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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

☑	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2025

☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______________ to ________________

Commission File Number 1-32414

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)


Texas		72-1121985
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

5718 Westheimer Road, Suite 700, Houston, Texas		77057-5745
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (713) 626-8525

Securities registered pursuant to section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.00001	WTI	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every interactive data file required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ☐	Accelerated filer	☑
Non-accelerated filer ☐	Smaller reporting company	☐
	Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company. Yes ☐ No ☑

As of October 31, 2025, there were 148,777,224 shares outstanding of the registrant’s common stock, par value $0.00001.

Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION		1

Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets as of September 30, 2025 and December 31, 2024	1
	Condensed Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2025 and 2024	2
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three Months and Nine Months Ended September 30, 2025 and 2024	3
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2025 and 2024	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 4.	Controls and Procedures	29

PART II – OTHER INFORMATION		30

Item 1.	Legal Proceedings	30
Item 1A.	Risk Factors	30
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30
Item 3.	Defaults Upon Senior Securities	30
Item 4.	Mine Safety Disclosures	30
Item 5.	Other Information	30
Item 6.	Exhibits	30

SIGNATURE		32

Table of Contents

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

W&T OFFSHORE, INC.

Condensed Consolidated Balance Sheets

(In thousands)

(Unaudited)


	September 30,		December 31,
	2025		2024
Assets
Current assets:
Cash and cash equivalents	$	124,795	$	109,003
Restricted cash		1,552		1,552
Accounts receivable:
Oil, natural gas liquids and natural gas sales		57,280		63,558
Joint interest, net of allowance for credit losses of $10,477 and $10,414, respectively		28,118		25,841
Prepaid expenses and other current assets		17,506		18,504
Total current assets		229,251		218,458

Oil and natural gas properties and other, net of accumulated depletion and amortization of $8,444,693 and $8,356,776, respectively		678,671		777,741
Restricted deposits for asset retirement obligations		23,019		22,730
Deferred income taxes		—		48,808
Other assets		29,685		31,193
Total assets	$	960,626	$	1,098,930
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable	$	89,438	$	83,625
Accrued liabilities		18,928		33,271
Undistributed oil and natural gas proceeds		54,582		53,131
Advances from joint interest partners		2,395		2,443
Current portion of asset retirement obligations		34,528		46,326
Current portion of long-term debt, net		8,600		27,288
Total current liabilities		208,471		246,084

Asset retirement obligations		531,493		502,506
Long-term debt, net		341,843		365,935
Other liabilities		17,515		16,182

Commitments and contingencies		33,791		20,800

Shareholders’ deficit:
Preferred stock: $0.00001 par value; 20,000 shares authorized; no shares issued		—		—
Common stock: $0.00001 par value; 400,000 shares authorized; 151,642 shares and 150,243 shares issued, respectively		2		2
Additional paid-in capital		603,140		595,407
Retained deficit		(751,462)		(623,819)
Treasury stock: 2,869 shares, at cost		(24,167)		(24,167)
Total shareholders’ deficit		(172,487)		(52,577)
Total liabilities and shareholders’ deficit	$	960,626	$	1,098,930

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

W&T OFFSHORE, INC.

Condensed Consolidated Statements of Operations

(In thousands, except per share data)

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues:
Oil	$	84,131	$	90,862	$	251,861	$	308,842
NGLs		4,000		5,636		13,487		21,265
Natural gas		37,400		23,148		107,311		66,674
Other		1,984		1,726		7,090		8,135
Total revenues		127,515		121,372		379,749		404,916

Operating expenses:
Lease operating expenses		76,215		72,412		224,151		217,229
Gathering, transportation and production taxes		5,818		6,147		16,976		22,265
Depreciation, depletion, and amortization		28,580		34,206		87,917		104,817
Asset retirement obligations accretion		8,002		7,848		25,075		24,217
General and administrative expenses		21,510		19,723		59,337		61,592
Total operating expenses		140,125		140,336		413,456		430,120

Operating loss		(12,610)		(18,964)		(33,707)		(25,204)

Interest expense, net		8,998		9,992		27,495		30,228
Loss on extinguishment of debt		—		—		15,015		—
Derivative gain, net		(4,108)		(3,199)		(13,398)		(5,702)
Other (income) expense, net		(2,017)		15,709		11,122		22,189
Loss before income taxes		(15,483)		(41,466)		(73,941)		(71,919)
Income tax expense (benefit)		55,991		(4,545)		48,994		(8,136)
Net loss	$	(71,474)	$	(36,921)	$	(122,935)	$	(63,783)

Net loss per common share (basic and diluted)	$	(0.48)	$	(0.25)	$	(0.83)	$	(0.43)

Weighted average common shares outstanding (basic and diluted)		148,589		147,206		148,015		147,002

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

W&T OFFSHORE, INC.

Condensed Consolidated Statements of Changes in Shareholders’ Equity

(In thousands)

(Unaudited)


	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Equity (Deficit)
Balances at June 30, 2025	148,293	$	2	$	599,945	$	(678,501)	2,869	$	(24,167)	$	(102,721)
Cash dividends	—		—		—		(1,487)	—		—		(1,487)
Share-based compensation	—		—		3,537		—	—		—		3,537
Stock issued	480		—		—		—	—		—		—
Shares withheld related to net settlement of equity awards	—		—		(342)		—	—		—		(342)
Net loss	—		—		—		(71,474)	—		—		(71,474)
Balances at September 30, 2025	148,773	$	2	$	603,140	$	(751,462)	2,869	$	(24,167)	$	(172,487)


	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Equity (Deficit)
Balances at June 30, 2024	147,162	$	2	$	589,678	$	(560,508)	2,869	$	(24,167)	$	5,005
Cash dividends	—		—		—		(1,518)					(1,518)
Share-based compensation	—		—		1,956		—	—		—		1,956
Stock issued	183		—		—		—	—		—		—
Shares withheld related to net settlement of equity awards	—		—		(32)		—	—		—		(32)
Net income	—		—		—		(36,921)	—		—		(36,921)
Balances at September 30, 2024	147,345	$	2	$	591,602	$	(598,947)	2,869	$	(24,167)	$	(31,510)


	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Deficit
Balances at December 31, 2024	147,374	$	2	$	595,407	$	(623,819)	2,869	$	(24,167)	$	(52,577)
Cash dividends	—		—		—		(4,708)	—		—		(4,708)
Share-based compensation	—		—		8,497		—	—		—		8,497
Stock issued	1,399		—		—		—	—		—		—
Shares withheld related to net settlement of equity awards	—		—		(764)		—	—		—		(764)
Net loss	—		—		—		(122,935)	—		—		(122,935)
Balances at September 30, 2025	148,773	$	2	$	603,140	$	(751,462)	2,869	$	(24,167)	$	(172,487)


	Common Stock			Additional							Total
	Outstanding			Paid-In		Retained		Treasury Stock			Shareholders’
	Shares	Value		Capital		Deficit		Shares	Value		Equity (Deficit)
Balances at December 31, 2023	146,581	$	1	$	586,014	$	(530,656)	2,869	$	(24,167)	$	31,192
Cash dividends	—		—		—		(4,508)	—		—		(4,508)
Share-based compensation	—		—		6,374		—	—		—		6,374
Stock issued	764		1		—		—	—		—		1
Shares withheld related to net settlement of equity awards	—		—		(786)		—	—		—		(786)
Net loss	—		—		—		(63,783)	—		—		(63,783)
Balances at September 30, 2024	147,345	$	2	$	591,602	$	(598,947)	2,869	$	(24,167)	$	(31,510)

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

W&T OFFSHORE, INC.

