Table of Contents
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, 2026
or
☐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 20, 2026, there were 154,895,304 shares outstanding of the registrant’s common stock, par value $0.00001.
W&T OFFSHORE, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
Page
PART I – FINANCIAL INFORMATION
1
Item 1.
Financial Statements
Condensed Consolidated Balance Sheets as of September 30, 2026 and December 31, 2025
Condensed Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2026 and 2025
2
Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three Months and Nine Months Ended September 30, 2026 and 2025
3
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2026 and 2025
4
Notes to Condensed Consolidated Financial Statements
5
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
15
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
25
Item 4.
Controls and Procedures
PART II – OTHER INFORMATION
27
Legal Proceedings
Item 1A.
Risk Factors
Unregistered Sales of Equity Securities and Use of Proceeds
Defaults Upon Senior Securities
Mine Safety Disclosures
Item 5.
Other Information
Item 6.
Exhibits
28
SIGNATURE
29
ITEM 1. FINANCIAL STATEMENTS
Condensed Consolidated Balance Sheets
(In thousands)
(Unaudited)
September 30,
December 31,
2026
2025
Assets
Current assets:
Cash and cash equivalents
$
191,317
140,558
Restricted cash
—
62
Accounts receivable:
Oil, natural gas liquids and natural gas sales
79,113
59,633
Joint interest, net of allowance for credit losses of $10,638 and $10,529, respectively
25,455
24,473
Prepaid expenses and other current assets
18,477
14,543
Total current assets
314,362
239,269
Oil and natural gas properties and other, net of accumulated depreciation, depletion and amortization of $8,554,290 and $8,473,181, respectively
621,476
662,082
Restricted deposits for asset retirement obligations
24,410
24,026
Deferred income taxes
96
35
Other assets
30,684
30,395
Total assets
991,028
955,807
Liabilities and Shareholders’ Deficit
Current liabilities:
Accounts payable
95,409
98,406
Accrued liabilities
52,486
39,809
Undistributed oil and natural gas proceeds
66,941
59,065
Advances from joint interest partners
2,123
2,394
Current portion of asset retirement obligations
22,010
26,147
Current portion of long-term debt, net
1,000
8,458
Total current liabilities
239,969
234,279
Asset retirement obligations
558,802
535,704
Long-term debt, net
350,972
342,355
Other liabilities
17,365
15,781
Commitments and contingencies
13,851
27,440
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; 157,758 shares and 151,647 shares issued, respectively
Additional paid-in capital
643,055
604,732
Retained deficit
(808,821)
(780,319)
Treasury stock: 2,869 shares, at cost
(24,167)
Total shareholders’ deficit
(189,931)
(199,752)
Total liabilities and shareholders’ deficit
See Notes to Condensed Consolidated Financial Statements.
Condensed Consolidated Statements of Operations
(In thousands, except per share data)
Three Months Ended September 30,
Nine Months Ended September 30,
Revenues:
Oil
111,773
84,131
322,330
251,861
NGLs
9,121
4,000
22,069
13,487
Natural gas
41,204
37,400
123,184
107,311
Other
4,982
1,984
12,135
7,090
Total revenues
167,080
127,515
479,718
379,749
Operating expenses:
Lease operating expenses
76,671
76,215
214,348
224,151
Gathering, transportation and production taxes
9,376
5,818
24,595
16,976
Depreciation, depletion, and amortization
28,266
28,580
81,109
87,917
Asset retirement obligations accretion
8,606
8,002
25,899
25,075
General and administrative expenses
31,685
21,510
84,026
59,337
Other operating expenses
655
Total operating expenses
155,259
140,125
430,632
413,456
Operating income (loss)
11,821
(12,610)
49,086
(33,707)
Interest expense, net
8,956
8,998
27,373
27,495
Loss on extinguishment of debt
15,015
Derivative loss (gain), net
15,800
(4,108)
42,230
(13,398)
Other expense (income), net
216
(2,017)
1,334
11,122
Loss before income taxes
(13,151)
(15,483)
(21,851)
(73,941)
Income tax expense
498
55,991
1,767
48,994
Net loss
(13,649)
(71,474)
(23,618)
(122,935)
Net loss per common share (basic and diluted)
(0.09)
(0.48)
(0.16)
(0.83)
Weighted average common shares (basic and diluted)
151,847
148,589
150,121
148,015
Condensed Consolidated Statements of Changes in Shareholders’ Equity
Common Stock
Additional
Total
Outstanding
Paid-In
Retained
Treasury Stock
Shareholders’
Shares
Value
Capital
Deficit
Balances at June 30, 2026
150,916
621,460
(793,496)
2,869
(196,201)
Cash dividends
(1,676)
Net proceeds from issuance of common stock
3,573
14,670
Share-based compensation
7,565
Share-based compensation common stock issuances
400
Shares withheld related to net settlement of equity awards
(640)
Balances at September 30, 2026
154,889
Balances at June 30, 2025
148,293
599,945
(678,501)
(102,721)
(1,487)
3,537
480
(342)
Balances at September 30, 2025
148,773
603,140
(751,462)
(172,487)
Balances at December 31, 2025
148,778
(4,884)
Proceeds from issuance of common stock
16,348
Reclassification of liability-classified awards to equity-classified awards
11,044
2,538
(3,739)
Balances at December 31, 2024
147,374
595,407
(623,819)
(52,577)
(4,708)
8,497
1,399
(764)
Condensed Consolidated Statements of Cash Flows
Operating activities:
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion
107,008
112,992
28,915
Amortization of debt issuance costs
2,374
2,605
Derivative premium payment
(7,300)
Derivative cash (settlements) receipts, net
(20,908)
14,169
Deferred income tax (benefit) expense
(61)
48,808
Changes in operating assets and liabilities:
Accounts receivable
(20,462)
4,001
(2,460)
674
Accounts payable, accrued liabilities and other
(6,686)
5,748
Asset retirement obligation settlements
(26,512)
(24,873)
Net cash provided by operating activities
72,520
51,303
