W&T Offshore reports $167M revenue

Cover page 2 changes

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For the quarterly period ended June September 30, 2026

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As of July 31, October 20, 2026, there were 150,942,952 154,895,304 shares outstanding of the registrant s common stock, par value $0.00001.

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Financial statements 31 changes

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Joint interest, net of allowance for credit losses of $ 10,629 10,638 and $ 10,529 , respectively

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Oil and natural gas properties and other, net of accumulated depreciation, depletion and amortization of $ 8,526,024 8,554,290 and $ 8,473,181 , respectively

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Common stock: $ 0.00001 par value; 400,000 shares authorized; 153,785 157,758 shares and 151,647 shares issued, respectively

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Six Months Ended June 30,

Three Months Ended June September 30,

Nine Months Ended September 30,

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Other operating expenses

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Income tax expense (benefit)

Other expense (income), net

Income Loss before income taxes

Net income loss per common share (basic and diluted)

Weighted average common shares outstanding: (basic and diluted)

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Balances at March 31, 2026

Balances at June 30, 2026

Net proceeds from issuance of common stock

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Reclassification of liability-classified awards to equity-classified awards

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Balances at March 31, 2025

Balances at June September 30, 2026

Balances at June 30, 2025

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Balances at June September 30, 2025

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Proceeds from issuance of common stock

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Balances at June September 30, 2026

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Balances at June September 30, 2025

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Six Months Ended June 30,

Nine Months Ended September 30,

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Deferred income tax (benefit) expense

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Distribution from unconsolidated affiliate

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Proceeds from issuance of New TVPX Loan

Purchase of government securities in connection with legal defeasance of 11.75 % Senior Second Lien Notes ( 5,889 5,348 )

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Proceeds from issuance of common stock

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Net cash provided by (used in) financing activities

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Note 2: FINANCIAL INSTRUMENTS 4 changes

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July 2026 - Dec 2026

July 2026 - Dec 2026

The following table reflects the contracted volumes and weighted average prices under the terms of the Company s open oil derivative contracts as of June September 30, 2026:

July Oct 2026 - April 2027

Note 3: ASSET RETIREMENT OBLIGATIONS 2 changes

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Six Months Ended June 30,

Nine Months Ended September 30,

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Note 4: DEBT 3 changes

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As of June 30, 2026, the Company was in compliance with all applicable covenants.

In September 2026, the promissory note evidencing the TVPX Loan was amended and restated pursuant to the Second Amended and Restated Promissory Note (as so amended and restated, the New TVPX Loan ), and the $ 8.0 million of proceeds from the New TVPX Loan were used to repay the $ 8.0 million of balloon payment that was due at the maturity date of the TVPX Loan. The New TVPX Loan bears a fixed interest rate of 6.18 % per annum and requires monthly amortization payments of $ 83.3 thousand plus accrued interest, and a balloon payment of $ 5.0 million at the end of the loan term in September 2029. The New TVPX Loan is secured by the aircraft financed and is guaranteed by the Company on an unsecured basis.

As of June September 30, 2026, there were no borrowings outstanding under the Credit Agreement, dated as of January 28, 2025, by and among the Company, Texas Capital Bank, as administrative agent, and the various agents and lenders party thereto (the Credit Agreement ) and letters of credit outstanding were $ 6.6 million. There was $ 43.4 million available for the issuance of letters of credit and borrowings under the Credit Agreement as of June 30, 2026, based on a borrowing base of $ 50.0 million and $ 6.6 million of letters of credit outstanding.

Note 5: COMMITMENTS AND CONTINGENCIES 4 changes

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In 2023, the Company received notification from the Office of Natural Resources Revenue (the ONRR ) regarding results of an audit performed on the Company s historical refund claims taken on various properties for alleged royalties owed to the ONRR. The review process is ongoing, and In September 2026, the Company does not believe any accrual is necessary at finalized a settlement with ONRR resolving this time. matter. The settlement provides for a net ONRR royalty credit of approximately $ 8.5 million that is expected to be realized through reduced royalty payments beginning in the fourth quarter of 2026.

