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Good morning, ladies and gentlemen, and welcome to the Talos Energy Inc. Fourth Quarter and Full Year 2025 Earnings Conference Call. At this time, all lines are in a listen-only mode. If at any time during this call you require immediate assistance, please press 0 for the operator. This call is being recorded today, 02/25/2026. I will now turn the call over to Clay P. Jeansonne, VP, Investor Relations. Please go ahead.

Thank you, operator. Good morning, everyone, and welcome to our fourth quarter and full year 2025 earnings conference call. Joining me today to discuss our results are Paul Goodfellow, President and Chief Executive Officer, and

Thank you, Clay. Good morning to everyone joining us on our call today. I would like to start by thanking the entire Talos team for their hard work dedication and unwavering commitment to safety and delivery of our business during 2025. The results we will discuss today are a direct result of their effort. First, we are pleased to report continued strong safety performance with no serious injuries in 2025, underscoring our steadfast commitment to the health and well-being of our employees and contractors. Additionally, our environmental stewardship remains a core focus with a spill rate significantly below industry averages, underscoring our commitment to protecting the communities and environment where we live and work. 2025 was the start of a transformation journey for Talos Energy Inc. The year was defined by a revamped strategy, operational excellence, and strong financial delivery supported by a new leadership team. High production, greater capital efficiency, and lower operating costs resulted in significant free cash flow generation, which led to meaningful return of capital via share repurchases. All of this was accomplished while navigating a weakening commodity price environment throughout the year. As we look ahead to 2026 and beyond, we intend to build on the momentum we have created, executing our strategy while balancing the inherently volatile business and long-cycle nature of offshore oil and gas. In June, we introduced a new corporate strategy. Our strategy is anchored on three core pillars built to deliver results now while also positioning Talos Energy Inc. for the medium and long term, and underpinned by a disciplined capital allocation framework. Since announcing this strategy, our team has been laser-focused on executing and building the foundation to be a leading pure-play offshore E&P company. Under the first pillar of the strategy, improving our business every day, the teams rose to the challenge to think creatively, and we realized approximately $72 million in free cash flow improvements in 2025, far exceeding our initial target of $25 million. These savings were generated through more than 80 initiatives spanning margin enhancement, capital efficiency, commercial opportunities, and organizational improvements. About half of that $72 million was a one-time benefit in 2025, while the other half is structural and recurring, which gives us solid momentum heading into 2026. The team has many initiatives in flight, and we look forward to updating you on our progress throughout the year. Our relentless focus on efficiency has strengthened our position as the low-cost E&P operator in the Gulf Of America, in addition to delivering top decile EBITDA margins across the sector. Over the past three years, while the industry trend for E&Ps in the Gulf Of America has been an increased cost structure, Talos Energy Inc.’s proactive management of its cost base and increasing production have resulted in a reduction in operating cost on a unit basis. In fact, for 2025, our operating costs are on average 30% lower than the offshore peer group average. This advantaged cost structure has helped us to generate top decile EBITDA margins in the E&P sector for 2025. These achievements reflect disciplined execution and a culture committed to continuous improvement. Within the second pillar of our strategy, growing production and profitability, we continue to advance organic growth throughout the year, achieving first production at Sunspear and Katmai West number two. Our teams continue to deliver outstanding operational results at our Katmai field, where production flows through three subsea completions tied back to the Talos Energy Inc.