Ladies and gentlemen, thank you for standing by. Welcome to the W&T Offshore's fourth quarter and full year 2025 conference call. During today's call, all parties will be in a listen-only mode. Following the company's prepared remarks, the call will be open for questions and answers. During the question-and-answer session, we will ask that you limit yourself to one question and one follow-up. You can always rejoin the queue. This conference is being recorded, and a replay will be made available on the company's website following the call. I would now like to turn the conference over to Al Petrie, Investor Relations Coordinator. Please go ahead. Thank you, Dave. On behalf of the management team, I would like to welcome all of you to today's conference call to review W&T Offshore's fourth quarter and full year 2025 financial and operational results. Before we begin, I'd like to remind you that our comments may include forward-looking statements. It should be noted that a variety of factors could cause W&T's actual results to differ materially from the anticipated results or expectations expressed in these forward-looking statements. Today's call may also contain certain non-GAAP financial measures. Please refer to the earnings release that we issued yesterday for disclosures on forward-looking statements and reconciliations of non-GAAP measures. With that, I'd like to turn the call over to Tracy Krohn, our Chairman and CEO. Thanks, Al. Good morning, everyone, and welcome to our year-end 2025 conference call. With me today are William Williford, our Executive Vice President and Chief Operating Officer, Samir Parasnis, our Executive Vice President and Chief Financial Officer, and Trey Hartman, our Vice President and Chief Accounting Officer, who are all available to answer questions later during the call. We delivered solid operational and financial results in 2025 by remaining focused on our strategic vision. Our proven strategy is simple and effective. We focus on cash flow generation, maintaining and optimizing our high-quality conventional assets, and opportunistically capitalizing on accretive opportunities to build shareholder value. We're successfully executing our strategy and remain committed to that operational performance, returning value to our stakeholders and ensuring the safety of our employees and contractors. Our ability to deliver consistent production and EBITDA results while integrating producing property acquisitions has helped W&T grow during our 40+ year history. In 2025, we accomplished many things. Here's the bullet points. One, we increased production every quarter in 2025 from 30,500 barrels of oil equivalent per day in the first quarter to 36,200 barrels of oil equivalent per day in the fourth quarter by focusing on production enhancement projects. Two, while we did not drill any new wells, we did invest $55 million in 2025 CapEx and performed 34 workovers and 4 recompletions. Three, we also generated adjusted EBITDA of $130 million for full year 2025. Four, we continued to focus on enhancing our liquidity and reducing debt. At year-end 2025, we grew cash by $31 million year over year to almost $141 million and reduced our net debt by $74 million to $210 million, further strengthening that balance sheet. Five, we reported year-end 2025 proved reserves of 121 million barrels of oil equivalent with a PV-10 of $1.1 billion. Obviously those numbers have gotten better since the beginning of March due to geopolitics. Six, we accomplished all of this while also returning value to our shareholders through our quarterly dividend. We've paid 9 consecutive quarterly cash dividends since initiating the dividend policy in late 2023 and announced the first quarter 2026 payment that will occur later this month. Going into a little more detail about the positive production numbers we were able to deliver in 2025. Normally in the first quarter of every year, we have some temporary downtime associated with the impact from cold weather and freezes. We experienced some in 2025 and again in 2026 as well. Through our focus, production uplift projects and continued focus on ramping up recently acquired fields, we were able to achieve quarter-over-quarter growth and year-over-year growth. In the fourth quarter, production was up 2% over Q3 2025 and up 13% over the same quarter in 2024. Over the years, we've consistently created value by very methodically integrating producing property acquisitions, enhancing their capabilities, and thus extracting greater value. After we close any acquisition, we take time to assess and more fully evaluate the newly acquired assets. We have a large footprint across the Gulf of Mexico, so we look for ways to optimize operations, increase production, and utilize that large footprint where we can. That reduces costs and maximizes value. We work really hard on logistics. The assets we acquired in 2024 added meaningful reserves at an attractive price, and they required some additional capital and expense spending to maximize that production capability in all those fields. By the fourth quarter of 2025, we'd also completed all the major projects on the acquired assets and the production and cash flow benefits from the diligent work of this team to get all those properties online and up to our operating standards is reflected in our results. Moving into 2026, we remain focused on enhancing production and minimizing decline across our asset base through low cost, low risk workovers or recompletions. We remain focused on cost control and capturing synergies associated with those asset acquisitions. We reduced our fourth quarter LOE to $22.40 per barrel of oil equivalent, which was 4% lower compared with the third quarter of 2025, and our absolute costs were below the midpoint of our guidance. Looking ahead, we're expecting our 2026 costs to be lower compared to 2025, which I will discuss later in the call. For the full year 2025, our capital expenditures were $55 million coming in below the lower end of