W&T Offshore WTI Form 10-Q filing Q2 FY2026

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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See Notes to Condensed Consolidated Financial Statements.

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See Notes to Condensed Consolidated Financial Statements.

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See Notes to Condensed Consolidated Financial Statements.

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See Notes to Condensed Consolidated Financial Statements.

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W&T OFFSHORE, INC.

Notes to Condensed Consolidated Financial Statements

NOTE 1 — NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Nature of Operations

W&T Offshore, Inc. (with subsidiaries referred to herein as the “Company”) is an independent oil and natural gas producer with substantially all of its operations offshore in the Gulf of America. The Company is active in the exploration, development and acquisition of oil and natural gas properties. The Company operates in one reportable segment.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries and an interest in Monza Energy LLC (“Monza”), which is accounted for under the proportional consolidation method. All intercompany accounts and transactions have been eliminated in consolidation. These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Accordingly, certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included.

Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in Part II, Item 8. Financial Statements and Supplementary Data of the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 (the “2025 Annual Report”).

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

NOTE 2 — FINANCIAL INSTRUMENTS

The Company’s financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities, derivative instruments and debt. Except for derivative instruments and debt, the carrying amount of the Company’s financial instruments approximates fair value due to the short-term, highly liquid nature of these instruments.

Derivative Instruments

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 30, 2026:

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(1) Bbls – barrels of oil

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W&T OFFSHORE, INC.

Notes to Condensed Consolidated Financial Statements (continued)

The fair value of the Company’s derivative financial instruments was recorded in the Condensed Consolidated Balance Sheets as follows (in thousands):

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The Company measures the fair value of its derivative instruments on a recurring basis by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The income approach converts expected future cash flows to a present value amount based on market expectations. The inputs used for the fair value measurement of derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity future prices.

The impact of commodity derivative contracts on the Condensed Consolidated Statements of Operations was as follows (in thousands):

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Debt

The following table presents the net values and estimated fair values of the Company’s debt (in thousands):

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The fair value of the TVPX Loan was measured using a discounted cash flows model and current market rates. The fair value of the 10.75% Senior Second Lien Notes due 2029 (the “10.75% Notes”) was measured using quoted prices, although the market is inactive. The fair value of debt was classified as Level 2 within the valuation hierarchy.

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W&T OFFSHORE, INC.

Notes to Condensed Consolidated Financial Statements (continued)

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NOTE 3 — ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations (“AROs”) represent the estimated present value of the amount incurred to plug, abandon and remediate the Company’s properties at the end of their productive lives. A summary of the changes to ARO is as follows (in thousands):

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NOTE 4 — DEBT

The components comprising the Company’s debt are presented in the following table (in thousands):

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As of June 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 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.

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

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W&T OFFSHORE, INC.

Notes to Condensed Consolidated Financial Statements (continued)

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NOTE 5 — COMMITMENTS AND CONTINGENCIES

ONRR Audit of Historical Refund Claims

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 the Company does not believe any accrual is necessary at this time.

Bonding Disputes

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 constitute an abuse of right; (2) the Sureties’ interpretation of the indemnity agreements render 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.

In June 2025, the Company entered into Settlement and Release Agreements (the “Settlement Agreements”), by and between the Company and USSIC and Philadelphia Indemnity Insurance Company (“PIIC”) to dismiss all of such sureties’ claims related to the Sureties Litigation without prejudice. Pursuant to the applicable Settlement Agreement, USSIC and PIIC agreed that: (i) there will be no change to the 2024 premium rates paid by the Company or any of its affiliates, subsidiaries or joint venture entities, for any currently existing surety bond executed by USSIC or PIIC until after December 31, 2026, at the earliest, (ii) USSIC and PIIC withdraw all demands for collateral and agree not to request, demand, or otherwise insist on collateral, whether related to a surety bond or pursuant to the indemnity agreements, until after December 31, 2026, at the earliest; provided that such restriction shall not apply if (a) the Company does 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 the Company or its affiliates or subsidiaries; (c) there is an initiation of an insolvency proceeding for the Company or any of its affiliates, subsidiaries or joint venture entities, whether voluntary or involuntary; (d) there is an uncured event of default under the indenture governing the 10.75% Notes that results in an acceleration, in whole or in part, of the indebtedness thereunder; or (e) the Company or its affiliates or subsidiaries initiate a lawsuit against USSIC or PIIC. Each of the Settlement Agreements also provides that, in the event that the Company enters 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, the Company shall, on a pro rata basis, provide substantially similar collateral to USSIC or PIIC as it does to such other party.