Investing activities:
Investment in oil and natural gas properties and equipment
(26,900)
(38,881)
Acquisition of property interests
(711)
Proceeds from sale of oil and natural gas properties
11,916
Insurance proceeds
58,500
Purchases of furniture, fixtures and other
(248)
(121)
Distribution from unconsolidated affiliate
927
Net cash (used in) provided by investing activities
(27,148)
31,630
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
(8,825)
(825)
Proceeds from issuance of New TVPX Loan
8,000
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
(94)
(11,478)
Payment of dividends
(4,687)
(4,507)
Net cash provided by (used in) financing activities
5,325
(67,141)
Change in cash, cash equivalents and restricted cash
50,697
15,792
Cash, cash equivalents and restricted cash, beginning of year
140,620
110,555
Cash, cash equivalents and restricted cash, end of period
126,347
NOTE 1 — NATURE OF OPERATIONS AND BASIS OF PRESENTATION
Nature of Operations
W&T Offshore, Inc. (with subsidiaries referred to herein as the “Company”) is an independent oil and natural gas producer with substantially all of its operations offshore in the Gulf of America. The Company is active in the exploration, development and acquisition of oil and natural gas properties. The Company operates in one reportable segment.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries and an interest in Monza Energy LLC (“Monza”), which is accounted for under the proportional consolidation method. All intercompany accounts and transactions have been eliminated in consolidation. These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Accordingly, certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included.
Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in Part II, Item 8. Financial Statements and Supplementary Data of the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 (the “2025 Annual Report”).
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.
NOTE 2 — FINANCIAL INSTRUMENTS
The Company’s financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities, derivative instruments and debt. Except for derivative instruments and debt, the carrying amount of the Company’s financial instruments approximates fair value due to the short-term, highly liquid nature of these instruments.
Derivative Instruments
The following table reflects the contracted volumes and weighted average prices under the terms of the Company’s open oil derivative contracts as of September 30, 2026:
Average
Instrument
Daily
Weighted
Period
Type
Volumes
Strike Price
Floor Price
Ceiling Price
Oil (WTI)
(Bbls) (1)
(Bbls)
($/Bbls)
Oct 2026 - Dec 2026
collars
368,000
56.18
69.40
swap
2,000
184,000
64.53
Oct 2026 - April 2027
call
10,000
2,120,000
122.50
(1)
Bbls – barrels of oil
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):
1,607
318
15,310
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):
Realized loss (gain) (1)
9,882
(9,691)
26,251
(15,545)
Unrealized loss
5,918
5,583
15,979
2,147
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, 2026
December 31, 2025
Net Value
Fair Value
10.75% Notes
343,972
363,615
320,208
New TVPX Loan
TVPX Loan
8,613
351,972
371,615
350,813
328,821
The fair value of the 10.75% Senior Second Lien Notes due 2029 (the “10.75% Notes”) was measured using quoted prices, although the market is inactive. The fair values of the New TVPX and the TVPX Loan were measured using a discounted cash flows model and current market rates. The fair value of debt was classified as Level 2 within the valuation hierarchy.
6
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):
Asset retirement obligations, beginning of period
561,851
548,832
Liabilities settled
Accretion expense
Disposition of oil and natural gas properties
(1,469)
Liabilities incurred
1,029
Revisions of estimated liabilities
19,574
17,427
Asset retirement obligations, end of period
580,812
566,021
Less: Current portion
(22,010)
(34,528)
Long-term
531,493
NOTE 4 — DEBT
The components comprising the Company’s debt are presented in the following table (in thousands):
10.75% Senior Second Lien Notes due 2029:
Principal
Unamortized debt issuance costs
(6,028)
(7,645)
TVPX Loan:
8,825
Unamortized discount
(305)
(62)
Total debt, net
Less current portion, net
(1,000)
(8,458)
In September 2026, the promissory note evidencing the TVPX Loan was amended and restated pursuant to the Second Amended and Restated Promissory Note (as so amended and restated, the “New TVPX Loan”), and the $8.0 million of proceeds from the New TVPX Loan were used to repay the $8.0 million of balloon payment that was due at the maturity date of the TVPX Loan. The New TVPX Loan bears a fixed interest rate of 6.18% per annum and requires monthly amortization payments of $83.3 thousand plus accrued interest, and a balloon payment of $5.0 million at the end of the loan term in September 2029. The New TVPX Loan is secured by the aircraft financed and is guaranteed by the Company on an unsecured basis.
As of September 30, 2026, there were no borrowings outstanding under the Credit Agreement, dated as of January 28, 2025, by and among the Company, Texas Capital Bank, as administrative agent, and the lenders party thereto (the “Credit Agreement”) and letters of credit outstanding were $6.6 million. There was $43.4 million available for the
7
issuance of letters of credit and borrowings under the Credit Agreement as of September 30, 2026, based on a borrowing base of $50.0 million and $6.6 million of letters of credit outstanding. On October 1, 2026, the Company amended the Credit Agreement to convert its revolving credit facility into a reserve-based revolving credit facility. See Note 13 – Subsequent Event for additional information.
As of September 30, 2026, the Company was in compliance with all applicable covenants.
