W&T Offshore, Inc. Q4 FY2025 earnings call

• Focus on cash flow generation, maintaining and optimizing high-quality conventional assets, and opportunistically capitalizing on accretive opportunities. - Increased production every quarter in 2025 through production enhancement projects. - Invested $55,000,000 in 2025 CapEx, performed 34 workovers and 4 recompletions. - Generated adjusted EBITDA of $130,000,000 for full year 2025. - Grew cash by $31,000,000 and reduced net debt by $74,000,000 at year-end 2025. - Returned value to shareholders through quarterly dividend, paid nine consecutive quarterly cash dividends since late 2023. - In 2026, focus on enhancing production and minimizing decline through low-cost, low-risk workovers, cost control, and capturing synergies from asset acquisitions. - Completed major projects on acquired assets in 2025, reflecting production and cash flow benefits. - DOI proposed regulatory changes that could reduce insurance costs and financial burdens for the industry.

In 2025, production increased every quarter from 30,500 barrels of oil equivalent per day in Q1 to 36,200 in Q4. Adjusted EBITDA was $130,000,000. Year-end proved reserves were 121,000,000 barrels of oil equivalent with a PV-10 of $1,100,000,000 (improved since March due to geopolitics). Fourth quarter LOE was $22.4 per barrel of oil equivalent, 4% lower than 2025. 2026 costs expected to be lower. Reserves breakdown: 71% proved developed producing, 24% proved developed non-producing, 5% proved undeveloped. 42% liquids (32% crude oil, 10% NGLs) and 58% natural gas.

• 2026 production midpoint expected to be around 35,000 barrels of oil equivalent per day (assuming no additional acquisitions or drilling). - 2026 LOE projected to be lower than 2025. - First quarter 2026 LOE expected to be between $63,000,000 and $70,000,000 and full year 2026 LOE of $265,000,000 to $295,000,000. - First quarter gathering, transportation, and production taxes expected to range between $8,000,000 and $9,000,000. - First quarter cash G&A costs expected to be between $15,000,000 and $17,000,000.

• Geopolitical factors could impact reserves and financials. - Regulatory changes in the past have imposed financial burdens and affected the industry. - Unplanned downtime due to winter freezes can temporarily reduce production volumes. - Antitrust lawsuits related to surety providers can affect available capital for work and development.

Q: Starting with your guide, it is clear that you are prioritizing capital discipline and preservation in the current macro environment, not overly focusing on the front part of the curve. With that said, could you speak to where you see the greatest opportunity in the market for cash-on-cash returns, and if there is a sustained price scenario where you would be more inclined to engage the drill bit?

A: Thanks, Derrick. Sure. We still think that there will be acquisitions available, and we are confident that we will have our fair share over the next one to two years. We have maintained a record over 40 years of being able to replace and replenish those reserves. Short term and long term, we still see those as possibilities for growth. Organically, we do have prospect inventory, but we feel that our efforts are better placed in making acquisitions as opposed to trying to drill right now. All those prospects, with the exception of a couple of them, are actually held by production.

Q: And for my follow-up, I wanted to focus on the regulatory policy updates you referenced in your prepared remarks. As you see it today, could you speak to what it means for W&T Offshore, Inc. from an insurance cost perspective? And if there could also be potential impacts to your cost of capital as you start to reduce the financial burdens?

A: Sure. To us, that means that the insurance premium costs will be going down in the future. We have made a lot of those payments already this year. What that means is that, because of the change in the regulations with regard to financial assurance—which was a term that was, or supplemental financial insurance rather, is a term that was coined in the Obama administration and further exasperated in the Biden administration—that provided so-called financial assurance for decommissioning costs. Most of these leases have, in the chain of title—and that is referenced in the actual lease that operators signed as lessees—you are required, as a lessee on any lease, to be jointly and severally liable for all the due decommissioning liabilities on the lease. So if Exxon owned a property or Shell or Chevron or anybody owned the property 20 years ago and had a lease interest, sold it, it lapsed, whatever, and the lease comes up having remaining decommissioning liabilities, those responsible in that queue are liable jointly and severally for all of those assets being removed from the ocean floor and decommissioning of all the wells. So the government never really needed these financial assurances. This was something that was done by this administration to be punitive. Unfortunately, it sucked a few companies out of The Gulf. A few of our competitors are gone and are not there anymore. A few producers that were contributing to the overall energy output of The United States are no longer there. Clearly, those premiums could have been used better as actual capital to get rid of some of those decommissioning issues that companies had. We feel like this is a proper and fitting action that the government has taken, and we applaud them greatly.