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

W&T OFFSHORE, INC.

Notes to Condensed Consolidated Financial Statements (continued)

surety entities make additional collateral demands, the fulfillment of such demands could be significant and could impact the Company’s liquidity.

Contingent Decommissioning Obligations

Certain counterparties in past divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform required abandonment obligations. Due to operation of law, the Company may be required to assume decommissioning obligations for those interests. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. The Company no longer owns these assets, nor are they related to current operations.

The changes in the contingent decommissioning obligations were as follows (in thousands):

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Although it is reasonably possible that the Company could receive state or federal decommissioning orders in the future or be notified of defaulting third parties in existing leases, the Company cannot predict with certainty if, how or when such orders or notices will be resolved or estimate a possible loss or range of loss that may result from such orders. However, the Company could incur judgments, enter into settlements or revise the Company’s opinion regarding the outcome of certain notices or matters, and such developments could have a material adverse effect on the Company’s results of operations in the period in which the amounts are accrued and the Company’s cash flows in the period in which the amounts are paid. To the extent the Company does incur costs associated with these properties in future periods, the Company intends to seek contribution from other parties that owned an interest in the facilities.

Other Claims

In the ordinary course of business, the Company is a party to various pending or threatened claims and complaints seeking damages or other remedies concerning commercial operations and other matters. In addition, claims or contingencies may arise related to matters occurring prior to the Company’s acquisition of properties or related to matters occurring subsequent to the Company’s sale of properties. In certain cases, the Company has indemnified the sellers of properties acquired, and in other cases, has indemnified the buyers of properties sold. The Company is also subject to federal and state administrative proceedings conducted in the ordinary course of business including matters related to alleged royalty underpayments on certain federal-owned properties. Although the Company can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have, the Company believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on the consolidated financial position, results of operations or liquidity of the Company.

NOTE 6 — STOCKHOLDERS’ EQUITY

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

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

W&T OFFSHORE, INC.

Notes to Condensed Consolidated Financial Statements (continued)

NOTE 7 — SHARE-BASED COMPENSATION

2026 Grants

In May 2026, the Company granted share-based compensation to its employees. The grants consisted of 2.8 million restricted stock units (“RSUs”) and 2.6 million performance stock units (“PSUs”).

The RSUs were valued as of the grant date and vest 1/3 each year on May 29, 2027, 2028 and 2029. The grant date fair value of the RSUs was $10.2 million.

The PSUs are subject to performance criteria of (i) total shareholder return and relative shareholder return (collectively, the “TSR PSUs”), (ii) cash return on capital employed (the “CROCE PSUs”) and (iii) reserve performance (the “Reserve PSUs”). The performance period for the measurement of the performance goals began on January 1, 2026 and ends on December 31, 2028. To be eligible to receive the earned PSUs, employees must be employed from the grant date through December 31, 2028. Different levels of achievement across these metrics will affect the percentage of PSUs that the employee receives upon the satisfaction of the service requirement. The percentage of PSUs received upon vesting ranges from 0% to 200%.

The TSR PSUs will account for 50% of the target PSUs granted to employees. The TSR PSUs contain both a service condition and a market condition. The grant date fair value of the TSR PSUs was $8.5 million and was calculated using a Monte Carlo simulation.

The CROCE PSUs and Reserve PSUs will account for 40% and 10%, respectively, of the target PSUs granted to employees. The CROCE PSUs and Reserve PSUs contain both a service condition and a performance condition. The grant date fair value of the CROCE PSUs and Reserve PSUs, which was determined using the closing price of the Company’s common stock on the date of grant, was $3.8 million and $1.0 million, respectively. The cumulative compensation cost that will be recognized will be equal to the fair value of the awards deemed probable of vesting multiplied by the percentage of the requisite service period that has been rendered. Unlike the TSR PSUs, if the performance condition is not satisfied, any previously recognized compensation expense is reversed.

As of the grant date, the Company did not have enough shares of common stock available under its long-term incentive plan to satisfy its commitments to deliver shares upon vesting. Accordingly, the Company will account for these awards as liability awards, and the fair value of these awards will be remeasured at the end of each reporting period based on either the current market price of the Company’s common stock (for RSUs and PSUs with both a service condition and a performance condition) or through the use of the Monte Carlo simulation method (for the PSUs with both a service condition and a market condition).