NOTE 5 — COMMITMENTS AND CONTINGENCIES
ONRR Audit of Historical Refund Claims
In 2023, the Company received notification from the Office of Natural Resources Revenue (the “ONRR”) regarding results of an audit performed on the Company’s historical refund claims taken on various properties for alleged royalties owed to the ONRR. In September 2026, the Company finalized a settlement with ONRR resolving this matter. The settlement provides for a net ONRR royalty credit of approximately $8.5 million that is expected to be realized through reduced royalty payments beginning in the fourth quarter of 2026.
Bonding Disputes
Since October 2024, the Company has been involved in litigation with certain providers of private and government-required surety bonds, including Endurance Assurance Corporation, Lexon Insurance Company, U.S. Specialty Insurance Company (“USSIC”), Pennsylvania Insurance Company a/k/a Applied Surety Underwriters and United States Fire Insurance Company (collectively, the “Sureties”), that secure decommissioning obligations or ONRR disputed matters the Company may have with respect to certain oil and natural gas assets of the Company (the “Sureties Litigation”). The Company contends that (1) the Sureties may not enforce their indemnity agreements such that their actions constitute an abuse of right; (2) the Sureties’ interpretation of the indemnity agreements renders the agreements illusory; (3) the Sureties may not make unreasonable demands for collateral; (4) the Sureties must accept reasonable collateral as offered by the Company; (5) no additional collateral is required of the Company; (6) the Sureties may not make joint demands for collateral that are inconsistent with those of each other such that the Company cannot comply with each demand; and (7) the Sureties’ changed business model is not legitimate grounds to demand further collateral beyond that offered by the Company. The Company has also filed counterclaims against the Sureties claiming: (1) violations of the Sherman Antitrust Act; (2) violations of the Texas Free Enterprise and Antitrust Act; (3) violations of the Texas Insurance Code Section 541; (4) tortious interference with existing contracts and prospective business relationships; and (5) conspiracy.
In June 2025, the Company entered into Settlement and Release Agreements (the “Settlement Agreements”), by and between the Company and USSIC and Philadelphia Indemnity Insurance Company (“PIIC”) to dismiss all of such sureties’ claims related to the Sureties Litigation without prejudice. Pursuant to the applicable Settlement Agreement, USSIC and PIIC agreed that: (i) there will be no change to the 2024 premium rates paid by the Company or any of its affiliates, subsidiaries or joint venture entities, for any currently existing surety bond executed by USSIC or PIIC until after December 31, 2026, at the earliest, (ii) USSIC and PIIC withdraw all demands for collateral and agree not to request, demand, or otherwise insist on collateral, whether related to a surety bond or pursuant to the indemnity agreements, until after December 31, 2026, at the earliest; provided that such restriction shall not apply if (a) the Company does not pay premiums owed to USSIC or PIIC when due; (b) a claim is made by a third party against any bond issued by USSIC or PIIC to the Company or its affiliates or subsidiaries; (c) there is an initiation of an insolvency proceeding for the Company or any of its affiliates, subsidiaries or joint venture entities, whether voluntary or involuntary; (d) there is an uncured event of default under the indenture governing the 10.75% Notes that results in an acceleration, in whole or in part, of the indebtedness thereunder; or (e) the Company or its affiliates or subsidiaries initiate a lawsuit against USSIC or PIIC. Each of the Settlement Agreements also provides that, in the event that the Company enters into an agreement to provide collateral to another party in settlement of the Sureties Litigation on bonds existing as of the date of the Settlement Agreement, the Company shall, on a pro rata basis, provide substantially similar collateral to USSIC or PIIC as it does to such other party.
8
In June 2025, the presiding judge in the Sureties Litigation recommended denying the requests for preliminary injunction submitted by two surety providers. The preliminary injunction would have required the Company to immediately post $105 million of collateral. The recommendation effectively nullified all current collateral requests by the surety providers and provided that the Company did not need to post collateral until a determination is made on the merits of the Sureties Litigation with the remaining surety providers.
The Sureties Litigation with respect to the Sureties other than USSIC and PIIC remains ongoing. To the extent that the Company is required to fulfill the collateral demands made by the remaining surety entities, or in the event that other surety entities make additional collateral demands, the fulfillment of such demands could be significant and could impact the Company’s liquidity.
Contingent Decommissioning Obligations
Certain counterparties in past divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform required abandonment obligations. Due to operation of law, the Company may be required to assume decommissioning obligations for those interests. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. The Company no longer owns these assets, nor are they related to current operations.
The changes in the contingent decommissioning obligations were as follows (in thousands):
Contingent decommissioning obligations, beginning of period
36,157
22,551
(4,772)
(1,660)
Accrual for additional estimated liabilities
13,659
Contingent decommissioning obligations, end of period
31,385
34,550
(17,534)
(759)
33,791
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.
9
NOTE 6 — STOCKHOLDERS’ EQUITY
At-the-Market Equity Offering
During the three months ended September 30, 2026, the Company sold an aggregate of 3.6 million shares of common stock for an average price of $4.16 per share in connection with the Company’s “at-the-market” equity offering program and received proceeds, net of commissions and expenses, of $14.7 million. As of September 30, 2026, the Company has $68.1 million of remaining availability under this program.
Dividends
During the nine months ended September 30, 2026, the Company declared cash dividends of $4.9 million.
On October 29, 2026, the Company’s board of directors declared a regular quarterly dividend of $0.01 per share of common stock for the fourth quarter of 2026. The dividend is to be paid on November 19, 2026 to stockholders of record at the close of business on November 12, 2026.
NOTE 7 — SHARE-BASED COMPENSATION
2026 Grants
In May 2026, the Company granted share-based compensation to its employees. The grants consisted of 2.8 million restricted stock units (“RSUs”) and 2.6 million performance stock units (“PSUs”).