Since October 2024, the Company has been involved in litigation with certain providers of private and government-required surety bonds, including Endurance Assurance Corporation, Lexon Insurance Company, U.S. Specialty Insurance Company ( USSIC ), Pennsylvania Insurance Company a/k/a Applied Surety Underwriters and United States Fire Insurance Company (collectively, the Sureties ), that secure decommissioning obligations or ONRR disputed matters the Company may have with respect to certain oil and natural gas assets of the Company (the Sureties Litigation ). The Company contends that (1) the Sureties may not enforce their indemnity agreements such that their action actions constitute an abuse of right; (2) the Sureties interpretation of the indemnity agreements render renders the agreements illusory; (3) the Sureties may not make unreasonable demands for collateral; (4) the Sureties must accept reasonable collateral as offered by the Company; (5) no additional collateral is required of the Company; (6) the Sureties may not make joint demands for collateral that are inconsistent with those of each other such that the Company cannot comply with each demand; and (7) the Sureties changed business model is not legitimate grounds to demand further collateral beyond that offered by the Company. The Company has also filed counterclaims against the Sureties claiming: (1) violations of the Sherman Antitrust Act; (2) violations of the Texas Free Enterprise and Antitrust Act; (3) violations of the Texas Insurance Code Section 541; (4) tortious interference with existing contracts and prospective business relationships; and (5) conspiracy.

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In June 2025, 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 the Company to immediately post $ 105 million of collateral. The recommendation effectively nullified all current collateral requests by the surety providers and provided that the Company did not need to post collateral until a determination on the merits of the Sureties Litigation with the remaining surety providers.

The Sureties Litigation with respect to the Sureties other than USSIC and PIIC remains ongoing. To the extent that the Company is required to fulfill the collateral demands made by the remaining surety entities, or in the event that other

Notes to the financial statements 4 changes

In June 2025, 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 the Company to immediately post $ 105 million of collateral. The recommendation effectively nullified all current collateral requests by the surety providers and provided that the Company did not need to post collateral until a determination is made on the merits of the Sureties Litigation with the remaining surety providers.

The Sureties Litigation with respect to the Sureties other than USSIC and PIIC remains ongoing. To the extent that the Company is required to fulfill the collateral demands made by the remaining surety entities, or in the event that other surety entities make additional collateral demands, the fulfillment of such demands could be significant and could impact the Company s liquidity.

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Six Months Ended June 30,

Nine Months Ended September 30,

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Note 6: STOCKHOLDERS EQUITY 4 changes

At-the-Market Equity Offering

During the three months ended September 30, 2026, the Company sold an aggregate of 3.6 million shares of common stock for an average price of $ 4.16 per share in connection with the Company s at-the-market equity offering program and received proceeds, net of commissions and expenses, of $ 14.7 million. As of September 30, 2026, the Company has $ 68.1 million of remaining availability under this program.

During the six nine months ended June September 30, 2026, the Company declared cash dividends of $ 3.2 4.9 million.

On August 5, October 29, 2026 , the Company s board of directors declared a regular quarterly dividend of $ 0.01 per share of common stock for the third fourth quarter of 2026. The dividend is to be paid on August 26, November 19, 2026 to stockholders of record at the close of business on August 19, November 12, 2026 .

Note 7: SHARE-BASED COMPENSATION 2 changes

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Modification of awards

In June 2026, the Company s long-term incentive plan was amended to increase the shares available for issuance from 10.0 million to 22.0 million. As a result of this increase, the Company reclassified the RSUs and PSUs that were granted in 2025 from liability awards to equity awards. The modification resulted in the remeasurement of the TSR PSUs at $ 7.44 per share and the remaining PSUs and RSUs at $ 4.01 per share on the modification date. The liability balance as of the modification date of $ 11.0 million was reclassified to additional paid in capital.

Note 8: INCOME TAXES 2 changes

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The Company s effective tax rates for the three and six nine months ended June September 30, 2026 were ( 12.2 3.8 )% and ( 14.6 8.1 )%, respectively. These effective tax rates differ from the federal statutory rate primarily due to the impact of losses with no tax benefit, nondeductible compensation and adjustments to the Company s valuation allowance. The Company s effective tax rates for the three and nine months ended September 30, 2025 were not meaningful due to the Company recording a valuation allowance against its net deferred tax assets during that quarter.