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

The Company records income taxes for interim periods based on an estimated annual effective tax rate. The estimated annual effective rate is recomputed on a quarterly basis and may fluctuate due to changes in forecasted annual operating income, positive or negative changes to the valuation allowance for net deferred tax assets and changes to actual or forecasted permanent book to tax differences.

The Company’s effective tax rates for the three and six months ended June 30, 2026 were (12.2)% and (14.6)%, respectively. These effective tax rates differ from the federal statutory rate primarily due to the impact of losses with no tax benefit and adjustments to the Company’s valuation allowance. The Company’s effective tax rates for the three and

W&T OFFSHORE, INC.

Notes to Condensed Consolidated Financial Statements (continued)

six months ended June 30, 2025 were 10.2% and 12.0%, respectively. These effective tax rates differ from the federal statutory rate primarily due to state income tax expense and adjustments to the Company’s valuation allowance.

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 mainly due to negative 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 June 30, 2026 and December 31, 2025, the Company had a valuation allowance of $101.7 million and $100.3 million, respectively.

NOTE 9 — NET INCOME (LOSS) PER COMMON SHARE

The following table presents the calculation of basic and diluted net income (loss) per common share (in thousands, except per share amounts):

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(1) Includes RSUs and PSUs as their effect, if included, would have been anti-dilutive.

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W&T OFFSHORE, INC.

Notes to Condensed Consolidated Financial Statements (continued)

NOTE 10 — INVESTMENT IN MONZA

Monza is considered to be a variable interest entity. As the Company is not considered to be the primary beneficiary of Monza, the Company does not fully consolidate Monza but instead consolidates Monza based on its ownership interest.

The following table presents the amounts recorded by the Company on the Condensed Consolidated Balance Sheets related to the consolidation of the proportional interest in Monza’s operations (in thousands):

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The following table presents the amounts recorded by the Company in the Condensed Consolidated Statements of Operations related to the consolidation of the proportional interest in Monza’s operations (in thousands):

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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 30, 2026 and December 31, 2025, the unused advances were $2.3 million and $2.4 million, respectively, which are included in Advances from joint interest partners in the Condensed Consolidated Balance Sheets*.*

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

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NOTE 11 — SEGMENT INFORMATION

The Company reports its operations in one reportable segment which is engaged in the acquisition, development and production of oil, NGLs and natural gas offshore in the Gulf of America. The segment derives revenue from the sale of produced oil, NGLs and natural gas.

The measure of profit or loss that the Chief Operating Decision Maker (the “CODM”) uses to assess performance and allocate resources for the operating segment is consolidated net loss. The CODM uses consolidated net loss in deciding whether to reinvest profits into the operating segment or into other activities, such as for acquisitions or to return capital to shareholders through a combination of dividends and/or share repurchases.

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

The CODM is regularly provided with only the consolidated expenses as noted on the face of the Condensed Consolidated Statements of Operations and, accordingly, these expenses are considered to be significant expenses.

W&T OFFSHORE, INC.

Notes to Condensed Consolidated Financial Statements (continued)

NOTE 12 — OTHER SUPPLEMENTAL INFORMATION

Condensed Consolidated Balance Sheet Details

Prepaid expenses and other current assets consisted of the following (in thousands):

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Accrued liabilities consisted of the following (in thousands):

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Condensed Consolidated Statements of Cash Flows Information

Supplemental statements of cash flows information consisted of the following (in thousands):

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 2025 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 2025 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.

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, 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 gross acres (457,100 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 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.

Recent Developments

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

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.

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.

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.

RESULTS OF OPERATIONS

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

Revenues

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

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

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

(2) MMcf — million cubic feet

(3) MBoe — thousand barrels of oil equivalent

(4) Boe — barrels of oil equivalent

(5) Bbl — barrels of oil, condensate or NGLs

(6) Mcf — thousand cubic feet

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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 30, 2026 and 2025 (in thousands):

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Production volumes increased by 105 MBoe to 3,157 MBoe during the three months ended June 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.