The RSUs were valued as of the grant date and vest 1/3 each year on May 29, 2027, 2028 and 2029. The grant date fair value of the RSUs was $10.2 million.
The PSUs are subject to performance criteria of (i) total shareholder return and relative shareholder return (collectively, the “TSR PSUs”), (ii) cash return on capital employed (the “CROCE PSUs”) and (iii) reserve performance (the “Reserve PSUs”). The performance period for the measurement of the performance goals began on January 1, 2026 and ends on December 31, 2028. To be eligible to receive the earned PSUs, employees must be employed from the grant date through December 31, 2028. Different levels of achievement across these metrics will affect the percentage of PSUs that the employee receives upon the satisfaction of the service requirement. The percentage of PSUs received upon vesting ranges from 0% to 200%.
The TSR PSUs will account for 50% of the target PSUs granted to employees. The TSR PSUs contain both a service condition and a market condition. The grant date fair value of the TSR PSUs was $8.5 million and was calculated using a Monte Carlo simulation.
The CROCE PSUs and Reserve PSUs will account for 40% and 10%, respectively, of the target PSUs granted to employees. The CROCE PSUs and Reserve PSUs contain both a service condition and a performance condition. The grant date fair value of the CROCE PSUs and Reserve PSUs, which was determined using the closing price of the Company’s common stock on the date of grant, was $3.8 million and $1.0 million, respectively. The cumulative compensation cost that will be recognized will be equal to the fair value of the awards deemed probable of vesting multiplied by the percentage of the requisite service period that has been rendered. Unlike the TSR PSUs, if the performance condition is not satisfied, any previously recognized compensation expense is reversed.
As of the grant date, the Company did not have enough shares of common stock available under its long-term incentive plan to satisfy its commitments to deliver shares upon vesting. Accordingly, the Company will account for these awards as liability awards, and the fair value of these awards will be remeasured at the end of each reporting period based on either the current market price of the Company’s common stock (for RSUs and PSUs with both a service condition and a performance condition) or through the use of the Monte Carlo simulation method (for the PSUs with both a service condition and a market condition).
10
Modification of Awards
In June 2026, the Company’s long-term incentive plan was amended to increase the shares available for issuance from 10.0 million to 22.0 million. As a result of this increase, the Company reclassified the RSUs and PSUs that were granted in 2025 from liability awards to equity awards. The modification resulted in the remeasurement of the TSR PSUs at $7.44 per share and the remaining PSUs and RSUs at $4.01 per share on the modification date. The liability balance as of the modification date of $11.0 million was reclassified to additional paid in capital.
NOTE 8 — INCOME TAXES
The Company records income taxes for interim periods based on an estimated annual effective tax rate. The estimated annual effective rate is recomputed on a quarterly basis and may fluctuate due to changes in forecasted annual operating income, positive or negative changes to the valuation allowance for net deferred tax assets and changes to actual or forecasted permanent book to tax differences.
The Company’s effective tax rates for the three and nine months ended September 30, 2026 were (3.8)% and (8.1)%, respectively. These effective tax rates differ from the federal statutory rate primarily due to the impact of losses with no tax benefit, nondeductible compensation and adjustments to the Company’s valuation allowance. The Company’s effective tax rates for the three and nine months ended September 30, 2025 were not meaningful due to the Company recording a valuation allowance against its net deferred tax assets during that quarter.
At each reporting date, the Company considers all available positive and negative evidence to evaluate whether its deferred tax assets are more likely than not to be realized. During 2025, the amount of the Company’s deferred tax assets considered realizable was reduced due to negative evidence that outweighed positive evidence supporting its ability to realize its deferred tax assets. The Company was able to support that a portion of its deferred tax assets would be realizable through the generation of income from future reversals of existing taxable temporary differences and recorded a valuation allowance against the remaining unsupported deferred tax assets. As of September 30, 2026 and December 31, 2025, the Company had a valuation allowance of $103.8 million and $100.3 million, respectively.
NOTE 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):
Weighted average common shares outstanding (basic and diluted)
Shares excluded due to being anti-dilutive (1)
22,000
14,005
11
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):
Working capital
2,240
502
Oil and natural gas properties and other, net
21,913
24,289
15,994
13,947
936
840
56
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):
9,320
8,566
5,394
6,496
Other income, net
142
141
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 September 30, 2026 and December 31, 2025, the unused advances were $2.1 million and $2.4 million, respectively, which are included in Advances from joint interest partners in the Condensed Consolidated Balance Sheets.
During the nine months ended September 30, 2026, Monza paid cash distributions of $13.6 million, of which $2.8 million was paid to the Company.
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 are reported in its Condensed Consolidated Statements of Operations and segment assets are 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.
12
NOTE 12 — OTHER SUPPLEMENTAL INFORMATION
Condensed Consolidated Balance Sheet Details
Prepaid expenses and other current assets consisted of the following (in thousands):
Derivatives
Insurance/bond premiums
6,407
5,630
Prepaid deposits related to royalties
7,649
6,382
Prepayments to vendors
2,541
1,636
273
577
Accrued liabilities consisted of the following (in thousands):
Accrued interest
6,418
15,768
Accrued salaries/payroll taxes/benefits
10,720
12,513
Contingent P&A liability
17,534
8,717
Operating lease liabilities
1,283
1,765
Income taxes payable
358
202
863
844
Total accrued liabilities
Condensed Consolidated Statements of Cash Flows Information
Supplemental statements of cash flows information consisted of the following (in thousands):
Non-cash investing and financing activities:
Accrual for investment in oil and natural gas properties
3,280
5,942
Right of use asset obtained in exchange for new lease liabilities
1,491
ARO - additions and revisions, net
16,987
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
197
201
NOTE 13 — SUBSEQUENT EVENT
On October 1, 2026, the Company entered into the Second Amendment to the Credit Agreement (the “Amendment”) which amends the Credit Agreement (as amended, the “Amended Credit Agreement”). Pursuant to the Amendment, the Company’s revolving credit facility was converted into a reserve-based revolving credit facility (the “RBL Facility”), maturing on the earlier of July 28, 2028 and the date that is six months prior to the stated maturity date
13
of the 10.75% Notes, with an aggregate maximum credit amount of $100.0 million and an aggregate elected commitment amount initially set at $50.0 million.