At each reporting date, the Company considers all available positive and negative evidence to evaluate whether its deferred tax assets are more likely than not to be realized. During 2025, the amount of the Company s deferred tax assets considered realizable was reduced due to negative evidence that outweighed positive evidence supporting its ability to realize its deferred tax assets. The Company was able to support that a portion of its deferred tax assets would be realizable through the generation of income from future reversals of existing taxable temporary differences and recorded a valuation allowance against the remaining unsupported deferred tax assets. As of September 30, 2026 and December 31, 2025, the Company had a valuation allowance of $ 103.8 million and $ 100.3 million, respectively.

Note 10: INVESTMENT IN MONZA 4 changes

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Six Months Ended June 30,

Nine Months Ended September 30,

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As required, the Company may call on Monza to provide cash to fund its portion of certain projects in advance of capital expenditure spending. As of June September 30, 2026 and December 31, 2025, the unused advances were $ 2.3 2.1 million and $ 2.4 million, respectively, which are included in Advances from joint interest partners in the Condensed Consolidated Balance Sheets .

During the six nine months ended June September 30, 2026, Monza paid cash distributions of $ 8.2 13.6 million, of which $ 1.7 2.8 million was paid to the Company.

Note 11: SEGMENT INFORMATION 1 change

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As the Company discloses a single reportable segment, total operating net revenues for the Company s operating segment is are reported in its Condensed Consolidated Statements of Operations and segment assets is are reported in its Condensed Consolidated Balance Sheets.

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Note 12: OTHER SUPPLEMENTAL INFORMATION 4 changes

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Six Months Ended June 30,

Nine Months Ended September 30,

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ARO - acquisitions, additions, dispositions and revisions, net

ARO - additions and revisions, net

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Forward-looking statements 58 changes

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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 September 30, 2026, we hold working interests in 48 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 591,000 588,500 gross acres (457,100 (455,800 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, 449,200 446,700 gross acres on the conventional shelf and approximately 136,200 gross acres in the deepwater. A majority of our daily production is derived from wells we operate.

On October 1, 2026, we entered into the Amended Credit Agreement, pursuant to which our revolving credit facility was converted into a reserve-based revolving credit facility, with an aggregate maximum credit amount of $100.0 million and an aggregate elected commitment amount initially set at $50.0 million . For additional information about the Amended Credit Agreement, see Part I, Item 1. Financial Statements Note 13 Subsequent Event .

On August 5, October 29, 2026, we declared a regular quarterly dividend of $0.01 per share of common stock for the third fourth quarter of 2026. We expect to pay the dividend on August 26, November 19, 2026 to stockholders of record as of the close of business on August 19, November 12, 2026.

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On June 18, 2026, the United States and Iran signed a memorandum of understanding ( MOU ) related to the conflict between the two countries, including with respect to the re-opening of the Strait of Hormuz, which had been closed earlier in 2026 and had contributed to elevated oil prices. Expectations of increasing oil supply and moderating inventory draws have caused oil prices to fall. The average spot price for WTI oil averaged $84.81 per barrel in June 2026, down $17.32 per barrel from May 2026. In the Energy Information Administration s (the EIA ) Short-Term Energy Outlook published in July 2026, the EIA is forecasting that spot prices for WTI will average $68.50 per barrel for the remainder of 2026 and $60.83 per barrel in 2027. The EIA expects that ongoing oil inventory accumulation over the next year will continue to put downward pressure on oil prices.

Just over a week after signing the MOU, Iran launched a drone strike against a ship in the Strait of Hormuz. The attack, interpreted by the United States as a violation of the ceasefire agreement, prompted a round of contained strikes against Iran. In addition, Yemen s Houthis opened a new front in the war by targeting vessels carrying Saudi oil, further disrupting global oil shipping as the Red Sea is another strategic waterway that oil companies use to transport their oil from the Middle East. Although oil prices rose as a result of these disruptions, prices are still significantly lower than the high prices experienced in the middle of May 2026. Workarounds via pipelines and the use of the southern shipping route through the Strait of Oman have kept the cost of oil from skyrocketing, and production worldwide has also stepped up in response to the off-and-on closure of the Strait of Hormuz.

The Henry Hub spot price averaged $2.95 per MMBtu for the second quarter of 2026, and the EIA expects the spot prices for Henry Hub natural gas to average $3.47 per MMBtu for the remainder of 2026 and average $3.49 per MMBtu in 2027. The EIA expects that record natural gas production will help meet rising demand from the electric power sector, putting moderate downward pressure on natural gas prices.