-owned Tarantula facility. Katmai West number one continues to be a standout performer, ranking among the top 10 producing wells in the Gulf Of America. In mid-2025, Tarantula’s gross processing capacity was expanded to 35,000 barrels of oil equivalent per day to accommodate higher volumes following the success of the Katmai West number two well. Most recently, targeted debottlenecking efforts have boosted throughput to approximately 38,000 barrels of oil equivalent per day. These recent debottlenecking efforts were achieved with minimal capital outlay, reflecting the team’s commitment to grow production and profitability and their ability to unlock value through creativity and ingenuity. Looking ahead, we expect production from the Katmai field to remain essentially flat throughout 2027. The production profile helps underscore our overall base decline rate in the mid to high teens, which is another differentiator for Talos Energy Inc. relative to onshore peers. We are also excited about the Katmai North prospect, which provides potential exploration upside to the field. The team continues to mature this prospect with new seismic data, and the recent blocks we strategically acquired in the lease sale near our Katmai complex further enhanced our prospectivity in the area. Under the third pillar, we continue to build a long-lived scale portfolio that supports long-term sustainable growth. The discovery of the Daenerys exploration prospect marks the potential for a significant addition to our resource base with appraisal activities set to begin in 2026. Additionally, Talos Energy Inc. was pleased to be named the apparent high bidder on 11 new leases, with eight being awarded to date, totaling approximately $15 million in last December’s big beautiful lease sale. These leases surround our Daenerys discovery, and new positions in the Neptune and Katmai areas further leverage our existing infrastructure. We significantly expanded our resource potential, adding eight prospects, some of which span multiple blocks with more than 300 million barrels of gross unrisked resource potential across amplitude-supported Miocene and Wilcox opportunities. This represents approximately two times our current proved reserve base. We increased our working interest in the Beacon-operated Monument project 21% to roughly 30%. Monument is a large Wilcox discovery expected to come online at the end of this year and is expected to provide a durable production profile in 2027 and beyond. Talos Energy Inc. continues to invest in state-of-the-art seismic technology and proprietary reprocessing supported by a broad multi-client seismic footprint across the Gulf Of America. Our modern imaging capabilities and technical expertise help de-risk prospects and improve success rates expected every year, which positions us well ahead of two federal Gulf Of America lease sales over the next decade. Now let me highlight the key projects we have planned for 2026. Talos Energy Inc. successfully drilled the Cardona well in late 2025, delivering the project under budget and ahead of schedule. Production commenced earlier this year with the well flowing to the Talos Energy Inc.-owned Pompano facility. Talos Energy Inc. also recently drilled the CPN well ahead of schedule with first production expected in 2026. The team continues to advance the Talos Energy Inc.-operated Brutus rig reactivation program with the first of four wells scheduled to begin drilling in quarter two and the remaining wells to follow in sequence. We expect that the majority of drilling activities will be completed this year and anticipate bringing three wells online by year end with the fourth well online in early 2027. The Monument Project operated by Beacon Offshore continues to advance towards a March spud, with the rig planned to operate continuously throughout the year. Both wells are expected to be completed in 2026, yielding first oil by year end. Beacon plans to develop it as a subsea tieback to the Shenandoah production facility in Walker Ridge, and the project has firm committed capacity of 20,000 barrels of oil per day. While 2026 is a year marked by investment and development in the project, we expect 2027 to benefit from a full year of production. The Daenerys discovery was a significant highlight in 2025. As we previously stated, the discovery well was temporarily suspended to preserve its future utility pending further appraisal. We plan to spud the appraisal well late in 2026. The appraisal program is designed to test the northern part of the prospect and is strategically planned to penetrate multiple prospective intervals, enabling a thorough assessment of the reservoir. Additionally, the well has been engineered to accommodate multiple future sidetracks, enabling further appraisal and development. We expect results in the 2025 was a great year where we accomplished tremendous results all across the business. In 2026, we will continue to execute safely and will remain guided by the disciplined capital allocation framework that underpins our strategy. We will stay true to our three strategic pillars as we advance the business, create long-term value, and achieve our clear vision for Talos Energy Inc. to become a leading pure-play offshore E&P. Now I would like to turn it over to