The key highlights of the Amended Credit Agreement are as follows:
There were no changes to interest rate margins, the Term SOFR floor, maturity, collateral or the Company’s financial covenants, including a maximum net leverage ratio of 2.50 to 1.00 and a minimum current ratio of 1.00 to 1.00.
14
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the unaudited condensed consolidated financial statements and the related notes included in Part I, Item 1. Financial Statements, of this Quarterly Report, as well as our audited consolidated financial statements and the notes thereto in the 2025 Annual Report and the related MD&A included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, of our 2025 Annual Report. Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we” and “our” are to W&T Offshore, Inc. and its wholly owned subsidiaries.
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 2025 Annual Report, and may be discussed or updated from time to time in subsequent reports filed with the SEC.
Reserve engineering is a process of estimating underground accumulations of crude oil, NGLs and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and the price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing, and production activities, or changes in commodity prices, may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of crude oil, NGLs and natural gas that are ultimately recovered.
All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
BUSINESS OVERVIEW
We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of America. As of September 30, 2026, we hold working interests in 48 offshore fields in federal and state waters (which include 41 fields in federal waters and seven in state waters). We currently have under lease approximately 588,500 gross acres (455,800 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 5,600 gross acres in Alabama state waters, 446,700 gross acres on the conventional shelf and approximately 136,200 gross acres in the deepwater. A majority of our daily production is derived from wells we operate.
Recent Developments
On October 1, 2026, we entered into the Amended Credit Agreement, pursuant to which our revolving credit facility was converted into a reserve-based revolving credit facility, with an aggregate maximum credit amount of $100.0 million and an aggregate elected commitment amount initially set at $50.0 million. For additional information about the Amended Credit Agreement, see Part I, Item 1. Financial Statements – Note 13 – Subsequent Event.
On October 29, 2026, we declared a regular quarterly dividend of $0.01 per share of common stock for the fourth quarter of 2026. We expect to pay the dividend on November 19, 2026 to stockholders of record as of the close of business on November 12, 2026.
Business Outlook
Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production. Changes in the prices that we receive for our production impact all aspects of our business; most notably our cash flows from operations, revenues, capital allocation and budgeting decisions and our reserves volumes. Prices of oil, NGLs and natural gas have historically been volatile and can fluctuate significantly over short periods of time for many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, domestic production activities and political issues, and international geopolitical and economic events.
In its Short-Term Energy Outlook published in October 2026, the Energy Information Administration (the “EIA”) assumes that a combination of convoys through the Strait of Hormuz and workarounds to oil exports from the Middle East, including bypass routes and increased use of ship-to-ship transfers, will lead to production and exports from the region generally increasing through the forecast period. In spite of the increased production and flows from the Middle East, the EIA is forecasting that the spot price for WTI will average $97.00 per barrel in the fourth quarter of 2026 and then fall to an average of $80.00 per barrel in 2027. The attacks on the East-West pipeline in Saudi Arabia highlight the potential for continued volatility in physical oil flows and oil prices amid ongoing withdrawals of oil inventories globally. Additional upward pressure on oil prices stems from extreme tightness in diesel markets that raises demand for oil in order for refiners to meet diesel demand.
The EIA is forecasting the Henry Hub spot price for natural gas to average $3.16 per MMBtu in 2027, a 9% decrease from 2026. The decrease reflects ongoing higher-than-average natural gas inventories driven by production increases that offset rising liquefied natural gas exports.
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.
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RESULTS OF OPERATIONS
Three Months Ended September 30, 2026 Compared to the Three Months Ended September 30, 2025
Revenues
Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs. Our oil, NGL and natural gas revenues do not include the effects of derivatives, which are reported in Derivative loss (gain), net in our Condensed Consolidated Statements of Operations.
The following table presents information regarding our revenues, production volumes and average realized sales prices (which exclude the effect of hedging unless otherwise stated) for the periods presented and corresponding changes (in thousands, except average realized sales prices data):
Change
27,642
5,121
3,804
2,998
39,565
Production Volumes:
Oil (MBbls) (1)
1,314
1,302
NGLs (MBbls)
482
280
Natural gas (MMcf) (2)
10,305
10,159
146
Total oil equivalent (MBoe) (3)
3,514
3,275
239
Average daily equivalent sales (Boe/day) (4)
38,196
35,598
2,598
Average realized sales prices:
Oil ($/Bbl) (5)
85.06
64.62
20.44
NGLs ($/Bbl)
18.92
14.29
4.63
Natural gas ($/Mcf) (6)
4.00
3.68
0.32
Oil equivalent ($/Boe)
46.13
38.33
7.80
Oil equivalent ($/Boe), including realized commodity derivatives
43.32
41.29
2.03
17
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, 2026 and 2025 (in thousands):
Price
Volume
26,863
779
2,223
2,898
3,269
535
32,355
4,212
36,567
Production volumes increased by 239 Mboe to 3,514 MBoe during the three months ended September 30, 2026 compared to the same period in 2025 primarily due to recompletion of a well at our Garden Banks 783 field.