In its Short-Term Energy Outlook published in October 2026, the Energy Information Administration (the EIA ) assumes that a combination of convoys through the Strait of Hormuz and workarounds to oil exports from the Middle East, including bypass routes and increased use of ship-to-ship transfers, will lead to production and exports from the region generally increasing through the forecast period. In spite of the increased production and flows from the Middle East, the EIA is forecasting that the spot price for WTI will average $97.00 per barrel in the fourth quarter of 2026 and then fall to an average of $80.00 per barrel in 2027. The attacks on the East-West pipeline in Saudi Arabia highlight the potential for continued volatility in physical oil flows and oil prices amid ongoing withdrawals of oil inventories globally. Additional upward pressure on oil prices stems from extreme tightness in diesel markets that raises demand for oil in order for refiners to meet diesel demand.

The EIA is forecasting the Henry Hub spot price for natural gas to average $3.16 per MMBtu in 2027, a 9% decrease from 2026. The decrease reflects ongoing higher-than-average natural gas inventories driven by production increases that offset rising liquefied natural gas exports.

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Three Months Ended June September 30, 2026 Compared to the Three Months Ended June September 30, 2025

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Three Months Ended June September 30,

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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 the three months ended June September 30, 2026 and 2025 (in thousands):

Production volumes increased by 105 239 Mboe to 3,157 3,514 MBoe during the three months ended June September 30, 2026 compared to the same period in 2025 primarily due to restoring production at our West Delta 73 and Eugene Island 64 fields and recompletion of a well at our Garden Banks 783 field. partially offset by reduced production at our Mobile Bay fields due to a temporary re-route of production due to third-party maintenance.

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Three Months Ended June September 30,

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Other operating expenses

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Other operating expenses

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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 $5.4 increased $0.5 million during the three months ended June September 30, 2026 compared to the same period in 2025. On a per Boe basis, LOE decreased to $22.67 $21.82 per Boe during the three months ended June September 30, 2026 compared to $25.20 $23.27 per Boe during the three months ended June September 30, 2025. On a component basis, base LOE decreased $2.5 $3.2 million, workover expenses decreased increased $1.1 million and facilities maintenance expense decreased $1.9 million and hurricane repairs increased $0.1 $2.6 million.

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 June September 30, 2026.

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 expenses are not necessarily comparable from period to period. The decreases increases in workover expenses and 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 increased $1.1 $3.6 million for the three months ended June September 30, 2026 compared to the three months ended June September 30, 2025 primarily due to the impact of the new NGL processing contract at Mobile Bay and higher production volumes in the three months ended June September 30, 2026 .

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 $0.9 $0.3 million for the three months ended June September 30, 2026 as compared to the three months ended June September 30, 2025 primarily due to a decrease of $1.6 $2.1 million from the decrease in the a lower depletion rate per thousand cubic feet equivalent ( Mcfe ) offset by an increase of $0.9 $2.0 million from the increase in production. The DD&A rate decreased to $8.10 $8.04 per Boe for the three months ended June September 30, 2026 from $8.67 $8.73 per Boe for the three months ended June September 30, 2025. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs partially offset by decreased and increased proved reserves.

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 $9.8 $10.2 million for the three months ended June September 30, 2026 compared to the three months ended June September 30, 2025 primarily due to increases of $8.2 $6.9 million in share-based compensation costs and $1.1 $2.9 million in legal and professional fees.

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Three Months Ended June September 30,

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Other expense, net Other expense, net decreased $13.2 million for the three months ended June 30, 2026 compared to the same period in 2025 primarily related to an accrual of additional expenses in the three months ended June 30, 2025 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 may not be able to perform required abandonment obligations.

Other expense (income), net

Derivative loss (gain), net During the three months ended June September 30, 2026, we recorded a $1.9 $15.8 million derivative loss for our oil derivative contracts consisting of $13.7 $9.9 million of realized losses offset by $11.8 and $5.9 million of unrealized gain loss from the increase decrease in the fair value of our open contracts . During the three months ended June September 30, 2025, we recorded a $12.0 $4.1 million derivative gain for our natural gas derivative contracts consisting of $9.5 $9.7 million of realized gains and $2.5 offset by $5.6 million of unrealized gain loss from the increase decrease in the fair value of our open contracts.