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2025		2024
Operating activities:
Net loss	$	(122,935)	$	(63,783)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		112,992		129,034
Share-based compensation		8,497		6,374
Amortization of debt issuance costs		2,605		3,445
Loss on extinguishment of debt		15,015		—
Derivative gain, net		(13,398)		(5,702)
Derivative cash receipts, net		14,169		6,165
Deferred income expense (benefit)		48,808		(8,136)
Changes in operating assets and liabilities:
Accounts receivable		4,001		(2,557)
Prepaid expenses and other current assets		674		(3,242)
Accounts payable, accrued liabilities and other		5,748		22,602
Asset retirement obligation settlements		(24,873)		(20,344)
Net cash provided by operating activities		51,303		63,856

Investing activities:
Investment in oil and natural gas properties and equipment		(38,881)		(23,233)
Acquisition of property interests		(711)		(80,635)
Proceeds from sale of oil and natural gas properties		11,916		—
Insurance proceeds		58,500		—
Purchases of furniture, fixtures and other		(121)		(166)
Distribution from unconsolidated affiliate		927		—
Net cash provided by (used in) investing activities		31,630		(104,034)

Financing activities:
Proceeds from issuance of 10.75% Senior Second Lien Notes		350,000		—
Repayment of 11.75% Senior Second Lien Notes		(269,830)		—
Repayment of Term Loan		(114,159)		—
Repayments of TVPX Loan		(825)		(825)
Purchase of government securities in connection with legal defeasance of 11.75% Senior Second Lien Notes		(5,348)		—
Premium payments and debt extinguishment costs		(10,230)		—
Debt issuance costs		(11,478)		(579)
Payment of dividends		(4,507)		(4,427)
Other		(764)		(785)
Net cash used in financing activities		(67,141)		(6,616)

Change in cash, cash equivalents and restricted cash		15,792		(46,794)
Cash, cash equivalents and restricted cash, beginning of year		110,555		177,755
Cash, cash equivalents and restricted cash, end of period	$	126,347	$	130,961

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

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, 2024 (the “2024 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 costless collar contracts as of September 30, 2025:


	Average
	Daily	Total	Weighted		Weighted
Period	Volumes	Volumes	Floor Price		Ceiling Price
Oil (WTI)	(Bbls) ⁽¹⁾	(Bbls)	($/Bbls)		($/Bbls)
Oct 2025 - Dec 2025	2,000	184,000	$	63.00	$	77.25

⁽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):


	September 30,		December 31,
	2025		2024
Prepaid expenses and other current assets	$	546	$	868
Other assets		—		4,150
Accrued liabilities		30		3,731

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):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Realized gain ⁽¹⁾	$	(9,691)	$	(1,370)	$	(15,545)	$	(5,489)
Unrealized (gain) loss		5,583		(1,829)		2,147		(213)
Derivative gain, net	$	(4,108)	$	(3,199)	$	(13,398)	$	(5,702)

⁽¹⁾	The three and nine months ended September 30, 2025 include $7.6 million and $11.9 million, respectively, related to the monetization of the Company’s natural gas put contracts and costless collar.

Debt

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


	September 30, 2025				December 31, 2024
	Net Value		Fair Value		Net Value		Fair Value
Term Loan	$	—	$	—	$	112,132	$	109,727
11.75% Notes		—		—		272,081		278,765
10.75% Notes		341,843		338,695		—		—
TVPX Loan		8,600		8,809		9,010		9,395
Total	$	350,443	$	347,504	$	393,223	$	397,887

The fair values of the TVPX Loan and the Term Loan were measured using a discounted cash flows model and current market rates. The fair values of the 10.75% Notes and the 11.75% Notes were 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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Notes to Condensed Consolidated Financial Statements (continued)

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):


	Nine Months Ended September 30,
	2025		2024
Asset retirement obligations, beginning of period	$	548,832	$	498,815
Liabilities settled		(24,873)		(20,342)
Accretion expense		25,075		24,217
Liabilities acquired		—		17,647
Disposition of oil and natural gas properties		(1,469)		—
Liabilities incurred		1,029		—
Revisions of estimated liabilities		17,427		34,690
Asset retirement obligations, end of period		566,021		555,027
Less: Current portion		(34,528)		(45,139)
Long-term	$	531,493	$	509,888

NOTE 4 — DEBT

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


	September 30,		December 31,
	2025		2024
10.75% Senior Second Lien Notes due 2029:
Principal	$	350,000	$	—
Unamortized debt issuance costs		(8,157)		—
Total		341,843		—

Term Loan:
Principal		—		114,159
Unamortized debt issuance costs		—		(2,027)
Total		—		112,132

11.75% Senior Second Lien Notes due 2026:
Principal		—		275,000
Unamortized debt issuance costs		—		(2,919)
Total		—		272,081

TVPX Loan:
Principal		9,100		9,925
Unamortized discount		(418)		(771)
Unamortized debt issuance costs		(82)		(144)
Total		8,600		9,010

Total debt, net		350,443		393,223
Less current portion, net		(8,600)		(27,288)
Long-term debt, net	$	341,843	$	365,935

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W&T OFFSHORE, INC.

Notes to Condensed Consolidated Financial Statements (continued)

Issuance of 10.75% Senior Second Lien Notes due 2029

On January 28, 2025, the Company issued and sold $350.0 million in aggregate principal amounts of its 10.75% Senior Second Lien Notes (the “10.75% Notes”), which are governed under an indenture dated January 28, 2025 (the “Indenture”). The 10.75% Notes mature on February 1, 2029 and interest is payable on each February 1 and August 1, commencing August 1, 2025. The 10.75% Notes are guaranteed by the Company’s direct and indirect wholly-owned subsidiaries (the “Guarantors”). The 10.75% Notes are secured by second priority liens (subject to permitted liens and certain other exceptions) on substantially all of the oil and natural gas properties of the Company and the Guarantors.

Prior to February 1, 2027, the Company may redeem all or any portion of the 10.75% Notes at a redemption price equal to 100% of the principal amount of the outstanding 10.75% Notes plus accrued and unpaid interest to the redemption date plus the Applicable Premium (as defined in the Indenture). In addition, prior to February 1, 2027, the Company may, at its option, on one or more occasions, redeem up to 35% of the aggregate original principal amount of the 10.75% Notes in an amount not greater than the net cash proceeds from certain equity offerings at a redemption price of 110.75% of the principal amount of the outstanding 10.75% Notes plus accrued and unpaid interest to the redemption date.