our capital guidance. In the fourth quarter, we finished a $20 million pipeline facility project at West Delta 73 that will help support production growth, improve operational performance, and increase our net realized pricing. We expect to see the benefit of that project in the first quarter of 2026. Overall, our capital expense was back half loaded in 2025, driven by recompletion and facility capital work to bring online and increase production in multiple fields relating to the 2024 acquisition. In addition, our asset retirement settlement costs totaled $37 million for 2025 as we continue to responsibly decommission assets. You can see our operational performance in 2025 allowed us to focus on improving our balance sheet. At the beginning of 2025, we had several transactions that strengthened and simplified our balance sheet, adding material cash to the bottom line and improving our credit ratings from S&P and Moody's. In January, we successfully closed a $350 million offering of new second lien notes that decreased our interest rates by 100 basis points, and together with other transactions, reduced our total debt by $39 million. We also entered into a new credit agreement for a $50 million revolving credit facility, which matures in July 2028, that replaced the previous $50 million credit facility provided by Calculus Lending. We also sold a non-core interest at Garden Banks, which included about 200 barrels of oil equivalent per day for $12 million, and we received $58 million in cash for an insurance settlement related to the Mobile Bay 78-1 well. All of these actions have allowed us to enhance liquidity and improve our financial flexibility. These financial actions, coupled with strong operational performance, allowed us to increase cash by $31 million and reduce our net debt by $74 million at year-end 2025. All of this was accomplished in what I consider to have been a much lower price environment for oil and gas. Our ability to execute our strategy delivered positive results in 2025, including an improved balance sheet, enhanced liquidity, growing production, and adjusted EBITDA, all of which has positioned us for success as we move into 2026. We are well positioned to take advantage of growth opportunities like we've done in the past, focusing on accretive low-risk acquisitions of producing properties rather than high risk drilling in the uncertain commodity price environment. These acquisitions must meet our stringent criteria of, one, generating free cash flow, two, providing a solid base of proved reserves with upside potential, and three, providing for the ability of our operations team to reduce costs. With our experience, strong balance sheet over our 40-year track history, we've successfully integrated acquisitions. We believe we are well-positioned to add to those impressive portfolios of assets. Turning to our year-end reserve results. We have a portfolio of conventional Gulf of Mexico assets that have established a record value over time. Over the past two years, our overall year-end reserves have remained virtually flat, including the volume and the PV-10. We've produced 24.6 million barrels of oil equivalent of production, but we've also made an accretive acquisition of several fields that's helped to offset this production. Since closing the latest acquisition in January 2024, we've generated almost $285 million in adjusted EBITDA, while only spending about $167 million in capital expenditures, including acquisitions. We believe that our strategy of acquiring and enhancing producing properties continues to add value to our shareholders as reflected in our reserve amounts and value. For year-end 2025, our SEC proved reserves were 121 million barrels of oil equivalent with a PV-10 of $1.12 billion in a reduced price environment. Notably, we recorded an increase to PDP PV-10 of $279 million. That's proved developed producing reserve compared to year-end 2024, as we had reserves reclassified to proved developed producing. The reserves were classified as 71% proved developed producing, 24% proved developed non-producing, and only 5% proved undeveloped. At year-end 2024, only 52% were proved developed producing and 17% were proved undeveloped. W&T's reserve lives ratio at year-end 2025, based on year-end 2025 proved reserves and 2025 production, was 9.8 years, about 10 years. Approximately 42% of year-end 2025 SEC proved reserves were liquids, with 32% crude oil and 10% NGLs, and we had 58% natural gas. Yesterday, we provided detailed guidance for first quarter and full year 2026 in our earnings release. In the first quarter of 2026, as I previously mentioned, we incurred unplanned downtime at several fields due to winter freezes that temporarily reduced our production volumes. We're predicting the midpoint of Q1 2026 production to be around 35,000 barrels of oil equivalent per day. We are continuing to focus on production enhancement projects throughout 2026, and we expect the full 2026 production midpoint to also be around 35,000 barrels of oil equivalent per day. This is assuming no additional acquisitions or drilling. Our ability to maintain low decline production is a testament to our quality and our culture of operational excellence and the strength of our reserves. With several capital projects completed in 2025, we're planning much lower capital expenditures for 2026 due to a substantial reduction in capital projects associated with pipelines at about $22 million at the midpoint, or less than half the amount invested in 2025. This does not include acquisitions. We're also forecasting about $38 million in plugging and abandonment expenses for 2026. That's in line with the $37 million we spent in 2025. We have a reliable asset base of low decline wells, and we've focused more on acquisition over the past several years rather than on drilling many new wells, which has kept our capital spending much lower. Turning to costs, our guidance for 2026 LOE is projected to be lower than 2025, despite higher production