First, I will recap 2025 through the lens of our strategic framework, then I will discuss some fourth quarter specifics and end with the 2026 outlook before handing it over for Q&A. Underpinning our execution of the three strategic pillars, which Paul discussed, is a disciplined capital allocation framework designed to deliver strong financial outcomes. In 2025, that is exactly what Talos Energy Inc. did. We invested about $500 million of exploration and development capital and produced an average of 95,000 barrels of oil equivalent per day. This generated approximately $1.2 billion in adjusted EBITDA and $418 million of adjusted free cash flow, despite a steady decline in oil prices throughout the year. Our framework calls for returning up to 50% of annual free cash flow to shareholders, and that is what we did. Since announcing our capital allocation framework in Q2 of last year, we have returned approximately 44% of adjusted free cash flow to shareholders through share repurchases. Throughout 2025, we reduced our outstanding share count by about 7%, demonstrating consistent follow-through and clear focus on enhancing per share value. In the fourth quarter, we produced an average of 89 barrels of oil equivalent per day, including 65,000 barrels of oil per day. Fourth quarter volumes were impacted by about 3,000 barrels of oil equivalent per day due to the shut-in of our Genovese well following a failure of its surface-controlled subsurface safety valve. We are working diligently to accelerate the delivery of an insert safety valve, and we expect Genovese to return to production in 2026. Our fourth quarter oil cut was slightly higher than our 2025 average, and we expect that higher oil cut to continue through 2026, which will support our peer-leading margins. Another critical element of our financial framework is maintaining a strong balance sheet. We ended the year with low leverage of 0.7 times and approximately $1 billion in total liquidity, including a year-over-year increase in cash on hand. We have no near-term debt maturities, and recently we extended our credit facility to 2030 while reaffirming our borrowing base at $700 million. We believe this financial strength positions Talos Energy Inc. to navigate commodity cycles and support the strategic growth elements of pillars two and three. For example, last year we increased our working interest in the high-value Monument prospect and also increased our potential inventory with additional leases acquired in the big beautiful lease sale in December, as Paul mentioned. We believe we are well positioned to continue strengthening our portfolio within the Gulf Of America as well as in other conventional basins. Now I want to touch briefly on our year-end reserves. Talos Energy Inc.’s proved reserves were 175 million barrels of oil equivalent, of which approximately 75% is oil. The PV-10 of our proved reserves was approximately $3.2 billion, which is calculated at year-end SEC pricing. We also believe that Talos Energy Inc. has significant value beyond our proved reserves with estimated probable reserves of 103 million barrels, adding an additional PV-10 of $2.3 billion at year-end SEC prices, equating to approximately $5.5 billion in 2P value. Our reserve replacement ratio over a trailing three-year period is approximately 140% of Talos Energy Inc.’s production. During the fourth quarter, we recorded a non-cash impairment of $170 million related to the full cost ceiling test under the SEC guidelines. As a reminder, this test primarily compares the net capitalized cost of our oil and gas properties to the present value of future net cash flows from our proved reserves using trailing twelve-month pricing. Next, let me share a quick overview of our hedge positions. We view hedging as a risk management tool to help stabilize cash flow in a downside scenario while also maintaining attractive exposure to higher oil prices. For the first quarter 2026, we have hedged approximately 29,000 barrels of oil per day with a floor price of approximately $63 per barrel. That represents approximately 47% of our expected first quarter oil production at the midpoint of guidance. And for the year, we have hedged roughly 23,000 barrels of oil per day representing approximately 36% of our expected annual oil production at the midpoint of guidance, with floors above $61 per barrel. Turning to guidance, we expect our 2026 capital expenditures, excluding P&A, to range between $500 million and $550 million. We expect to focus on low-breakeven, high-margin oil projects with a balanced allocation across infrastructure-led development, exploration, and appraisal. Approximately 60% of the total CapEx is allocated towards Talos Energy Inc.-operated projects, while about 40% is allocated to non-operated projects. Our non-op spend is higher year-over-year, driven primarily by increased spending on the Beacon-operated Monument project. As we invest for the future and advance our strategy to build a long-lived scaled portfolio, approximately 10% of our 2026 budget is allocated to exploration, which includes the Daenerys appraisal well. Talos Energy Inc. also plans to allocate $100 to $130 million of capital towards P&A, similar to 2025 levels. We remain committed to meeting our obligations while continuing to pursue opportunities to optimize and more strategically execute these projects. In 2026, we expect production to average between 85,000 to 90,000 barrels of oil equivalent per day and 62,000 to 66,000 barrels of oil per day. As I mentioned, oil as a percentage of total production in 2026 is expected to increase a couple percentage points year-over-year to approximately 73%. Every year, we account for a few items in our production guidance that are unique to offshore operators. Our approach to 2026 guidance is consistent. For example, we have planned maintenance projects throughout the year designed to ensure safe operations, high uptime, and lower unit operating costs for the life of those assets, but these activities reduce our production while they occur. We estimate planned downtime will impact annual production by 6,000 barrels of oil equivalent per day, which includes the annual impact of approximately 2,000 barrels of oil equivalent per day from the Genovese well, which will be shut in for the first half of the year. We also account for weather-related downtime such as hurricanes, in addition to an estimate of unplanned downtime associated with third-party facilities and pipelines. We have included a contingency of an aggregate 4,000 barrels of oil equivalent per day for these unplanned downtime and weather-related factors into our 2026 guidance, consistent with last year’s approach. Two important items to note. First, when normalizing for weather and deferred production at Genovese, our 2026 oil guidance would have been higher year-over-year. Additionally, we expect our year-end 2026 exit rate to be higher than our 2025 year-end exit rate due to the timing of new projects coming online and the return of the Genovese well in the second half of the year. Additional guidance details can be found in our presentation posted on our website. To wrap up, 2025 was a phenomenal operational and financial year for Talos Energy Inc., and we are excited to build upon this success in 2026. We believe our vision, strategy, and strong financial delivery combine for an exciting value proposition to investors. We will now open for questions.