From February 1, 2027 to (and including) January 31, 2028, the Company may redeem the 10.75% Notes in whole or in part, at redemption prices (expressed as percentages of the principal amount thereof) equal to 105.375% and 100.000% from February 1, 2028 and thereafter, plus accrued and unpaid interest, if any, to the redemption date.

The Indenture includes a number of covenants that, among other things, limit the Company’s ability and the ability of its Restricted Subsidiaries (as defined in the Indenture), including the Guarantors, to (i) make investments; (ii) incur additional indebtedness or issue certain types of preferred stock; (iii) create certain liens; (iv) sell assets; (v) enter into agreements that restrict dividends or other payments from the Company’s subsidiaries to the Company; (vi) consolidate, merge or transfer all or substantially all of the assets of the Company; (vii) engage in transactions with affiliates; (viii) pay dividends or make other distributions on capital stock or subordinated indebtedness; and (ix) create subsidiaries that would not be restricted by the covenants of the Indenture. These covenants are subject to important exceptions and qualifications set forth in the Indenture. In addition, most of the above-described covenants will terminate if both S&P Global Ratings, a division of S&P Global Inc., and Moody’s Investors Service, Inc. assign the Notes an investment grade rating and no default exists with respect to the Notes.

The Indenture provides for customary events of default, which include (subject in certain cases to customary grace and cure periods) nonpayment of principal or interest; breach of other agreements in the Indenture; failure to pay certain other indebtedness; the failure to pay certain final judgments against the Company or its Restricted Subsidiaries; the failure of certain guarantees to be enforceable; and certain events of bankruptcy or insolvency.

The Company used the net proceeds from the issuance of the 10.75% Notes, along with cash on hand, to (i) purchase for cash pursuant to a tender offer (the “Tender Offer”), such of the Company’s 11.75% Senior Second Lien Notes due 2026 (the “11.75% Notes”) that were validly tendered pursuant to the terms thereof; (ii) repay the $114.2 million of outstanding amounts under the credit agreement of certain of the Company’s indirect, wholly-owned subsidiaries (the “Term Loan”); (iii) fund the full redemption amount for an August 1, 2025 redemption of the remaining 11.75% Notes not validly tendered and accepted for purchase in the Tender Offer; and (iv) pay any premiums, fees and expenses relating to these transactions.

Redemption of the 11.75% Notes

On January 13, 2025, the Company commenced the Tender Offer for any and all of the Company’s outstanding 11.75% Notes. On January 28, 2025, the Company accepted and purchased $269.7 million aggregate principal amount of the outstanding 11.75% Notes for a purchase price equal to $1,036.25 for each $1,000 principal amount of the Notes purchased. An additional $89,000 of Notes were tendered on February 12, 2025. The Company purchased these Notes for $89,905 plus accrued interest.

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Notes to Condensed Consolidated Financial Statements (continued)

After giving effect to this purchase, an aggregate $5.2 million principal amount of the 11.75% Notes remained outstanding. The Company then effected a legal defeasance of the 11.75% Notes by purchasing $5.9 million of government securities and depositing these government securities with the trustee. The government securities generated sufficient cash upon maturity to effect the trustee’s optional redemption on August 1, 2025 of the remaining $5.2 million of outstanding principal plus interest. The $0.5 million of excess funds were then returned to the Company. Upon the deposit of the government securities with the trustee, the Company caused the satisfaction and discharge of the indenture governing the 11.75% Notes. The trustee acknowledged such discharge and satisfaction. As a result, the Company and the Guarantors of the 11.75% Notes have been released from their remaining obligations under the indenture governing the 11.75% Notes.

These transactions were accounted for as an extinguishment and the Company recognized a loss of $15.0 million in the nine months ended September 30, 2025.

Credit Facility

On January 28, 2025, in conjunction with the issuance of the 10.75% Notes, the Company terminated its Sixth Amended and Restated Credit Agreement and entered into a new credit agreement (the “Credit Agreement”) which provides the Company a revolving credit and letter of credit facility (the “Credit Facility”), with initial bank lending commitments of $50.0 million with a letter of credit sublimit of $10.0 million. The Credit Facility matures on July 28, 2028. The Credit Facility is guaranteed by the Guarantors and is secured by a first-priority lien on substantially all of the natural gas and oil properties and personal property assets of the Company and the Guarantors and the Company’s ownership in certain joint venture entities.

The Credit Agreement requires prepayment of all outstanding revolving loans every three months commencing on March 31, 2025, and the Company is prohibited from borrowing for a five-day period following such prepayment. To the extent the Consolidated Net Leverage Ratio (as defined in the Credit Agreement) exceeds 2.00 to 1.00 on the last day of any calendar month, the Company would be required to prepay the revolving loans in an amount equal to 75% of Excess Cash Flow (as defined in the Credit Agreement). If the aggregate amount outstanding under the Credit Facility exceeds the Credit Facility commitments at any time, the Company would be required to immediately upon request repay indebtedness to eliminate such excess. The Company will be required to make additional prepayments in the event of certain dispositions or casualty events, as more particularly described in the Credit Agreement.

Borrowings under the Credit Facility bear interest at a variable rate per annum which, at the Company’s option, is equal to either (a) an adjusted rate based on the Secured Overnight Financing Rate (“SOFR”) plus an applicable margin that varies from 3.75% to 4.75% depending on the utilization of the Credit Agreement or (b) a base rate plus an applicable margin that varies from 2.75% to 3.75%, such base rate calculated based on the highest of (i) the federal funds effective rate plus ½ of 1.0%, (ii) the U.S. Prime Rate and (iii) an adjusted SOFR rate for a one-month interest period plus 1.0%. Interest is payable quarterly in arrears for Base Rate loans, at the end of the applicable interest period for Term SOFR loans (but not less frequently than quarterly) and upon the prepayment or maturity of the underlying loans.

Additionally, the Company is required to pay both a quarterly commitment fee of 0.5% and a quarterly letter of credit fee in arrears in respect of unused commitments under the Credit Facility, and an annual administrative fee in the amount of $45,000, paid quarterly as set forth in the Credit Agreement. The applicable margins and letter of credit fee are calculated based upon the utilization levels of the Credit Facility as a percentage of the borrowing base then in effect and range from 3.75% to 4.75%.

The Credit Agreement includes certain customary affirmative and negative covenants including, but not limited to, restrictions on the Company’s ability to incur additional indebtedness, create liens on the Company’s property, pay dividends and make restricted payment or certain investments, in each cash subject to certain exceptions. The Credit Agreement also requires the Company to (i) maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1.00 to 1.00 for each fiscal quarter; (ii) maintain a ratio of consolidated total debt to EBITDAX of no greater than 2.50x, tested on a rolling four quarter basis; and (iii) maintain a minimum PDP PV-10 (as defined in the Credit Agreement) of $100 million as of the last day of any fiscal quarter.

