tax assets will not be utilized. Our effective tax rate for the three months ended September 30, 2024 was 11.0% and differs from the federal statutory rate primarily due to the impact of nondeductible compensation and adjustments to the valuation allowance.

Current wording

Income tax expense (benefit)* –*Our effective tax rates for the three months ended March 31, 2026 and 2025 were (13.3)% and 13.1%, respectively, and differed from the federal statutory rate primarily due to the impact of losses with no tax benefit and adjustments to the valuation allowance.

Previous wording

We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of September 30, 2025, we had $124.8 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.

Current wording

We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of March 31, 2026, we had $130.9 million of unrestricted 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 and will allow us to meet our cash requirements for at least the next 12 months and beyond.

Previous wording

Net cash provided by operating activities decreased $12.6 million in the nine months ended September 30, 2025 compared to the corresponding period in 2024. This was primarily due to decreases of $1.6 million in net loss adjusted for certain noncash items and $10.9 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 $25.2 million decrease in revenues, partially offset by an $8.0 million increase in derivative settlements and receipts and decreases in cash operating expenses. The decrease in operating assets and liabilitiesis primarily related to higher ARO settlements and unfavorable changes in accounts payable and accrued liabilities offset by favorable changes in accounts receivable.

Current wording

Net cash provided by operating activities increased $5.7 million in the three months ended March 31, 2026 compared to the corresponding period in 2025. This was primarily due to an increase of $25.5 million in net loss adjusted for certain noncash items and a decrease of $19.7 million in operating cash flows from changes in operating assets and liabilities. The increase in net loss adjusted for certain noncash items was primarily related to increases of $20.2 million in revenues and $5.6 million in derivative settlements. The decrease in operating assets and liabilitiesis primarily related to higher ARO settlements and unfavorable changes in accounts receivable, offset by favorable changes in accounts payable, accrued liabilities and other.

Previous wording

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 $31.6 million and $(104.0) million, respectively. During the nine months ended September 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 $38.9 million and $23.2 million during the nine months ended September 30, 2025 and 2024, respectively. During the nine months ended September 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.

Current wording

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 (used in) provided by investing activities were $(10.3) million and $63.3 million during the three months ended March 31, 2026 and 2025, respectively. Investments in oil and natural gas properties were $10.1 million and $6.7 million during the three months ended March 31, 2026 and 2025, respectively. During the three months ended March 31, 2025, we received $58.5 million in insurance proceeds and

Previous wording

Cash flows used in financing activities were $67.1 million and $6.6 million for the nine months ended September 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 $5.3 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 $21.3 million in premiums, fees and debt issuance costs.

Current wording

Cash flows used in financing activities were $1.9 million and $63.1 million for the three months ended March 31, 2026 and 2025, 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 a tender offer, $269.8 million of our 11.75% Senior Second Lien Notes due 2026 (the “11.75% Notes”); (ii) repay $114.2 million of amount outstanding under the credit agreement of certain of our indirect, wholly-owned subsidiaries; (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.

Previous wording

As of September 30, 2025, we expect to incur an additional $18.0 million to $24.0 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.

Current wording

As of March 31, 2026, we expect to incur an additional $12.0 million to $18.0 million of capital expenditures in the remainder of 2026, which excludes acquisitions. In our view of the outlook for the remainder of 2026, 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.

Previous wording

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 nine months ended September 30, 2025, we have paid $24.9 million related to these obligations. Our ARO estimates as of September 30, 2025 and December 31, 2024 were $566.0 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.

Current wording

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 three months ended March 31, 2026, we have paid $17.2 million related to these obligations. Our ARO estimates as of March 31, 2026 and December 31, 2025 were $566.0 million and $561.9 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 2025 Annual Report for additional information.

Previous wording

As of September 30, 2025, we have $359.1 million in aggregate principal amount of long-term debt outstanding, with $9.1 million in aggregate principal coming due over the next twelve months.

Current wording

As of March 31, 2026, we have $358.6 million in aggregate principal amount of long-term debt outstanding, with $8.6 million in aggregate principal coming due over the next twelve months.

Previous wording

During the nine months ended September 30, 2025, we declared cash dividends of $4.7 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.

Current wording

During the three months ended March 31, 2026, we declared a cash dividend of $0.01 per share of common stock. The dividend was paid on March 26, 2026 to stockholders of record as of the close of business on March 19, 2026. 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.