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):
456
3,558
Depreciation, depletion and amortization
(314)
604
10,175
15,134
Average per Boe ($/Boe):
21.82
23.27
(1.45)
2.67
1.78
0.89
8.04
8.73
(0.69)
2.45
2.44
0.01
9.02
6.57
0.19
44.19
42.79
1.40
Lease operating expenses – Lease operating expenses (“LOE”) include the expense of operating and maintaining our wells, platforms and other infrastructure primarily in the Gulf of America. These operating costs are comprised of several components including direct or base lease operating expenses, insurance premiums, workover costs and facility maintenance expenses. LOE, which depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties, increased $0.5 million during the three months ended September 30, 2026 compared to the same period in 2025. On a per Boe basis, LOE decreased to $21.82 per Boe during the three months ended September 30, 2026 compared to $23.27 per Boe during the three months ended September 30, 2025. On a component basis, base LOE decreased $3.2 million, workover expenses increased $1.1 million and facilities maintenance expense increased $2.6 million.
Expenses for direct labor, materials, supplies, repair, third-party costs and insurance comprise the most significant portion of our base LOE. These costs decreased primarily due to lower costs overall, reflecting the success of our cost reduction efforts that began in the fourth quarter of 2025 and continued into the three months ended September 30, 2026.
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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 expenses 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 and transportation consist of costs incurred in the post-production shipping of oil, NGLs, and natural gas to the point of sale. Production taxes consist of severance taxes levied by the Alabama Department of Revenue, the Louisiana Department of Revenue and the Texas Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of each state. Gathering, transportation and production taxes increased $3.6 million for the three months ended September 30, 2026 compared to the three months ended September 30, 2025 primarily due to the impact of the new NGL processing contract at Mobile Bay and higher production volumes in the three months ended September 30, 2026.
Depreciation, depletion and amortization – Depreciation, depletion and amortization expense (“DD&A”) is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities. DD&A decreased $0.3 million for the three months ended September 30, 2026 as compared to the three months ended September 30, 2025 primarily due to a decrease of $2.1 million from a lower depletion rate per thousand cubic feet equivalent (“Mcfe”) offset by an increase of $2.0 million from the increase in production. The DD&A rate decreased to $8.04 per Boe for the three months ended September 30, 2026 from $8.73 per Boe for the three months ended September 30, 2025. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs and increased proved reserves.
General and administrative expenses – General and administrative (“G&A”) expenses generally consist of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, share-based compensation costs, audit and other fees for professional services and legal compliance. G&A expenses increased $10.2 million for the three months ended September 30, 2026 compared to the three months ended September 30, 2025 primarily due to increases of $6.9 million in share-based compensation costs and $2.9 million in legal and professional fees.
Other Income and Expense Items
The following table presents the components of other income and expense items for the periods presented and corresponding changes (in thousands):
(42)
19,908
2,233
(55,493)
Derivative loss (gain), net – During the three months ended September 30, 2026, we recorded a $15.8 million derivative loss for our oil derivative contracts consisting of $9.9 million of realized losses and $5.9 million of unrealized loss from the decrease in the fair value of our open contracts. During the three months ended September 30, 2025, we recorded a $4.1 million derivative gain for our natural gas derivative contracts consisting of $9.7 million of realized gains offset by $5.6 million of unrealized loss from the decrease in the fair value of our open contracts.
Income tax expense – Our effective tax rate for the three months ended September 30, 2026 was (3.8)% and differed from the federal statutory rate primarily due to the impact of losses with no tax benefit, nondeductible compensation and adjustments to the valuation allowance. Our effective tax rate for the three months ended September 30, 2025 was not meaningful and differed from the federal statutory rate primarily due to the recording of a valuation allowance against our net deferred tax assets.
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Nine Months Ended September 30, 2026 Compared to the Nine Months Ended September 30, 2025
70,469
8,582
15,873
5,045
99,969
Oil (MBbls)
3,823
3,791
32
1,236
725
511
Natural gas (MMcf)
29,217
27,328
1,889
Total oil equivalent (MBoe)
9,930
9,071
859
Average daily equivalent sales (Boe/day)
36,374
33,227
3,147
Oil ($/Bbl)
84.31
66.44
17.87
17.86
18.60
(0.74)
Natural gas ($/Mcf)
4.22
3.93
0.29
47.09
41.08
6.01
44.44
42.80
1.64
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, 2026 and 2025 (in thousands):
68,283
2,186
(934)
9,516
8,457
7,416
75,806
19,118
94,924
Production volumes increased by 859 MBoe to 9,930 MBoe during the nine months ended September 30, 2026 compared to the same period in 2025 primarily due to recompletion of a well at our Garden Banks 783 field, restoring production at our West Delta 73 and Eugene Island 64 fields and increased production from our Mobile Bay fields due to reduced downtime.
20
(9,803)
7,619
(6,808)
824
24,689
17,176
21.59
24.71
(3.12)
2.48
1.87
0.61
8.17
9.69
(1.52)
2.61
2.76
(0.15)
8.46
6.54
1.92
0.07
43.38
45.57
(2.19)
Lease operating expenses – LOE decreased $9.8 million during the nine months ended September 30, 2026 compared to the same period in 2025. On a per Boe basis, LOE decreased to $21.59 per Boe during the nine months ended September 30, 2026 compared to $24.71 per Boe during the nine months ended September 30, 2025. On a component basis, base LOE decreased $11.0 million, workover expenses decreased $0.6 million and facilities maintenance expense increased $1.8 million.
Expenses for direct labor, materials, supplies, repair, third-party costs and insurance comprise the most significant portion of our base LOE. These costs decreased primarily due to lower costs overall, reflecting the success of our cost reduction efforts that began in the fourth quarter of 2025 and continued into the nine months ended September 30, 2026.