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Notes to Condensed Consolidated Financial Statements (continued)

In the event the Revolving Credit Exposure (as defined in the Credit Agreement) is greater than or equal to $20.0 million, the Company is required to enter into hedging transactions with prices, notional amounts and periods of time as applicable in the Credit Agreement.

On or before January 28, 2026, the Company is required to use commercially reasonable efforts to enter into an amendment or amendment and restatement of the Credit Agreement to include a reserve-based lending construct. If the Credit Agreement is not so amended or amended and restated, the aggregate commitments of the lenders will be redetermined on a semi-annual basis on February 1 and August 1 of each year, using the reserve reports delivered on or before December 31 and June 30, respectively. The Company will be required to prepay the amount of credit exposure that exceeds the newly redetermined commitment amount. Failure to convert the Credit Facility to a reserve-based lending facility is not an event of default under the Credit Agreement.

On September 3, 2025, the Company entered into the First Amendment to the Credit Agreement (“First Amendment”) effective as of March 1, 2025. The First Amendment amends the Credit Agreement to require that any calculation of PDP PV-10 (as defined in the Credit Agreement) deduct reasonable costs and expenses associated with asset retirement obligations. In addition, the First Amendment revises the reporting covenant to require delivery of an Excess Cash Flow Certificate (as defined in the Credit Agreement) within thirty days after the end of the calendar month in which the initial borrowing occurs and within thirty days after the end of each calendar month thereafter. In connection with the First Amendment, the Company and its guarantor subsidiaries each reaffirmed their respective obligations under the Credit Agreement and related Loan Documents (as defined in the Credit Agreement), all of which remain in full force and effect.

As of September 30, 2025, there were no borrowings outstanding under the Credit Agreement and no borrowings had been incurred under the Credit Agreement during the nine months ended September 30, 2025.

Covenants

As of September 30, 2025, the Company was in compliance with all applicable covenants.

NOTE 5 — COMMITMENTS AND CONTINGENCIES

Appeal with the Office of Natural Resources Revenue

In 2009, the Company recognized allowable reductions of cash payments for royalties owed to the Office of Natural Resources Revenue (the “ONRR”) for transportation of its deepwater production through subsea pipeline systems owned by the Company. In 2010, the ONRR audited calculations and support related to this usage fee, and ONRR notified the Company that they had disallowed approximately $4.7 million of the reductions taken. As of September 30, 2025, the Company has accrued $5.0 million related to this matter, consisting of $4.7 million for the disallowed reductions and $0.3 million for estimated penalties. The Company disagrees with the position taken by the ONRR and filed an appeal with the ONRR.

On August 26, 2025, the United States District Court for the Eastern District of Louisiana issued an order on the Company’s motion for summary judgment. The Company is in discussions with the ONRR regarding release of the related litigation bond and the amount, if any, to be refunded or credited to the Company. Such discussions are currently delayed due to the federal government shutdown.

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Notes to Condensed Consolidated Financial Statements (continued)

ONRR Audit of Historical Refund Claims

In 2023, the Company received notification from 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

On August 14, 2024, the Company filed a complaint seeking declaratory relief (the “Original Complaint”) in the U.S. District Court for the Southern District of Texas, Houston Division, against Endurance Assurance Corporation and Lexon Insurance Company (the “Sompo Sureties”), providers of private and government-required surety bonds that secure decommissioning obligations or ONRR disputed matters the Company may have with respect to certain oil and gas assets of the Company (the “Sompo Sureties Litigation”). As described in the Original Complaint, the Company has paid all negotiated premiums associated with the bonds issued by the Sompo Sureties prior to the Original Complaint and has not suffered a material change to its financial status. Despite this, the Sompo Sureties issued written demands to the Company requesting the Company provide collateral to the Sompo Sureties. On October 9, 2024, the Sompo Sureties filed an answer and counterclaim alleging breach of contract due to the Company’s failure to provide the collateral demanded by the Sompo Sureties. The Sompo Sureties originally issued approximately $55.0 million in surety bonds on behalf of the Company. However, the BOEM cancelled a $13.1 million bond when the Company fulfilled its decommissioning obligations. Despite this, the Sompo Sureties have requested approximately $55.0 million in cash collateral.

On October 21, 2024, U.S. Specialty Insurance Company (“USSIC”) filed a petition in the District Court of Harris County, Texas, alleging, among other things, breach of the indemnity agreement between the Company and USSIC and seeking to compel the Company to provide the collateral demanded by USSIC (the “USSIC Litigation”). On October 25, 2024, the Company filed a notice of removal with the District Court of Harris County, Texas, removing the case to U.S. District Court for the Southern District of Texas, Houston Division. USSIC has issued approximately $111.0 million in surety bonds on behalf of the Company and has requested $23.0 million in cash collateral.

On November 8, 2024, Pennsylvania Insurance Company a/k/a Applied Surety Underwriters (“Applied”) filed a petition in the United States District Court for the Southern District of Texas, Houston Division, alleging, among other things, breach of the indemnity agreement between the Company and Applied and seeking to compel the Company to provide the collateral demanded by Applied and unpaid premiums of approximately $0.4 million (the “Applied Litigation”). Applied issued approximately $11.3 million in surety bonds on behalf of the Company and has requested approximately $11.3 million in cash collateral.

Also on November 8, 2024, United States Fire Insurance Company (“U.S. Fire” and, together with the Sompo Sureties, USSIC and Applied, the “Sureties”) filed a petition in the United States District Court for the Southern District of Texas, Houston Division, alleging, among other things, breach of the indemnity agreement between the Company and U.S. Fire and seeking to compel the Company to provide the collateral demanded by U.S. Fire (the “U.S. Fire Litigation”). U.S. Fire has issued approximately $93.5 million in surety bonds on behalf of the Company and has requested approximately $93.5 million in cash collateral.

As of November 8, 2024, the Sureties’ aggregate collateral demands against the Company totaled approximately $183 million. In addition, Philadelphia Indemnity Insurance Company (“PIIC”) separately made a collateral demand of $71 million. No legal action has been filed by PIIC as of the date hereof. The total aggregate collateral demanded by the Sureties and PIIC is approximately $254 million as of November 8, 2024.

On November 22, 2024, the court consolidated the Sompo Sureties Litigation, USSIC Litigation, the Applied Litigation, and the U.S. Fire Litigation (as consolidated, the “Sureties Litigation”). On December 11, 2024, as a result of the foregoing, the Company filed an amended complaint (the Original Complaint, as amended, the “Complaint”) against the Sureties. The Complaint, in relevant part, seeks declaratory relief 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

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Notes to Condensed Consolidated Financial Statements (continued)

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 are not legitimate grounds to demand further collateral beyond that offered by the Company. The Company further asserts the following counterclaim against the Sureties: (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.