Income tax benefit expense Our effective tax rates rate for the three months ended June September 30, 2026 and 2025 were (12.2)% and 10.2%, respectively, was (3.8)% and differed from the federal statutory rate primarily due to the impact of losses with no tax benefit, nondeductible compensation and adjustments to the valuation allowance. 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 valuation allowance against our net deferred tax assets.

Six Nine Months Ended June September 30, 2026 Compared to the Six Nine Months Ended June September 30, 2025

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Six Months Ended June 30,

Nine Months Ended September 30,

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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 the six nine months ended June September 30, 2026 and 2025 (in thousands):

Production volumes increased by 620 859 MBoe to 6,416 9,930 MBoe during the six nine months ended June September 30, 2026 compared to the same period in 2025 primarily due to recompletion of a well at our Garden Banks 783 field, restoring production at our West Delta 73 and Eugene Island 64 Mobile Bay 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 .

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Six Months Ended June 30,

Nine Months Ended September 30,

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Other operating expenses

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Other operating expenses

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Lease operating expenses LOE decreased $10.3 $9.8 million during the six nine months ended June September 30, 2026 compared to the same period in 2025. On a per Boe basis, LOE decreased to $21.46 $21.59 per Boe during the six nine months ended June September 30, 2026 compared to $25.52 $24.71 per Boe during the six nine months ended June September 30, 2025. On a component basis, base LOE decreased $7.8 $11.0 million, workover expenses decreased $1.7 $0.6 million and facilities maintenance expense decreased $0.8 increased $1.8 million.

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 six nine months ended June September 30, 2026.

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 expenses are not necessarily comparable from period to period. The decreases decrease in workover expenses and the increase in facilities maintenance expenses were due to the timing and mix of projects undertaken.

Gathering, transportation and production taxes Gathering, transportation and production taxes increased $4.1 $7.6 million for the six nine months ended June September 30, 2026 compared to the six nine months ended June September 30, 2025 primarily due to the impact of the new NGL processing contract at Mobile Bay and higher production volumes in the six nine months ended June September 30, 2026 .

Depreciation, depletion and amortization DD&A decreased $6.5 $6.8 million for the six nine months ended June September 30, 2026 as compared to the six nine months ended June September 30, 2025 primarily due to a decrease of $12.5 $14.5 million from the decrease in the a lower depletion rate per Mcfe offset by an increase of $6.2 $8.1 million from the increase in production. The DD&A rate decreased to $8.24 $8.17 per Boe for the six nine months ended June September 30, 2026 from $10.24 $9.69 per Boe for the six nine months ended June September 30, 2025. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs partially offset by decreased and increased proved reserves.

General and administrative expenses G&A expenses increased $14.5 $24.7 million for the six nine months ended June September 30, 2026 compared to the six nine months ended June September 30, 2025 primarily due to an increase of $13.5 $20.4 million in share-based compensation costs and $3.5 million in legal and professional fees.

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Six Months Ended June 30,

Nine Months Ended September 30,

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Income tax expense (benefit)

Derivative loss (gain), net During the six nine months ended June September 30, 2026, we recorded a $26.4 $42.2 million derivative loss for our oil derivative contracts consisting of $16.4 $26.2 million of realized losses and $10.0 $16.0 million of unrealized loss from the decrease in the fair value of our open contracts . During the six nine months ended June September 30, 2025, we recorded a $9.3 $13.4 million derivative gain for our natural gas derivative contracts consisting of $5.9 $15.5 million of realized gains and $3.4 offset by $2.1 million of unrealized gain loss from the increase decrease in the fair value of our open contracts.

Other expense, net Other expense, net decreased $12.0 $9.8 million for the six nine months ended June September 30, 2026 compared to the same period in 2025 primarily related to an accrual of additional expenses in the six nine months ended June September 30, 2025 for net new 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 may not be able to perform required abandonment obligations.