Workover and facilities maintenance expenses consist of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production. Since these remedial operations are not regularly scheduled, workover and maintenance expenses are not necessarily comparable from period to period. The decrease in workover expenses and the increase in facilities maintenance expenses were due to the timing and mix of projects undertaken.
Gathering, transportation and production taxes – Gathering, transportation and production taxes increased $7.6 million for the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025 primarily due to the impact of the new NGL processing contract at Mobile Bay and higher production volumes in the nine months ended September 30, 2026.
Depreciation, depletion and amortization – DD&A decreased $6.8 million for the nine months ended September 30, 2026 as compared to the nine months ended September 30, 2025 primarily due to a decrease of $14.5 million from a lower depletion rate per Mcfe offset by an increase of $8.1 million from the increase in production. The DD&A rate decreased to $8.17 per Boe for the nine months ended September 30, 2026 from $9.69 per Boe for the nine months ended September 30, 2025. The DD&A rate per Boe decreased primarily as a result of decreases in future development costs and increased proved reserves.
21
General and administrative expenses – G&A expenses increased $24.7 million for the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025 primarily due to an increase of $20.4 million in share-based compensation costs and $3.5 million in legal and professional fees.
(122)
(15,015)
55,628
Other expense, net
(9,788)
(47,227)
Derivative loss (gain), net – During the nine months ended September 30, 2026, we recorded a $42.2 million derivative loss for our oil derivative contracts consisting of $26.2 million of realized losses and $16.0 million of unrealized loss from the decrease in the fair value of our open contracts. During the nine months ended September 30, 2025, we recorded a $13.4 million derivative gain for our natural gas derivative contracts consisting of $15.5 million of realized gains offset by $2.1 million of unrealized loss from the decrease in the fair value of our open contracts.
Other expense, net – Other expense, net decreased $9.8 million for the nine months ended September 30, 2026 compared to the same period in 2025 primarily related to an accrual of additional expenses in the nine months ended September 30, 2025 for new abandonment obligations related to our assumption of decommissioning obligations when certain counterparties in past divestiture transactions or third parties in existing leases have filed for bankruptcy protection or may not be able to perform required abandonment obligations.
Income tax expense – Our effective tax rate for the nine months ended September 30, 2026 was (8.1)% and differed from the federal statutory rate primarily due to the impact of losses with no tax benefit, nondeductible compensation and adjustments to the valuation allowance. Our effective tax rate for the nine months ended September 30, 2025 was not meaningful and differed from the federal statutory rate primarily due to the recording of a valuation allowance against our net deferred tax assets.
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, 2026, we had $191.3 million of unrestricted cash on hand and $43.4 million available under our Credit Agreement, based on a borrowing base of $50.0 million and $6.6 million of letters of credit outstanding. We also have up to approximately $68.1 million of availability through our “at-the-market” equity offering program, pursuant to which we may offer and sell shares of our common stock from time to time. Based on our current financial condition and current expectations of future market conditions, we believe our cash on hand, cash flows from operating activities and access to the equity markets from our “at-the-market” equity offering program will provide us with additional liquidity to continue our growth and will allow us to meet our cash requirements for at least the next 12 months and beyond.
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We continuously review our liquidity and capital resources. If market conditions were to change, for instance due to uncertainty created by geopolitical events, a pandemic or a significant decline in oil and natural gas prices, and our revenue was reduced significantly or operating costs were to increase significantly, our cash flows and liquidity could be negatively impacted.
Cash Flow Information
The following table summarizes cash flows provided by (used in) by type of activity for the following periods (in thousands):
Operating activities
21,217
Investing activities
(58,778)
Financing activities
72,466
Operating Activities
Our largest source of operating cash is collecting cash from customers and joint interest partners from sales of our products. The primary use of operating cash is to pay our suppliers, employees and others for a wide range of goods and services.
Net cash provided by operating activities increased $21.2 million in the nine months ended September 30, 2026 compared to the corresponding period in 2025. This was primarily due to a favorable change of $62.9 million in net loss adjusted for certain noncash items offset by an unfavorable change of $41.7 million in operating cash flows from changes in operating assets and liabilities. The favorable change in net loss adjusted for certain noncash items was primarily related to increases of $100.0 million in revenues offset by an increase of $35.1 million in derivative settlements. The unfavorable change in operating assets and liabilities is primarily related to higher ARO settlements and unfavorable changes in accounts receivable, accounts payable and accrued liabilities and other.
Investing Activities
Our principal recurring investing activity is the funding of acquisitions and investments in oil and natural gas properties to support and generate revenues from operations. Cash flows (used in) provided by investing activities were $(27.1) million and $31.6 million during the nine months ended September 30, 2026 and 2025, respectively. Investments in oil and natural gas properties were $26.9 million and $38.9 million during the nine months ended September 30, 2026 and 2025, respectively. During the nine months ended September 30, 2025, we received $58.5 million in insurance proceeds and $11.9 million in proceeds from the sale of oil and natural gas properties. As we use the full cost method of accounting for our oil and natural gas properties, these proceeds were recorded in our full cost pool.
Financing Activities
Cash flows provided by (used in) financing activities were $5.3 million and $(67.1) million for the nine months ended September 30, 2026 and 2025, respectively. During the nine months ended September 30, 2026, we used $8.0 million in proceeds from our New TVPX Loan to repay the $8.0 million of balloon payment that was due at the maturity date of the TVPX Loan. In addition, we received $14.7 million in net proceeds from the sale of our common stock in connection with our “at-the-market” equity offering program. In connection with our debt refinancing in January 2025, we received $350.0 million in proceeds from the issuance of our 10.75% Notes and used these proceeds, along with cash on hand, to (i) purchase for cash, pursuant to a tender offer, $269.8 million of our 11.75% Senior Second Lien Notes due 2026 (the “11.75% Notes”); (ii) repay $114.2 million of amount outstanding under the credit agreement of certain of our indirect, wholly-owned subsidiaries; (iii) purchase $5.3 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 $21.7 million in premiums, fees and debt issuance costs.