On June 14, 2025, the Company entered into a Settlement and Release Agreement, dated effective as of June 13, 2025 (the “USSIC Settlement Agreement”), by and between the Company and USSIC and, on June 15, 2025, the Company entered into a Settlement Agreement, dated effective as of June 14, 2025 (the “PIIC Settlement Agreement,” and, together with the USSIC Settlement Agreement, the “Settlement Agreements”), by and between the Company and PIIC to dismiss all claims related to the Sureties Litigation without prejudice. Pursuant to the applicable Settlement Agreement, USSIC and PIIC agree that: (i) there will be no change to the 2024 premium rates paid by 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 Company’s second lien notes due 2029 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. The entry into the Settlement Agreements resulted in the withdrawal of approximately $94 million in collateral demands.

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

All of the remaining parties to the Sureties Litigation previously agreed to mediate the case until the mediator declares an impasse. As of August 2025, mediation is no longer active as the mediator has declared an impasse with respect to the surety providers that did not enter into the Settlement Agreements. The Company continues to evaluate potential avenues for resolution of the remaining related premium and collateral-related matters.

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.

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.

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Notes to Condensed Consolidated Financial Statements (continued)

During the nine months ended September 30, 2025, the Company incurred $1.7 million in costs related to the decommissioning obligations and, after reassessing the existing anticipated decommissioning obligations, recorded an additional $13.7 million increase in the decommissioning obligations accrual. As of September 30, 2025, the accrual for these decommissioning obligations is $34.5 million.

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 nine months ended September 30, 2025, the Company declared cash dividends of $4.7 million to holders of its common stock.

On November 5, 2025, the Company’s board of directors declared a regular quarterly dividend of $0.01 per share of common stock for the fourth quarter of 2025. The dividend is to be paid on November 26, 2025 to stockholders of record at the close of business on November 19, 2025.

NOTE 7 — SHARE-BASED COMPENSATION

In May 2025, the Company granted share-based compensation to its employees. The grants consisted of 6.1 million restricted stock units (“RSUs”) and 5.2 million performance stock units (“PSUs”).

The RSUs were valued as of the grant date and vest 1/3 each year on May 16, 2026, 2027 and 2028. The grant date fair value of the RSUs was $9.0 million. This amount will be expensed over the service period.

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, 2025 and ends on December 31, 2027. To be eligible to receive the earned PSUs, employees must be employed from the grant date through December 31, 2027. 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%.

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Notes to Condensed Consolidated Financial Statements (continued)

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 $5.0 million and was calculated using a Monte Carlo simulation. This amount will be expensed on a straight-line basis over the service period.

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 was $3.1 million and $0.8 million, respectively. The cumulative compensation cost that will be recognized will be equal to the grant date 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.

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.

During the three months ended September 30, 2025, the Company performed a valuation allowance analysis and determined that it is more likely than not that the Company’s net deferred tax assets will not be utilized and recorded a $59.9 million valuation allowance against the Company’s net deferred tax assets. As a result, the Company’s effective tax rates for the three and nine months ended September 30, 2025 were not meaningful. As of September 30, 2025, the Company has a valuation allowance of $92.6 million against all of its net deferred tax assets.

The Company’s effective tax rate for the three and nine months ended September 30, 2024 was 11.0% and 11.3%, respectively. These effective tax rates differ from the federal statutory rate primarily due to the impact of nondeductible compensation and adjustments to the Company’s valuation allowance.

On July 4, 2025, the One Big Beautiful Bill Act (the “OBBBA”) was signed into law which, among other things, modified tax legislation affecting bonus depreciation rules and interest deductions. Specifically, the OBBBA provides for 100% bonus depreciation for property acquired and placed in service after January 19, 2025, and the use of earnings before income taxes, depreciation and amortization, rather than earnings before income taxes, with no phase-out for purposes of calculating the interest limitation for taxable years beginning after 2024. The Company calculated its quarterly tax provision following the new regulations set forth under the OBBBA.

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W&T OFFSHORE, INC.

Notes to Condensed Consolidated Financial Statements (continued)

NOTE 9 — NET LOSS PER COMMON SHARE

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Net loss	$	(71,474)	$	(36,921)	$	(122,935)	$	(63,783)

Weighted average common shares outstanding (basic and diluted)		148,589		147,206		148,015		147,002

Net loss per common share (basic and diluted)	$	(0.48)	$	(0.25)	$	(0.83)	$	(0.43)

Shares excluded due to being anti-dilutive ⁽¹⁾		14,005		3,531		14,005		3,531

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

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):


	September 30,		December 31,
	2025		2024
Working capital	$	191	$	29
Oil and natural gas properties and other, net		25,126		28,042
Other assets		13,305		13,038
Asset retirement obligations		769		691

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):


	Nine Months Ended September 30,
	2025		2024
Total revenues	$	8,566	$	8,546
Total operating expenses		6,496		5,540
Interest income		141		165

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 both September 30, 2025 and December 31, 2024, the unused advances were $2.4 million, which are included in Advances from joint interest partners in the Condensed Consolidated Balance Sheets.

During the nine months ended September 30, 2025, Monza paid cash distributions of $23.2 million, of which $4.8 million was paid to the Company.

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W&T OFFSHORE, INC.

Notes to Condensed Consolidated Financial Statements (continued)

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.

NOTE 12 — OTHER SUPPLEMENTAL INFORMATION

Condensed Consolidated Balance Sheet Details

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


	September 30,		December 31,
	2025		2024
Derivatives	$	546	$	868
Insurance/bond premiums		8,902		6,988
Prepaid deposits related to royalties		6,154		8,562
Prepayments to vendors		1,314		1,586
Other		590		500
Prepaid expenses and other current assets	$	17,506	$	18,504

Accrued liabilities consisted of the following (in thousands):


	September 30,		December 31,
	2025		2024
Accrued interest	$	6,353	$	13,472
Accrued salaries/payroll taxes/benefits		8,493		11,623
Derivatives		30		3,731
Operating lease liabilities		1,740		1,522
Income taxes payable		48		—
Contingent P&A liability		759		1,751
Other		1,505		1,172
Total accrued liabilities	$	18,928	$	33,271

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W&T OFFSHORE, INC.

Notes to Condensed Consolidated Financial Statements (continued)

Condensed Consolidated Statements of Cash Flows Information

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


	September 30,		December 31,
	2025		2024
Cash and cash equivalents	$	124,795	$	109,003
Restricted cash		1,552		1,552
Cash, cash equivalents and restricted cash		126,347		110,555


	Nine Months Ended September 30,
	2025		2024
Non-cash investing and financing activities:
Accrual for investment in oil and natural gas properties		5,942		5,258
Right of use asset obtained in exchange for new lease liabilities		1,491		—
ARO - acquisitions, additions, dispositions and revisions, net		16,987		52,337
Government securities transferred to trustee in connection with legal defeasance		5,348		—
Legal defeasance of 11.75% Notes		5,170		—
Change in accrual for dividends declared but not paid on unvested share-based awards		201		82

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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 2024 Annual Report and the related MD&A included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, of our 2024 Annual Report. Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we” and “our” are to W&T Offshore, Inc. and its wholly owned subsidiaries.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

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

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

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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 September 30, 2025, we hold working interests in 50 producing offshore fields in federal and state waters (which include 43 fields in federal waters and seven in state waters). We currently have under lease approximately 624,700 gross acres (486,900 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 5,600 gross acres in Alabama state waters, 477,200 gross acres on the conventional shelf and approximately 141,900 gross acres in the deepwater. A majority of our daily production is derived from wells we operate.

