W&T Offshore Inc.
10/29/2026 | Press release | Distributed by Public on 10/29/2026 15:01
Quarterly Report for Quarter Ending September 30, 2026 (Form 10-Q)
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.
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
||||
|
|
|
2026 |
|
2025 |
|
|
Change |
||
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
111,773 |
|
$ |
84,131 |
|
$ |
27,642 |
|
NGLs |
|
9,121 |
|
4,000 |
|
5,121 |
|||
|
Natural gas |
|
41,204 |
|
37,400 |
|
3,804 |
|||
|
Other |
|
4,982 |
|
1,984 |
|
2,998 |
|||
|
Total revenues |
|
167,080 |
|
127,515 |
|
39,565 |
|||
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes: |
|
|
|
|
|
|
|||
|
Oil (MBbls) (1) |
|
1,314 |
|
1,302 |
|
12 |
|||
|
NGLs (MBbls) |
|
482 |
|
280 |
|
202 |
|||
|
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 |
|||
| (1) | MBbls - thousands of barrels of oil, condensate or NGLs |
| (2) | MMcf - million cubic feet |
| (3) | MBoe - thousand barrels of oil equivalent |
| (4) | Boe - barrels of oil equivalent |
| (5) | Bbl - barrels of oil, condensate or NGLs |
| (6) | Mcf - thousand cubic feet |
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 |
|
Total |
|||
|
Oil |
$ |
26,863 |
|
$ |
779 |
|
$ |
27,642 |
|
NGLs |
2,223 |
|
|
2,898 |
|
5,121 |
||
|
Natural gas |
3,269 |
|
|
535 |
|
3,804 |
||
|
|
$ |
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
||||
|
|
|
2026 |
|
2025 |
|
|
Change |
||
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
76,671 |
|
$ |
76,215 |
|
$ |
456 |
|
Gathering, transportation and production taxes |
|
|
9,376 |
|
|
5,818 |
|
|
3,558 |
|
Depreciation, depletion and amortization |
|
28,266 |
|
|
28,580 |
|
(314) |
||
|
Asset retirement obligations accretion |
|
|
8,606 |
|
|
8,002 |
|
|
604 |
|
General and administrative expenses |
|
|
31,685 |
|
|
21,510 |
|
|
10,175 |
|
Other operating expenses |
|
|
655 |
|
|
- |
|
|
655 |
|
Total operating expenses |
|
$ |
155,259 |
|
$ |
140,125 |
|
$ |
15,134 |
|
|
|
|
|
|
|
|
|
|
|
|
Average per Boe ($/Boe): |
|
|
|
|
|
|
|||
|
Lease operating expenses |
|
$ |
21.82 |
|
$ |
23.27 |
|
$ |
(1.45) |
|
Gathering, transportation and production taxes |
|
2.67 |
|
|
1.78 |
|
0.89 |
||
|
Depreciation, depletion and amortization |
|
8.04 |
|
|
8.73 |
|
(0.69) |
||
|
Asset retirement obligations accretion |
|
|
2.45 |
|
|
2.44 |
|
|
0.01 |
|
General and administrative expenses |
|
9.02 |
|
|
6.57 |
|
2.45 |
||
|
Other operating expenses |
|
|
0.19 |
|
|
- |
|
|
0.19 |
|
Total operating expenses |
|
$ |
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.
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
||||
|
|
|
2026 |
|
2025 |
|
|
Change |
||
|
Interest expense, net |
$ |
8,956 |
|
$ |
8,998 |
$ |
(42) |
||
|
Derivative loss (gain), net |
|
|
15,800 |
|
|
(4,108) |
|
|
19,908 |
|
Other expense (income), net |
|
216 |
|
|
(2,017) |
|
2,233 |
||
|
Income tax expense |
|
498 |
|
|
55,991 |
|
(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.
Nine Months Ended September 30, 2026 Compared to the Nine Months Ended September 30, 2025
Revenues
The following table presents information regarding our revenues, production volumes and average realized sales prices (which exclude the effect of hedging unless otherwise stated) for the periods presented and corresponding changes (in thousands, except average realized sales prices data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
||||
|
|
|
2026 |
|
2025 |
|
|
Change |
||
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
322,330 |
|
$ |
251,861 |
|
$ |
70,469 |
|
NGLs |
|
22,069 |
|
13,487 |
|
8,582 |
|||
|
Natural gas |
|
123,184 |
|
107,311 |
|
15,873 |
|||
|
Other |
|
12,135 |
|
7,090 |
|
5,045 |
|||
|
Total revenues |
|
$ |
479,718 |
|
$ |
379,749 |
|
$ |
99,969 |
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes: |
|
|
|
|
|
|
|||
|
Oil (MBbls) |
|
3,823 |
|
3,791 |
|
32 |
|||
|
NGLs (MBbls) |
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
Average realized sales prices: |
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl) |
|
$ |
84.31 |
|
$ |
66.44 |
|
$ |
17.87 |
|
NGLs ($/Bbl) |
|
17.86 |
|
18.60 |
|
(0.74) |
|||
|
Natural gas ($/Mcf) |
|
4.22 |
|
3.93 |
|
0.29 |
|||
|
Oil equivalent ($/Boe) |
|
|
47.09 |
|
|
41.08 |
|
|
6.01 |
|
Oil equivalent ($/Boe), including realized commodity derivatives |
|
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):
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
Volume |
|
Total |
|||
|
Oil |
$ |
68,283 |
|
$ |
2,186 |
|
$ |
70,469 |
|
NGLs |
(934) |
|
|
9,516 |
|
8,582 |
||
|
Natural gas |
8,457 |
|
|
7,416 |
|
15,873 |
||
|
|
$ |
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.