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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):
Exploration and development
Conventional shelf (1)
7,260
31,765
Deepwater
12,813
5,024
Acquisitions of interests
711
Seismic and other
616
4,656
Investments in oil and gas property/equipment – accrual basis
20,689
42,156
In our view of the outlook for the remainder of 2026, we believe our expected level of capital expenditure will leave us with sufficient liquidity to operate our business, while providing liquidity to make strategic acquisitions. At current pricing levels, we expect our cash flows to cover our liquidity requirements, and we expect additional financing sources to be available if needed. If our liquidity becomes stressed from significant or prolonged reductions in realized prices, we have flexibility in our capital expenditure budget to reduce investments. We strive to maintain flexibility in our capital expenditure projects and if commodity prices improve, we may increase our investments.
Acquisitions
We have grown by making strategic acquisitions of producing properties in the Gulf of America. We seek opportunities where we can exploit additional drilling projects and reduce costs.
Any future acquisitions are subject to the completion of satisfactory due diligence, the negotiation and resolution of significant legal issues, the negotiation, documentation and completion of mutually satisfactory definitive agreements among the parties, the consent of our lenders, our ability to finance the acquisition and approval of our board of directors. We cannot guarantee that any such potential transaction would be completed on acceptable terms, if at all.
Asset Retirement Obligations
We have obligations to plug and abandon wells, remove platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. Through the nine months ended September 30, 2026, we have paid $26.5 million related to these obligations. Our ARO estimates as of September 30, 2026 and December 31, 2025 were $580.8 million and $561.9 million, respectively. As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one to many years in the future, actual expenditures could be substantially different than our estimates. See Part I, Item 1A. Risk Factors, of our 2025 Annual Report for additional information.
As of September 30, 2026, we have $358.0 million in aggregate principal amount of long-term debt outstanding, with $1.0 million in aggregate principal coming due over the next twelve months.
For additional information about our long-term debt, see Part I, Item 1. Financial Statements – Note 4 – Debt of this Quarterly Report and Part II, Item 8. Financial Statements and Supplementary Data, in our 2025 Annual Report.
24
During the nine months ended September 30, 2026, we declared cash dividends of $4.9 million to holders of our common stock. The amount and frequency of future dividends is subject to the discretion of our board of directors and primarily depends on earnings, capital expenditures, debt covenants and various other factors.
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, 2026 and assuming no other items had changed, our revenue would have decreased by approximately $16.2 million and $46.8 million in the three and nine months ended September 30, 2026, respectively. This amount would be representative of the effect on operating cash flows under these price change assumptions.
We have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted production through the use of swaps, purchased calls and purchased puts. Our derivatives will not mitigate all the commodity price risks of our forecasted production and, as a result, we will be subject to commodity price risks on our remaining forecasted production.
The following table summarizes the historical results of our derivatives:
Three Months Ended
Nine Months Ended
Oil ($/Bbl):
Average realized sales price, before the effects of derivative settlements
Effects of realized commodity derivatives
(7.52)
(6.86)
Average realized sales price, including realized commodity derivatives
77.54
77.45
Natural Gas ($/Mcf)
0.95
0.57
4.50
Our exposure to interest rate risk has not changed materially from the disclosures in Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, of our 2025 Annual Report.
ITEM 4. CONTROLS AND PROCEDURES
We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
As required by Exchange Act Rule 13a-15(b), our CEO and CFO performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this Quarterly Report. Based on that evaluation, our CEO and CFO have each concluded that as of September 30, 2026, our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.
During the quarter ended September 30, 2026, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
26
ITEM 1. LEGAL PROCEEDINGS
See Part I, Item 1. Financial Statements – Note 5 – Commitments and Contingencies of this Quarterly Report for information on various legal proceedings to which we are a party or our properties are subject.
ITEM 1A. RISK FACTORS
In addition to the information set forth in this Quarterly Report, investors should carefully consider the risk factors and other cautionary statements included under Part I, Item 1A. Risk Factors, in our 2025 Annual Report, together with all of the other information included in this Quarterly Report, and in our other public filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
Notwithstanding the matters discussed herein, there have been no material changes in our risk factors as previously disclosed in Part I, Item 1A. Risk Factors in our 2025 Annual Report.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
ITEM 4. MINE SAFETY DISCLOSURES
ITEM 5. OTHER INFORMATION
During the three months ended September 30, 2026, none of our directors or “officers” (as such term is defined in Rule 16(a)-1(f) under the Exchange Act) adopted or terminated a “Rule 10b5-1 trading agreement” or “non-Rule 10b5-1 trading arrangement” (each as defined in Item 408(a) and (c) of Regulation S-K).
ITEM 6. EXHIBITS
ExhibitNumber
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
First Amendment to the Amended and Restated Employment Agreement, dated as of August 5, 2026, by and between W&T Offshore, Inc. and Tracy W. Krohn (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed August 7, 2026)
10.2
Second Amendment to Credit Agreement, dated as of October 1, 2026, by and among W&T Offshore, Inc., the subsidiary guarantors party thereto, Texas Capital Bank, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed October 7, 2026)
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.
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 October 29, 2026.
By:
/s/ Sameer Parasnis
Sameer Parasnis
Executive Vice President and Chief Financial Officer