Recent Developments

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

Business Outlook

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

The Energy Information Administration (“EIA”) published its latest Short Term Energy Outlook in October 2025. The EIA is expecting that growing global oil supply and the transition away from peak summer seasonal demand will lead to significant growth in global oil inventories, causing oil prices to fall in the coming months. The EIA is forecasting that oil prices will fall to an average of $58.00 per barrel for the fourth quarter of 2025 and $48.50 per barrel in 2026. The EIA is also forecasting that Henry Hub spot prices are expected to average $3.33 per MMBtu for the fourth quarter of 2025 and $3.94 per MMBtu in 2026. The EIA is expecting that natural gas production will increase, leading to more natural gas inventory through the winter. In addition, above-average natural gas injections have increased storage levels heading into this winter.

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

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

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RESULTS OF OPERATIONS

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

Revenues

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


	Three Months Ended September 30,
	2025		2024			Change
Revenues:
Oil	$	84,131	$	90,862	$	(6,731)
NGLs		4,000		5,636		(1,636)
Natural gas		37,400		23,148		14,252
Other		1,984		1,726		258
Total revenues		127,515		121,372		6,143

Production Volumes:
Oil (MBbls) ⁽¹⁾		1,302		1,210		92
NGLs (MBbls)		280		262		18
Natural gas (MMcf) ⁽²⁾		10,159		8,289		1,870
Total oil equivalent (MBoe) ⁽³⁾		3,275		2,854		421

Average daily equivalent sales (Boe/day)		35,598		31,022		4,576

Average realized sales prices:
Oil ($/Bbl)	$	64.62	$	75.09	$	(10.47)
NGLs ($/Bbl)		14.29		21.51		(7.22)
Natural gas ($/Mcf)		3.68		2.79		0.89
Oil equivalent ($/Boe)		38.33		41.92		(3.59)
Oil equivalent ($/Boe), including realized commodity derivatives		41.29		42.40		(1.11)

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

(2)	MMcf — million cubic feet

(3)	MBoe — thousand barrels of oil equivalent

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


	Price		Volume		Total
Oil	$	(13,652)	$	6,921	$	(6,731)
NGLs		(2,021)		385		(1,636)
Natural gas		9,029		5,223		14,252
	$	(6,644)	$	12,529	$	5,885

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

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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):


	Three Months Ended September 30,
	2025		2024			Change
Operating expenses:
Lease operating expenses	$	76,215	$	72,412	$	3,803
Gathering, transportation and production taxes		5,818		6,147		(329)
Depreciation, depletion and amortization		28,580		34,206		(5,626)
Asset retirement obligations accretion		8,002		7,848		154
General and administrative expenses		21,510		19,723		1,787
Total operating expenses	$	140,125	$	140,336	$	(211)

Average per Boe ($/Boe):
Lease operating expenses	$	23.27	$	25.37	$	(2.10)
Gathering, transportation and production taxes		1.78		2.15		(0.37)
Depreciation, depletion and amortization		8.73		11.99		(3.26)
Asset retirement obligations accretion		2.44		2.75		(0.31)
General and administrative expenses		6.57		6.91		(0.34)
Total operating expenses	$	42.79	$	49.17	$	(6.38)

Lease operating expenses – Lease operating expenses include the expense of operating and maintaining our wells, platforms and other infrastructure primarily in the Gulf of America. These operating costs are comprised of several components including direct or base lease operating expenses, workover costs, facility maintenance expenses and hurricane repairs. Our lease operating costs, which depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties, increased by $3.8 million during the three months ended September 30, 2025 compared to the same period in 2024. On a component basis, base lease operating expenses increased $3.9 million, workover expenses increased $1.7 million, facilities maintenance expense decreased $1.5 million and hurricane repairs decreased $0.3 million.

Expenses for direct labor, materials, supplies, repair, third-party costs and insurance comprise the most significant portion of our base lease operating expense. Base lease operating expenses increased primarily due to the restart of production in our West Delta 73 field.

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

Gathering, transportation and production taxes – Gathering and transportation consist of costs incurred in the post-production shipping of oil, NGLs and natural gas to the point of sale. Production taxes consist of severance taxes levied by the Alabama Department of Revenue, the Louisiana Department of Revenue and the Texas Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of each state. Gathering, transportation and production taxes decreased $0.3 million for the three months ended September 30, 2025 compared to the three months ended September 30, 2024 primarily due to a decrease of $0.7 million in gathering and transportation expenses offset by an increase of $0.4 million in production taxes.

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Depreciation, depletion and amortization – Depreciation, depletion and amortization expense (“DD&A”) is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities. DD&A decreased $5.6 million for the three months ended September 30, 2025 as compared to the three months ended September 30, 2024 primarily due to a decrease of $9.2 million from the decrease in the depletion rate per Mcfe offset by an increase of $3.6 million for the increase in production. The DD&A rate per Boe decreased to $8.73 per Boe for the three months ended September 30, 2025 from $11.99 per Boe for the three months ended September 30, 2024. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs and a lower depreciable base, offset by decreased proved reserves. The lower depreciable base is due to the $58.5 million in insurance proceeds and $11.9 million of proceeds from the sale of oil and natural gas properties that were included in our full cost pool.

Asset retirement obligations accretion expense – Accretion expense is the expensing of the changes in value of our ARO as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values. Accretion expense was relatively flat in the three months ended September 30, 2025 compared to the same period in 2024.

General and administrative expenses – General and administrative (“G&A”) expenses generally consist of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, share-based compensation costs, audit and other fees for professional services and legal compliance. G&A expenses increased $1.8 million the three months ended September 30, 2025 compared to the three months ended September 30, 2024 primarily due to an increase of $1.6 million in share-based compensation costs.

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):


	Three Months Ended September 30,
	2025		2024			Change
Interest expense, net	$	8,998	$	9,992	$	(994)
Derivative gain, net		(4,108)		(3,199)		(909)
Other (income) expense, net		(2,017)		15,709		(17,726)
Income tax expense (benefit)		55,991		(4,545)		60,536

Interest expense, net – Interest expense, net, decreased $1.0 million for the three months ended September 30, 2025 compared to the same period in 2024 primarily due to a decrease of $11.5 million from the redemption of the 11.75% Notes and the repayment of the Term Loan in late January 2025, partially offset by $10.1 million incurred on the 10.75% Notes issued in late January 2025.

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

Other (income) expense, net – Other (income) expense, net changed by $17.7 million for the three months ended September 30, 2025 compared to the same period in 2024 primarily related to an accrual of $16.6 million of additional expenses for net abandonment obligations related to the Company’s assumption of decommissioning obligations when certain counterparties in past divestiture transactions or third parties in existing leases have filed for bankruptcy protection or have been unable to perform required abandonment obligations during the three months ended September 30, 2024.