Q: Thank you. Good morning. Tracy, can you talk about the depth of inventory W&T Offshore, Inc. has for recompletions and workovers that help you maintain or offset natural declines?

A: I will do better than that. I will defer that question to William J. Williford, who is our Chief Operating Officer.

Q: With respect to the regulatory environment that Derrick asked about, Tracy, do any of the proposed changes have an effect on what is attractive to W&T Offshore, Inc. in the acquisition market and the valuations of assets?

A: Yes. One of the things that I think you will see as a result of the change in regulatory requirements is fields will be allowed to produce longer, because you will not have to have these massive cash outlays or insurance outlays from a market that has shrunk and has shrunk a great deal. You will not have these massive cash and collateral requirements required by these companies to attempt to extort money from companies for their own purposes. We are involved in a lawsuit right now with some of the surety providers on an antitrust basis. That is one of the things that we have had to deal with as an industry. That takes away from the capital that is available to do actual work and drill wells and make improvements to leases.

Q: Thank you. And if I could ask just one more, Tracy, when you think about the types of acquisitions that you want to look at, if you focus primarily on exploitation and development, are you able to find properties that you can acquire without paying for what the seller might think is drilling upside?

A: Drilling upside is nebulous. Of course, that is always the highest-risk asset class, or potential asset class. You never really know what you are going to find until you put a hole in the ground to investigate it. No, I do not think that that changes the outlook. Most people do not think about additional drilling assets as primary in the consideration, unless you have already made a discovery and you are drilling on the fringes of that discovery. I think that you know this well. I know this is the largest basin by area in The U.S., and it is the second-largest by producing assets. We have been able to make a pretty good living over the last 40 years and increase values for shareholders and for our contractors and everybody else. It is a lovely little food chain that exists in the Gulf Of Mexico. This will help continue that trend that the Obama and Biden administrations helped to, or tried to, get rid of.

Q: Hey guys, thanks for allowing me to ask additional questions. Before the follow-up, I wanted to ask about the facility and production enhancements you pursued with Cox and the new marketing agreement for Mobile Bay. More specifically, could you help quantify or provide color on the uplift you expect in realizations and volumes by product?

A: That is a pretty comprehensive question, Derrick. I am not sure I have all the answers for your questions there right now as a sum total. What we do not do in The U.S. is we do not provide for a methodology of giving value to 2P reserves. We have to go to great lengths to explain that. In Europe, you are allowed to include 2P reserves in your reserve base. In The United States, via the SEC, we are not allowed to do that. That is the bigger difference that is hard to quantify. We do see that as value, and we have seen that year over year over year as an increase to our reserves by virtue of the type of reservoirs that we have—mainly water-drive reservoirs—that will actually provide a pressure mechanism by which Mother Nature actually helps us to drive that oil to the producing perforations. We are fortunate in this basin to have Mother Nature giving us a helping hand, so to speak.

Q: And, Tracy, maybe on that point, if I am looking at slide 16 of your new presentation, the way that I am reading that is that in your 2P bookings, you effectively do not need to drill any new wells, and you have the probable outcome of receiving additional recovery, thereby, again, increasing longevity of the asset base without new development capital being spent. Is that a fair prediction?

A: That is very fair. Derrick, I get a little bit nervous about quantifying some of these results because, in past administrations, that has been frowned on as an expression of 2P. But clearly, we book more cash and reserves over time as we realize that 2P part of our production stream. Traditionally, think about 1P reserves as proved producing and proved undeveloped and proved behind pipe, and then 2P is probable producing and probable behind pipe, probable undeveloped. We get a large portion—in fact, in that presentation that you referred to, it is about $750,000,000—of additional cash flow without any CapEx, hence no drilling, that comes to the wellbore in the form of cash and additional reserve bookings over time. It is a very effective tool that we find in the Gulf Of Mexico to add value without having to make capital expenditures.