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
||||
|
|
|
2026 |
|
2025 |
|
|
Change |
||
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
214,348 |
|
$ |
224,151 |
|
$ |
(9,803) |
|
Gathering, transportation and production taxes |
|
|
24,595 |
|
|
16,976 |
|
|
7,619 |
|
Depreciation, depletion and amortization |
|
81,109 |
|
|
87,917 |
|
(6,808) |
||
|
Asset retirement obligations accretion |
|
25,899 |
|
|
25,075 |
|
824 |
||
|
General and administrative expenses |
|
|
84,026 |
|
|
59,337 |
|
|
24,689 |
|
Other operating expenses |
|
|
655 |
|
|
- |
|
|
655 |
|
Total operating expenses |
|
$ |
430,632 |
|
$ |
413,456 |
|
$ |
17,176 |
|
|
|
|
|
|
|
|
|
|
|
|
Average per Boe ($/Boe): |
|
|
|
|
|
|
|||
|
Lease operating expenses |
|
$ |
21.59 |
|
$ |
24.71 |
|
$ |
(3.12) |
|
Gathering, transportation and production taxes |
|
2.48 |
|
1.87 |
|
0.61 |
|||
|
Depreciation, depletion and amortization |
|
8.17 |
|
9.69 |
|
(1.52) |
|||
|
Asset retirement obligations accretion |
|
|
2.61 |
|
|
2.76 |
|
|
(0.15) |
|
General and administrative expenses |
|
8.46 |
|
6.54 |
|
1.92 |
|||
|
Other operating expenses |
|
|
0.07 |
|
|
- |
|
|
0.07 |
|
Total operating expenses |
|
$ |
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.
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.
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, |
|
|
|
||||
|
|
|
2026 |
|
2025 |
|
|
Change |
||
|
Interest expense, net |
|
$ |
27,373 |
|
$ |
27,495 |
|
$ |
(122) |
|
Loss on extinguishment of debt |
|
|
- |
|
|
15,015 |
|
|
(15,015) |
|
Derivative loss (gain), net |
|
42,230 |
|
|
(13,398) |
|
55,628 |
||
|
Other expense, net |
|
1,334 |
|
|
11,122 |
|
(9,788) |
||
|
Income tax expense |
|
1,767 |
|
|
48,994 |
|
(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.
We continuously review our liquidity and capital resources. If market conditions were to change, for instance due to uncertainty created by geopolitical events, a pandemic or a significant decline in oil and natural gas prices, and our revenue was reduced significantly or operating costs were to increase significantly, our cash flows and liquidity could be negatively impacted.
Cash Flow Information
The following table summarizes cash flows provided by (used in) by type of activity for the following periods (in thousands):
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|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
||||
|
|
|
2026 |
|
2025 |
|
|
Change |
||
|
Operating activities |
|
$ |
72,520 |
|
$ |
51,303 |
|
$ |
21,217 |
|
Investing activities |
|
(27,148) |
|
31,630 |
|
(58,778) |
|||
|
Financing activities |
|
5,325 |
|
(67,141) |
|
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.
Capital Expenditures
The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of oil, NGLs and natural gas, acquisition opportunities, liquidity and financing options and the results of our exploration and development activities.
The following table presents our capital expenditures for exploration, development, acquisitions and other leasehold costs (in thousands):
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|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
||||
|
|
|
2026 |
|
2025 |
||
|
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 |
| (1) | Includes exploration and development capital expenditures in Alabama state waters. |
In our view of the outlook for the remainder of 2026, we believe our expected level of capital expenditure will leave us with sufficient liquidity to operate our business, while providing liquidity to make strategic acquisitions. At current pricing levels, we expect our cash flows to cover our liquidity requirements, and we expect additional financing sources to be available if needed. If our liquidity becomes stressed from significant or prolonged reductions in realized prices, we have flexibility in our capital expenditure budget to reduce investments. We strive to maintain flexibility in our capital expenditure projects and if commodity prices improve, we may increase our investments.
Acquisitions
We have grown by making strategic acquisitions of producing properties in the Gulf of America. We seek opportunities where we can exploit additional drilling projects and reduce costs.
Any future acquisitions are subject to the completion of satisfactory due diligence, the negotiation and resolution of significant legal issues, the negotiation, documentation and completion of mutually satisfactory definitive agreements among the parties, the consent of our lenders, our ability to finance the acquisition and approval of our board of directors. We cannot guarantee that any such potential transaction would be completed on acceptable terms, if at all.
Asset Retirement Obligations
We have obligations to plug and abandon wells, remove platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. Through the 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.
Debt
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.
Dividends
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.
W&T Offshore Inc. published this content on October 29, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on October 29, 2026 at 21:01 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]