Income tax expense (benefit) Our effective tax rates rate for the six nine months ended June September 30, 2026 and 2025 were (14.6)% and 12.0%, respectively, was (8.1)% and differed from the federal statutory rate primarily due to the impact of losses with no tax benefit, nondeductible compensation and adjustments to the valuation allowance. Our effective tax rate for the nine months ended September 30, 2025 was not meaningful and differed from the federal statutory rate primarily due to the recording of a valuation allowance against our net deferred tax assets.

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We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of June September 30, 2026, we had $150.7 $191.3 million of unrestricted cash on hand and $43.4 million available under our Credit Agreement, based on a borrowing base of $50.0 million and $6.6 million of letters of credit outstanding. We also have up to approximately $83.0 $68.1 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.

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Six Months Ended June 30,

Nine Months Ended September 30,

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Net cash provided by operating activities increased $11.1 $21.2 million in the six nine months ended June September 30, 2026 compared to the corresponding period in 2025. This was primarily due to an increase a favorable change of $53.2 $62.9 million in net loss adjusted for certain noncash items and a decrease offset by an unfavorable change of $42.1 $41.7 million in operating cash flows from changes in operating assets and liabilities. The increase favorable change in net loss adjusted for certain noncash items was primarily related to increases of $60.4 $100.0 million in revenues offset by an increase of $16.4 $35.1 million in derivative settlements. The decrease unfavorable change in operating assets and liabilities is primarily related to higher ARO settlements and unfavorable changes in accounts receivable, accounts payable and accrued liabilities and other.

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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 $(19.0) $(27.1) million and $52.5 $31.6 million during the six nine months ended June September 30, 2026 and 2025, respectively. Investments in oil and natural gas properties were $18.8 $26.9 million and $17.1 $38.9 million during the six nine months ended June September 30, 2026 and 2025, respectively. During the six nine months ended June September 30, 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.

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Cash flows provided by (used in) financing activities were $6.8 $5.3 million and $65.6 $(67.1) million for the six nine months ended June September 30, 2026 and 2025, respectively. During the nine months ended September 30, 2026, we used $8.0 million in proceeds from our New TVPX Loan to repay the $8.0 million of balloon payment that was due at the maturity date of the TVPX Loan. In addition, we received $14.7 million in net proceeds from the sale of our common stock in connection with our at-the-market equity offering program. 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 $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 $21.7 million in premiums, fees and debt issuance costs.

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Six Months Ended June 30,

Nine Months Ended September 30,

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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 nine months ended June September 30, 2026, we have paid $20.6 $26.5 million related to these obligations. Our ARO estimates as of June September 30, 2026 and December 31, 2025 were $573.2 $580.8 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.

As of June September 30, 2026, we have $358.3 $358.0 million in aggregate principal amount of long-term debt outstanding, with $8.3 $1.0 million in aggregate principal coming due over the next twelve months.

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During the six nine months ended June September 30, 2026, we declared cash dividends of $3.2 $4.9 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.

Market risk 1 change

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 nine months ended June September 30, 2026 and assuming no other items had changed, our revenue would have decreased by approximately $15.9 $16.2 million and $30.5 $46.8 million in the three and six nine months ended June September 30, 2026, respectively. This amount would be representative of the effect on operating cash flows under these price change assumptions.

9 unchanged paragraphs

Controls and procedures 2 changes

1 unchanged paragraph

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 September 30, 2026, 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 September 30, 2026, 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.

Other information 1 change

During the three months ended June September 30, 2026, none of our directors or officers (as such term is defined in Rule 16(a)-1(f) under the Exchange Act) adopted or terminated a Rule 10b5-1 trading agreement or non-Rule 10b5-1 trading arrangement (each as defined in Item 408(a) and (c) of Regulation S-K).

Exhibits 3 changes

2 unchanged paragraphs

First Amendment No. 1 to the Amended and Restated Employment Agreement, dated as of August 5, 2026, by and between W&T Offshore, Inc. 2023 Incentive Compensation Plan and Tracy W. Krohn (Incorporated by reference to Exhibit 10.1 of to the Company s Current Report on Form 8-K, filed June 4, August 7, 2026)

Second Amendment to Credit Agreement, dated as of October 1, 2026, by and among W&T Offshore, Inc., the subsidiary guarantors party thereto, Texas Capital Bank, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company s Current Report on Form 8-K, filed October 7, 2026)

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Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on August 5, October 29, 2026.

1 unchanged paragraph