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):

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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 million during the three months ended June 30, 2026 compared to the same period in 2025. On a per Boe basis, LOE decreased to $22.67 per Boe during the three months ended June 30, 2026 compared to $25.20 per Boe during the three months ended June 30, 2025. On a component basis, base LOE decreased $2.5 million, workover expenses decreased $1.1 million, facilities maintenance expense decreased $1.9 million and hurricane repairs increased $0.1 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 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 are not necessarily comparable from period to period. The decreases 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 million for the three months ended June 30, 2026 compared to the three months ended June 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 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 million for the three months ended June 30, 2026 as compared to the three months ended June 30, 2025 primarily due to a decrease of $1.6 million from the decrease in the depletion rate per thousand cubic feet equivalent (“Mcfe”) offset by an increase of $0.9 million from the increase in production. The DD&A rate decreased to $8.10 per Boe for the three months ended June 30, 2026 from $8.67 per Boe for the three months ended June 30, 2025. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs, partially offset by decreased 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 million for the three months ended June 30, 2026 compared to the three months ended June 30, 2025 primarily due to increases of $8.2 million in share-based compensation costs and $1.1 million in legal and professional fees.

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):

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

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.

Income tax benefit – Our effective tax rates for the three months ended June 30, 2026 and 2025 were (12.2)% and 10.2%, 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.

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

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):

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

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Production volumes increased by 620 MBoe to 6,416 MBoe during the six months ended June 30, 2026 compared to the same period in 2025 primarily due to restoring production at our West Delta 73, 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.

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):

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Lease operating expenses – LOE decreased $10.3 million during the six months ended June 30, 2026 compared to the same period in 2025. On a per Boe basis, LOE decreased to $21.46 per Boe during the six months ended June 30, 2026 compared to $25.52 per Boe during the six months ended June 30, 2025. On a component basis, base LOE decreased $7.8 million, workover expenses decreased $1.7 million and facilities maintenance expense decreased $0.8 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 months ended June 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 are not necessarily comparable from period to period. The decreases 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 increased $4.1 million for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 primarily due to the impact of the new NGL processing contract at Mobile Bay and higher production volumes in the six months ended June 30, 2026.

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

General and administrative expenses – G&A expenses increased $14.5 million for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 primarily due to an increase of $13.5 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):

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

Other expense, net – Other expense, net decreased $12.0 million for the six months ended June 30, 2026 compared to the same period in 2025 primarily related to an accrual of additional expenses in the six 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.

Income tax expense (benefit) – Our effective tax rates for the six months ended June 30, 2026 and 2025 were (14.6)% and 12.0%, 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.

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, 2026, we had $150.7 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 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):

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Operating Activities

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

Net cash provided by operating activities increased $11.1 million in the six months ended June 30, 2026 compared to the corresponding period in 2025. This was primarily due to an increase of $53.2 million in net loss adjusted for certain noncash items and a decrease of $42.1 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 $60.4 million in revenues offset by an increase of $16.4 million in derivative settlements. The decrease 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.

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 (used in) provided by investing activities were $(19.0) million and $52.5 million during the six months ended June 30, 2026 and 2025, respectively. Investments in oil and natural gas properties were $18.8 million and $17.1 million during the six months ended June 30, 2026 and 2025, respectively. During the six months ended June 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.

Financing Activities

Cash flows used in financing activities were $6.8 million and $65.6 million for the six months ended June 30, 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.

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):

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

In our view of the outlook for the remainder of 2026, we believe our expected 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, 2026, we have paid $20.6 million related to these obligations. Our ARO estimates as of June 30, 2026 and December 31, 2025 were $573.2 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.

Debt

As of June 30, 2026, we have $358.3 million in aggregate principal amount of long-term debt outstanding, with $8.3 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 4 – Debt of this Quarterly Report and Part II, Item 8. Financial Statements and Supplementary Data, in our 2025 Annual Report.

Dividends

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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, 2026 and assuming no other items had changed, our revenue would have decreased by approximately $15.9 million and $30.5 million in the three and six months ended June 30, 2026, 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 production through the use of swaps, purchased calls and purchased puts. Our derivatives will not mitigate all the commodity price risks of our forecasted 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 derivatives:

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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 2025 Annual Report.

ITEM 4. CONTROLS AND PROCEDURES

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, 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 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.

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Part I, Item 1. Financial Statements – Note 5 – Commitments and Contingencies of this Quarterly Report for information on various legal proceedings to which we are a party or our properties are subject.

ITEM 1A. RISK FACTORS

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 2025 Annual 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 2025 Annual Report.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

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ITEM 5. OTHER INFORMATION

During the three months ended June 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).

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ITEM 6. EXHIBITS

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* Filed herewith.

** Furnished herewith.

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​ W&T OFFSHORE, INC.

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​ By: /s/ Sameer Parasnis

​ Sameer Parasnis

​ Executive Vice President and Chief Financial Officer ​

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