Thank you. Please go ahead. Your first question comes from Greta Drefke from Goldman Sachs.

Good morning all, and thank you for taking my questions. My first is just on the Monument project this year. Can you speak a little bit more about the key next operational steps for the project and the path to first oil by 2026? You mentioned March spud for the project. Is that spud timing just for the first well or for both of the wells?

Good. Thanks, Greta. We expect Beacon to mobilize the rig, as we said, in March. They will have one rig working on the opportunity, and so they will drill both wells on a back-to-back basis and then complete the wells, which is why we expect both wells to be completed by the end of the year. The plan that we have at the moment is a continuous operation starting in March.

Great. Thank you. And then just my second question is on the safety valve issues you experienced as part of the fourth quarter. Can you speak a little bit more about the next operational steps of remediation of the valve at Genovese? How long do you expect it will take to receive the equipment you need, and how much time would it take to procure or send a rig over to complete the fix?

Yeah. Thanks, Greta. Let me maybe go back. We operate or have interest in about 120 subsea wells in the Gulf Of America, and so this is a fairly isolated incident. This well has been on production since 2018. It came as part of Fieldwood, and it has produced about 12 million barrels so far. The failure we have identified is a piston failure that meant that the flapper was closing. Importantly, there was no leak or environmental incident as a result of that. The teams have worked incredibly hard to not only identify the leak and the cause, but then to pull a remediation plan together, which, of course, means getting access to a vessel and access to the right type of equipment. What we are choosing to do here is to run an insert safety valve off an intervention vessel versus pulling and replacing the completion with a drill rig. We expect that to take place in the early part of the second half of the year. It is important to understand that whilst we operate the well, we do not operate the facility, and therefore we have to align timing with the operator of the facility. This well is tied back to the Nakika facility, and we are working very cooperatively with the operator of Nakika to line that up. Our plan is to bring an intervention vessel in to run an insert safety valve and to have the well back online in the early part of the second half of the year. It is also important to note that this failure, as disappointing as it was, is very different from the issue we had with a safety valve at Sunspear earlier in 2025. That happened during the completion activities. It was actually due to some proppant during flowback becoming embedded in the flapper, causing that flapper not to seal. In that case, we were on location, we had a rig under contract, and the best path and the only path there was to pull the completion and totally replace it, which is what we did, and we have seen great production and stability from that well ever since it came online. I hope that gives you both the color and the context, Greta.

Thank you very much.

Your next question comes from Timothy A. Rezvan from KeyBanc Capital Markets. Please go ahead.

Good morning, folks. Thank you for taking our questions. As a start, if you can give us a little more detail on next steps at Daenerys. You mentioned late 2026 as the timing of appraisal results. You operated much quicker than expected with your first discovery well, so do not know if you could clarify what late 2026 means. And then if we do get positive appraisal results, I know you have to look at the results to get next steps, but how could things play out if things continue to trend positively there? Thanks.

Yeah. Thanks, Tim. We expect to spud the well late in the second quarter. We have scoped the well, as we mentioned in our comments, in a way to give ourselves the maximum appraisal information in that secondary block, including the ability to have future utility of the well in terms of future sidetracks. We would expect that the well would be drilled and evaluated as we get to the end of the third quarter or start of the fourth quarter, and then it is a matter of exactly, as you said, what is the information and what does that then lead to in terms of a path forward. As we have always said, in a successful case where it looks like Daenerys may be a stand-alone, then we have already started the design basis of what that would look like. It may be less optimistic where it is maybe more of a tieback. We have also started looking at the optionality for that, and so we are working those in parallel. But it is just too early, Tim, to say in terms of exactly what the timeline would be. We will continue to update you throughout the year as we get back onto that well, execute, and get information. I would note, of course, that given we will be executing that well through the summer months, there is the risk of weather impact in terms of a delay, but that is always a risk within the Gulf.

Okay. Okay. I appreciate the context. I guess we will stay tuned on that. Then as a second question, Paul, you are almost at your one-year anniversary of joining. I would like to go a little bigger picture here. The share price was about 9. I know it is selling off today on Genovese, but still, it has been pretty strong financial and operational traction overall. You did not take this job, I am assuming, to run a sort of maintenance program. At some point, Talos Energy Inc. needs to be a growth company to get more relevance. Can you just talk about—you hit at 2027 organic growth opportunities—as you think medium term, your inclination or the need to grow the business to get more scale? And where I am going, this organic growth coming, does that preclude you from seeking inorganic growth opportunities? Just kind of curious—I know it is a broad question—on the lay of the land from here after a year in the role. Thanks.