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

Nine Months Ended September 30, 2025 Compared to the Nine Months Ended September 30, 2024

Revenues


	Nine Months Ended September 30,
	2025		2024			Change
Revenues:
Oil	$	251,861	$	308,842	$	(56,981)
NGLs		13,487		21,265		(7,778)
Natural gas		107,311		66,674		40,637
Other		7,090		8,135		(1,045)
Total revenues	$	379,749	$	404,916	$	(25,167)

Production Volumes:
Oil (MBbls)		3,791		3,992		(201)
NGLs (MBbls)		725		939		(214)
Natural gas (MMcf)		27,328		25,791		1,537
Total oil equivalent (MBoe)		9,071		9,230		(159)

Average daily equivalent sales (Boe/day)		33,227		33,686		(459)

Average realized sales prices:
Oil ($/Bbl)	$	66.44	$	77.37	$	(10.93)
NGLs ($/Bbl)		18.60		22.65		(4.05)
Natural gas ($/Mcf)		3.93		2.59		1.34
Oil equivalent ($/Boe)		41.08		42.99		(1.91)
Oil equivalent ($/Boe), including realized commodity derivatives		42.80		43.58		(0.78)

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


	Price		Volume		Total
Oil	$	(41,428)	$	(15,553)	$	(56,981)
NGLs		(2,929)		(4,849)		(7,778)
Natural gas		36,662		3,975		40,637
	$	(7,695)	$	(16,427)	$	(24,122)

Production volumes decreased by 159 MBoe to 9,071 MBoe during the nine months ended September 30, 2025 compared to the same period in 2024 primarily related to low gas availability in one of our fields and a shut-in of two other fields due to solids production in two of the wells, partially offset by restoring production at our West Delta 73 field and increased production at our Mobile Bay fields due to well stimulation work and reduced downtime.

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Operating Expenses


	Nine Months Ended September 30,
	2025		2024			Change
Operating expenses:
Lease operating expenses	$	224,151	$	217,229	$	6,922
Gathering, transportation and production taxes		16,976		22,265		(5,289)
Depreciation, depletion and amortization		87,917		104,817		(16,900)
Asset retirement obligations accretion expense		25,075		24,217		858
General and administrative expenses		59,337		61,592		(2,255)
Total operating expenses	$	413,456	$	430,120	$	(16,664)

Average per Boe ($/Boe):
Lease operating expenses	$	24.71	$	23.54	$	1.17
Gathering, transportation and production taxes		1.87		2.41		(0.54)
Depreciation, depletion and amortization		9.69		11.36		(1.67)
Asset retirement obligations accretion expense		2.76		2.62		0.14
General and administrative expenses		6.54		6.67		(0.13)
Total operating expenses	$	45.57	$	46.60	$	(1.03)

Lease operating expenses – Lease operating costs, which depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties, increased $6.9 million during the nine months ended September 30, 2025 compared to the same period in 2024. On a per Boe basis, lease operating expenses increased to $24.71 per Boe during the nine months ended September 30, 2025 compared to $23.54 per Boe during the nine months ended September 30, 2024. On a component basis, base lease operating expenses increased $2.8 million, workover expenses increased $2.5 million, facilities maintenance expense increased $2.0 million and hurricane repairs decreased $0.4 million.

Base lease operating expenses increased primarily due to the restart of production in our West Delta 73 field and increased repairs and maintenance at our Main Pass 61 field partially offset by reduced operating costs at Heidelberg due to a new producer that tied into the system sharing these costs.

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

Gathering, transportation and production taxes – Gathering, transportation and production taxes decreased $5.3 million for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 primarily due to a decrease of $5.7 million in gathering and transportation expenses offset by an increase of $0.4 million in production taxes. Gathering and transportation expenses decreased primarily due to lower production volumes in the nine months ended September 30, 2025 and higher processing fees for our Mobile Bay production that had to be re-routed to a different processing plant due to the shut-in of our Mobile Bay processing plant in the nine months ended September 30, 2024.

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Depreciation, depletion and amortization – D&A decreased $16.9 million for the nine months ended September 30, 2025 as compared to the nine months ended September 30, 2024 primarily due to decreases of $15.4 million from the decrease in the depletion rate per Mcfe and $1.5 million from the decrease in production. The DD&A rate decreased to $9.69 per Boe for the nine months ended September 30, 2025 from $11.36 per Boe for the nine months ended September 30, 2024. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs and a lower depreciable base, partially offset by decreased proved reserves. The lower depreciable base is due to the $58.5 million in insurance proceeds and $11.9 million of proceeds from the sale of oil and natural gas properties that were included in our full cost pool.

Asset retirement obligations accretion expense – Accretion expense increased $0.9 million in the nine months ended September 30, 2025 compared to the same period in 2024 primarily due to the increase in our ARO liability as a result of revisions to the estimates used in calculating the liability.

General and administrative expenses – G&A expenses decreased $2.3 million for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 primarily due to decreases of $4.2 million in non-recurring legal and professional fees and $1.5 million in employee benefit costs due to lower medical claims costs, partially offset by a $2.1 million increase in share-based compensation costs.

Other Income and Expense Items

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


	Nine Months Ended September 30,
	2025		2024			Change
Interest expense, net	$	27,495	$	30,228	$	(2,733)
Loss on extinguishment of debt		15,015		—		15,015
Derivative gain, net		(13,398)		(5,702)		(7,696)
Other expense, net		11,122		22,189		(11,067)
Income tax expense (benefit)		48,994		(8,136)		57,130

Interest expense, net – Interest expense, net, decreased $2.7 million for the nine months ended September 30, 2025 compared to the same period in 2024 primarily due to a decrease of $30.5 million from the redemption of the 11.75% Notes and the repayment of the Term Loan in late January 2025, partially offset by $26.9 million incurred on the 10.75% Notes issued in late January 2025.

Loss on extinguishment of debt – During the nine months ended September 30, 2025, we recorded a loss on extinguishment of debt related to our January 2025 refinancing. The loss consisted of (i) $9.8 million of premiums paid on the redemption of the tendered 11.75% Notes; (ii) $4.6 million related to the write-off of unamortized debt issuance costs; (iii) $0.5 million of fees related to the refinancing; and (iv) $0.2 million related to the legal defeasance of the untendered 11.75% Notes.

Derivative gain, net – During the nine months ended September 30, 2025, we recorded a $13.4 million derivative gain for our derivative contracts consisting of $15.5 million of realized gains, which included $11.9 million related to the monetization of our natural gas put contracts and costless collar offset by $2.1 million of unrealized loss from the decrease in the fair value of our open contracts. During the nine months ended September 30, 2024, we recorded a $5.7 million derivative gain for our natural gas derivative contracts consisting of $5.5 million of realized gains and $0.2 million of unrealized gain from the increase in the fair value of our open contracts.