in 2026. Similar to the capital projects, we spent operating expenses on recently acquired fields to bring them in line with our operational standards. Additionally, some of the capital projects that we undertook in 2025 should lead to lower expenses and higher price realizations. With that said, I believe that there are more opportunities to reduce our operating costs and find synergies to drive costs lower in the long term. Safety is paramount, and we are always working hard to reduce costs without impacting safety or deferring asset integrity work. Our first quarter 2026 LOE is expected to be between $63 million and $70 million, and full year 2026 LOE of $265 million-$295 million, which reflects the savings I mentioned earlier. Our first quarter gathering, transportation, and production taxes are expected to range between $8 million and $9 million. First quarter cash G&A costs are expected to be between $15 million and $17 million. As we mentioned in yesterday's earnings release, the DOI, Department of the Interior, has proposed some positive regulatory changes that would roll back obligations from the 2024 rule that would have required companies to set aside about $6.9 billion in supplemental financial assurance. About $6 billion would apply to small businesses that make up most of the operators in the Gulf. The proposed changes will better align financial assurance requirements with actual decommissioning risk and could reduce industry-wide bonding by approximately $484 million annually. These proposed revisions have been published in the Federal Register in the 60-day public comment period. That's expected to end on May 8, 2026. We welcome these changes proposed by the Trump administration that can further encourage US offshore production growth and further increase America's energy independence. Before we wrap up the call, I'd like to say how proud I am of all the people who've helped make W&T a success since we founded the company in 1983. Throughout that time, we've been an active, responsible, and profitable operator in the Gulf of Mexico. We're staunch advocates for the offshore industry, and we believe that our outstanding long life assets will continue to provide value for our shareholders and our country for many more years. As the largest shareholder, I believe we are well positioned to continue to grow and add value as we move into 2026. Our guidance forecasts that we can modestly grow production and reduce costs, which should lead to a continued buildup of our cash position. This allows us to remain active in evaluating growth opportunities, both organically and inorganically. We have a long track record of successfully integrating those assets into our portfolio, and we continue to believe that the Gulf of Mexico is a world-class basin that supports value creation. We remain focused on operational excellence and maximizing the cash flow potential of our asset base. With that, operator, we can now open the lines for questions. We'll now begin the question and answer session. To ask a question, you may press star then one on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star and then two. Our first question comes from Derrick Whitfield with Texas Capital. Please go ahead. Good morning, all, and great update. Thanks, Derrick. Starting with your guide, it's 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? If there is a sustained price scenario where you'd be more inclined to financially engage the drill bit? Sure. Well, we still think that there will be acquisitions available. We're confident that we'll have our fair share over the next 1-2 years. We've maintained a record over 40 years of being able to replace and replenish such 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. Great. For my follow-up, Tracy, I wanted to focus on the regulatory policy updates you referenced in your prepared remarks. As you guys see it today, could you speak to what it means for W&T 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? Sure. Well, to us, that means that insurance premium costs will be going down in the future. We've made a lot of those payments already this year. What that means is that because of the change in the regulations with regard to supplemental financial assurance rather, which is a term that was coined in the Obama administration and further exacerbated 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's referenced in the actual lease that operators sign as lessees. You're required as a lessee, on any lease, to be jointly and severally liable for all the decommission assets, or liabilities on the lease. If Exxon owned a property or Shell or Chevron or anybody owned a property, 20 years ago and had a lease interest, sold 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. The government never really needed these financial assurances. This was something that was done by these administrations to be punitive. Unfortunately, it sucked a few companies out of the Gulf. A few of our competitors are gone that weren't there anymore. 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 Carbon Group series is taking. We applaud them greatly. Terrific. Great update, guys. Thank you, sir. Again, if you have a question, please press star and then one. Our next question comes from Jeff Robertson with Water Tower Research. Please go ahead. Thank you. Good morning. Tracy, can you talk about the depth of inventory that W&T has, for recompletions and workovers that help you maintain or offset natural declines? I'll do that. I'll do better than that. I'll defer that question to William Williford, who's our Chief Operating Officer. Hey. Hey, good morning, Jeff. Thanks for the question. Yeah, we've been spending a lot of time at our Mobile Bay asset, that's a gas asset, where we've been doing a lot of asset stimulations, and we have ongoing asset stimulation set up and approved to do in 2026. That's gonna help maintain our production decline in Mobile Bay. Also we got recompletes associated with some