Yeah. Thanks, Tim. I think it is described very well in the strategy that we laid out in June, and our focus has been on rigorous execution of the strategy. Now, clearly, the near-term actions are always more visible, and I am incredibly proud of the work that the teams have done to drive that culture of improvement and improving our business each and every day, as that gives us the ability to think more mid and long term. As we have spoken about in terms of the second and third pillars, we are actively working those. You have seen us be very active in the, let us say, organic space in terms of lease sale activity. We actually started looking at that in the middle of last year with seismic that we, or further seismic that we, acquired and interpreted that informed what we wanted to do in the lease sale. The fact that we brought in roughly 300 million barrels of gross unrisked resource that is operated, I think, is an important point along the journey. Clearly, as we have always said, we will look at continued bolt-on, but also inorganic activity outside the Gulf Of America, which fits into more of that pillar three that we have spoken about. That work continues to be undertaken and executed, but within the very disciplined capital allocation framework that we have laid out. We are not going to look to build the portfolio inorganically just to get bigger. We will look to do it to get better, and therefore any deal that we do will need to absolutely fit within the capital framework that we have. We also set an incredibly high bar in terms of the risk profile of projects, making sure that it ties into the core that we have—subsurface and operational skills—and that it clearly fits strategically where our skill set is. I am very pleased with where we are, as you say, almost a year into my tenure, with a great team here that we have amassed that has phenomenal breadth of industry experience I think is being brought to bear into not just thinking about how we drive culture, but how we drive and shape Talos Energy Inc. of the future.

I appreciate the insight. Thank you.

Your next question comes from Paul Diamond from Citi. Please go ahead.

Thank you. Good morning all. Thanks for taking the call. Just wanted to touch quickly on the Tarantula facility. You talked about flow-through increasing up to 38 with relatively low capital intensity debottlenecking. I guess, question being, how much more meat is on that bone there, kind of extrapolatable? And talk to other assets—like, is that a process transferable to other assets, or is this more just having to do with Tarantula?

Yeah. Thanks, Paul. The first thing to say is when we talk about improving our business each and every day, what Will and John Spath and the team have done at Tarantula embodies that and is a real visible example. As you know, we expanded the nameplate capacity of Tarantula in 2025 to take account of the Katmai West number two well up to 35,000 barrels a day. What the team has then done—as they do on every asset and opportunity—is really look for where the limiting factors are and can we remove those limiting factors to eke a few more barrels of continued consistent throughput through the facility. That is what Will and the team have done at Tarantula where they have taken that from 35,000 barrels a day to roughly 38,000 barrels a day. To use your words, I think that bone is pretty clean, and I do not think you will see any more optimization gains from Tarantula. We now shift our attention to more of the growth side in terms of looking at Katmai North, which is a potential opportunity for us as we come into 2027, and, dependent on the outcome of that and, of course, other strategic leases that we have just taken in the big beautiful lease sale, how we should prosecute those will then determine the next step of expansion potentially at Tarantula that will be more capital intensive and will most likely include the expansion of the pipeline connection that we have from the facility. Now, the second part of your question in terms of how transferable is what the teams are doing at Tarantula, I would say it is absolutely transferable, and in fact you see that working in practice today. The approach of can we get more production and can we get more reliable production is something that has underpinned part of the tremendous results that the team has delivered in terms of improving each and every day. We have seen it, for example, in terms of gas lift optimization studies that we have done across the totality of the portfolio. We have seen it through putting a dedicated flow assurance team together to really make sure that we are optimizing flow assurance. Whilst you may not see a facility expansion where we are limited by facilities relative to wells—which is a specific challenge at Tarantula—the idea of optimizing and increasing throughput is something that the teams are doing on every facility that we operate, Paul.

Understood. I appreciate that. And just circling back a little bit to the 11 leases you talked about with the big beautiful auction. Can you provide a rough expectation of a timeline on those going forward and where they fit in the larger development program and from a priority perspective?