Other expense, net – Other expense, net decreased $11.1 million for the three months ended September 30, 2025 compared to the same period in 2024 primarily related to a $10.0 million decrease in the accrual of additional expenses for net abandonment obligations related to the Company’s assumption of decommissioning obligations when certain counterparties in past divestiture transactions or third parties in existing leases have filed for bankruptcy protection or have been unable to perform required abandonment obligations.

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Income tax expense (benefit) – 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 $63.5 million valuation allowance against our net deferred tax assets as it is more likely than not that all the deferred tax assets will not be utilized. Our effective tax rate for the nine months ended September 30, 2024 was 11.3% and differed from the federal statutory rate primarily due to the impact of nondeductible compensation and adjustments to the valuation allowance.

Liquidity and Capital Resources

Liquidity Overview

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

We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of September 30, 2025, we had $124.8 million of unrestricted cash on hand and $50.0 million available under our New Credit Agreement. We also have up to approximately $83.0 million of availability through our “at-the-market” equity offering program, pursuant to which we may offer and sell shares of our common stock from time to time. Based on our current financial condition and current expectations of future market conditions, we believe our cash on hand, cash flows from operating activities and access to the equity markets from our “at-the-market” equity offering program will provide us with additional liquidity to continue our growth and will allow us to meet our cash requirements for at least the next 12 months and beyond.

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):


	Nine Months Ended September 30,
	2025		2024			Change
Operating activities	$	51,303	$	63,856	$	(12,553)
Investing activities		31,630		(104,034)		135,664
Financing activities		(67,141)		(6,616)		(60,525)

Operating Activities

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

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

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Investing Activities

Our principal recurring investing activity is the funding of acquisitions and investments in oil and natural gas properties to support and generate revenues from operations. Cash flows provided by (used in) investing activities were $31.6 million and $(104.0) million, respectively. During the nine months ended September 30, 2024, we paid $80.6 million related to our January 2024 acquisition and our September 2023 acquisition. Investments in oil and natural gas properties were $38.9 million and $23.2 million during the nine months ended September 30, 2025 and 2024, respectively. During the nine months ended September 30, 2025, we also received $58.5 million in insurance proceeds and $11.9 million in proceeds from the sale of oil and natural gas properties. As we use the full cost method of accounting for our oil and natural gas properties, these proceeds were recorded in our full cost pool.

Financing Activities

Cash flows used in financing activities were $67.1 million and $6.6 million for the nine months ended September 30, 2025 and 2024, respectively. In connection with our debt refinancing in January 2025, we received $350.0 million in proceeds from the issuance of our 10.75% Notes and used these proceeds, along with cash on hand, to (i) purchase for cash, pursuant to the Tender Offer, $269.8 million of our 11.75% Notes; (ii) repay $114.2 million of amount outstanding under our Term Loan; (iii) purchase $5.3 million of government securities to be used in the legal defeasance of the remaining principal of our 11.75% Notes not validly tendered and accepted for purchase in the Tender Offer; and (iv) pay $21.3 million in premiums, fees and debt issuance costs.

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):


	Nine Months Ended September 30,
	2025		2024
Exploration and development
Conventional shelf ⁽¹⁾	$	31,765	$	14,917
Deepwater		5,024		6,027
Acquisitions of interests		711		80,635
Seismic and other		4,656		383
Investments in oil and gas property/equipment – accrual basis	$	42,156	$	101,962

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

As of September 30, 2025, we expect to incur an additional $18.0 million to $24.0 million of capital expenditures in the remainder of 2025, which excludes acquisitions. In our view of the outlook for the remainder of 2025, we believe this level of capital expenditure will leave us with sufficient liquidity to operate our business, while providing liquidity to make strategic acquisitions. At current pricing levels, we expect our cash flows to cover our liquidity requirements, and we expect additional financing sources to be available if needed. If our liquidity becomes stressed from significant or prolonged reductions in realized prices, we have flexibility in our capital expenditure budget to reduce investments. We strive to maintain flexibility in our capital expenditure projects and if commodity prices improve, we may increase our investments.

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.

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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 nine months ended September 30, 2025, we have paid $24.9 million related to these obligations. Our ARO estimates as of September 30, 2025 and December 31, 2024 were $566.0 million and $548.8 million, respectively. As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one to many years in the future, actual expenditures could be substantially different than our estimates. See Part I, Item 1A. Risk Factors, of our 2024 Annual Report for additional information.

Debt

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

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 2024 Annual Report.

Dividends

During the nine months ended September 30, 2025, we declared cash dividends of $4.7 million to holders of our common stock. The amount and frequency of future dividends is subject to the discretion of our board of directors and primarily depends on earnings, capital expenditures, debt covenants and various other factors.

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 nine months ended September 30, 2025 and assuming no other items had changed, our revenue would have decreased by approximately $12.5 million and $37.2 million in the three and nine months ended September 30, 2025, respectively. This amount would be representative of the effect on operating cash flows under these price change assumptions.

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

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2025		2024		2025		2024
Natural Gas ($/Mcf)
Average realized sales price, before the effects of derivative settlements	$	3.68	$	2.79	$	3.93	$	2.59
Effects of realized commodity derivatives		0.95		0.17		0.57		0.21
Average realized sales price, including realized commodity derivatives	$	4.63	$	2.96	$	4.50	$	2.80

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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 2024 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 September 30, 2025, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

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

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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 2024 Annual Report and in Part II, Item 1A. Risk Factors in our Quarterly Report for the quarter ended March 31, 2025 (the “Q1 Report”), together with all of the other information included in this Quarterly Report, and in our other public filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

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

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.

ITEM 5. OTHER INFORMATION

During the three months ended September 30, 2025, 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).

ITEM 6. EXHIBITS


Exhibit Number		Description

3.1		Second Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q, filed August 2, 2023)

3.2		Fourth Amended and Restated Bylaws of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed April 26, 2023)

10.1*		Reaffirmation Agreement, dated as of September 30, 2025

10.2*		First Amendment to Credit Agreement, dated as of September 3, 2025 but effective as of March 1, 2025

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10.3		First Amendment to the At-The-Market Equity Distribution Agreement, dated as of August 28, 2025 (incorporated by reference to Exhibit 1.1 of the Company’s Current Report on Form 8-K, filed on August 28, 2025)

31.1*		Section 302 Certification of Chief Executive Officer

31.2*		Section 302 Certification of Chief Financial Officer

32.1**		Section 906 Certification of Chief Executive Officer and Chief Financial Officer

101.INS*		Inline XBRL Instance Document

101.SCH*		Inline XBRL Schema Document

101.CAL*		Inline XBRL Calculation Linkbase Document

101.DEF*		Inline XBRL Definition Linkbase Document

101.LAB*		Inline XBRL Label Linkbase Document

101.PRE*		Inline XBRL Presentation Linkbase Document

104*		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*	Filed herewith.

**	Furnished herewith.

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SIGNATURE

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 November 6, 2025.


	W&T OFFSHORE, INC.

	By:	/s/ Sameer Parasnis
		Sameer Parasnis
		Executive Vice President and Chief Financial Officer

W&T OFFSHORE INC 10-Q