of our deepwater fields that were already set up and already on our reserve books, and we're just executing them based on where the production is in the current well. With that, we have several other opportunities, both on the workovers and recompletes similar to that allows us to not only maintain the current Production decline, flatten it out, but also increase it. That's why you see an increase year-over-year of our production based on in 2026 guidance versus what you see in 2025. With respect to the regulatory environment that Derrick asked about, Tracy, do any of the proposed changes or do the proposed changes have an effect on what is attractive to W&T in the acquisition market and the valuations of assets? I'm sorry, I didn't hear all of that question. Would you repeat it again, please? Sure. With respect to the regulatory changes that you see on the horizon, how does that affect, if any, the type of acquisitions that make sense for W&T to look at and potentially the valuations of properties in the Gulf? Yeah, sure. Well, you know, one of the things that I think that you'll see is as a result in the change of regulatory requirements is fields will be allowed to produce longer, because you won't have to have these massive cash outlays or insurance outlays from a market that has shrunk a great deal. You won't have these massive cash and collateral requirements required by these companies to attempt to extort money from companies for their own purposes. We're involved in a lawsuit right now with some of the surety providers on an in rem trust basis. So that's one of the things that we've had to deal with as an industry. That takes away from the capital that's available to do actual work and drill wells and make improvements to leases. Thank you. If I could ask just one more. Tracy, when you think about the types of acquisitions that you wanna 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? Now, drilling upside is a nebulous. Of course, that's always the highest risk, asset class or potential asset class. You never really know what you're gonna find until you put a hole in the ground to investigate it. No, I don't think that changes the outlook. Most people don't think about additional drilling assets as primary in the consideration unless you've already made a discovery and you're drilling on the fringes of that discovery. So I think that, you know. Well, I know this is the largest basin by area in the U.S., and it's the second-largest by producing assets. We've been able to make a pretty good living out over the last 40 years and increase the values for shareholders and all of our contractors and everybody else. It's 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. Thank you. Thank you. The next comes from Derrick Whitfield with Texas Capital. Please go ahead. Hey, guys. Thanks for allowing me to ask additional questions. Sure. 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? That's a pretty tough comprehensive question, Derrick. I'm not sure I have all the answers for your questions there right now as a sum total. You know, what we don't do in the U.S. is we don't 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're not allowed to do that. That's the bigger difference that's hard to quantify. We do see that as value, and we've seen that 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're fortunate in this basin to have mother nature giving us a helping hand, so to speak. Tracy, maybe on that point, if I'm looking at slide 16 of your new presentation, the way that I'm reading that is that in your 2P bookings, you effectively don't need to drill any new wells, and you have the probable outcome of receiving additional recovery, thereby get an increase in the longevity of the asset base without new development capital being spent. Is that a fair depiction? That's very fair. Derrick, I get a little bit nervous about quantifying some of these results because of you know we've had in the past administrations that that's been frowned on as an expression of 2P. Clearly, we book more cash and reserves over time as we realize that 2P part of our production stream. Traditionally, we think about 1P reserves as proved producing and proved underdeveloped and proved behind pipe. 2P as probable producing and probable behind pipe, probable undeveloped. We get a large portion, in fact, in that presentation that you referenced, it's about $750 million of additional cash flow without any CapEx. Hence no drilling, that comes through the wellbore in the form of cash and additional reserve bookings over time. A very effective tool that we find in the Gulf of Mexico to add value without having to make capital expenditures. Great update. Thanks for your time. Thank you, sir. This concludes our question and answer session. I would like to turn the conference back over to Tracy Krohn for any closing remarks. Thank you, operator. Really unbelievable times right now. You know, we're involved in a war in the Middle East that clearly demonstrates the point that things that affect us that we can't control are always geopolitical. Other than that, we have pretty good control over our destiny. Even with existing or former administrations, the oil and gas business is not gonna go away, fortunately. You know, in thinking about political challenges, it, you know, our business has always been challenging as a regulatory function. I don't try to belie that truth in anything other than the regulatory bodies, generally the people that work at these agencies have good intentions. Some of their political masters do not. We recognize that. I feel like with the current administration some of those barriers are coming down and that and rightfully so. We've been persecuted as an industry and even as individuals by certain administrations. I'll leave it with that and tell you that I think we'll have better news next quarter as well. Thank you very much, and we'll talk to you again soon. The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.