Yeah. Thanks, Paul. The criteria with which we looked at what leases to go and bid on were very similar to the strategic frame that we have, which is it has to be complementary to the skill set that we have. There are key plays we want to exploit and explore. We wanted to look for prospectivity that raised the overall average size of prospects that we have as well as adding material potential volume to the portfolio, but we wanted to do that in a way that we could take those opportunities through to competing for capital in a fairly short cycle. The timeline that we are generally working on—all the teams are working on—is from lease award, which, of course, once we are named the apparent high bidder, you then have to go through the process of formally awarding those leases. As we mentioned, we have had eight of the 11 formally awarded as of today. From the point of lease award, we are looking at roughly plus or minus a year or so in terms of having an opportunity ready to compete on the drill schedule. I think we would be looking, as we build the 2027 capital plan, to be bringing those opportunities forward to compete for capital. What is also a really important point is, if you take it back a step in terms of from the ideation, getting the seismic, interpreting the seismic, going for the lease—that whole process up until being ready to compete on the drill schedule is probably somewhere less than two years, which I think is a significant achievement and toward the upper end of the norms within the industry.

Understood. Appreciate the time. I will wait back. Thanks, Paul.

Your next question comes from Michael Stephen Scialla from Stephens. Please go ahead.

Hi, good morning. Paul, the Cardona and CPN were both drilled ahead of schedule and under budget. I guess Cardona has been online a little bit now. Can you say anything about the production expectations for those two wells? Maybe how Cardona compares to what you anticipated and what you expect from CPN?

Yeah. I think the easiest comment to say is both of those are in line with the expectations that we had. Again, both were executed very well. The CPN well clearly needs a tie-in, and so the time for that should take place, and that well should come online in the second half of the year into the third quarter. Based on the flowback data we have, we are very pleased with that well and confident that it will be at the upper end of the expectation range that we have. Just to tie back to a point that

Wanted to ask about the Katmai North. You said you have got new seismic data there that is maturing. I wanted to see what—I think at one point you had said that Greater Katmai area, the resource there, could be maybe double what the Katmai one and two suggested is right now. So I wanted to see if that is still the case or what the potential resource looks like with the Katmai North and what the timing of testing that prospect looks like.

Yeah, Michael. I think we have said, and there is no real change, that Katmai North—assuming it comes successfully through the seismic interpretation process—will compete for capital in 2027. We are still extremely encouraged by the greater Katmai area, which is why we took more leases in the recent lease sale. We would see at least the resource size that we have mentioned before, but we will update you as we do that work on those opportunities as we go throughout the year.

Sounds good. Thank you, Paul.

Thank you, Michael.

Your next question comes from Nathaniel Pendleton from Texas Capital. Please go ahead.

Good morning. On Slide 14, you mentioned investing in state-of-the-art seismic and proprietary—can you talk about those investments? And have there been any tangible results from those campaigns yet?

Yes. Thanks, Nate. The first tangible results in terms of first step, of course, is the lease sale success that we have just had. The areas that we were interested in actually went through advanced reprocessing, and we will continue to do that in other areas that we have an interest in. The other thing that is important is our use of OBN seismic, where we actually used that to pick the Katmai two West well, also used that on the current Brutus redevelopment program. We believe that seismic data, advanced interpretation, and grounding our decisions in the fundamentals of reservoir engineering and geology is absolutely critical to the success that we have had and will continue to have here at Talos Energy Inc.

Got it. Thank you. As my follow-up, maybe regarding the capital program for next year, is that 10% exploration CapEx target what you see as a good long-term run rate? And how should we think about your preferred long-term allocation of operated versus non-operated activity given the dominance of Monument in the coming year?

That is a short-term view in terms of it just happens to be the big development project that we have at the moment is operated by Beacon, and therefore there will be a higher proportion of non-operated capital in the Gulf Of America. I think our strength actually comes from being an operator. We show that in terms of the leading EBITDA margin results that we have, the operating scale and low cost that we have, and our ability to drill, complete, and tie in a very capital-efficient way. We are very happy to partner with companies like Beacon and others—it is a key part of our portfolio—but we bring a real strength from an operating point of view. We will continue to look for operating opportunities, but we will never turn away a non-operated opportunity where we see value and where we can help the operator improve that value. In terms of do we have a target for exploration spend, the answer is no. Ten percent happens to be where we are this year. I would expect as we get into 2027, given the fact that those lease sale opportunities are maturing through to compete for capital, you could see something slightly higher than that. But we will bring it always back to the capital allocation framework that we have, which talks about investing in high-margin production, making sure that we maintain the strength of the balance sheet, returning cash to shareholders, and then investing in accretive growth. Clearly, organic exploration falls into that fourth bucket.

Understood. Thanks for taking my questions.

And our last question comes from Noel Augustus Parks from Tuohy Brothers. Please go ahead.

Hi. Good morning. I wanted to ask a bit about the service environment. I just wonder if some of the optimism we have been hearing from the offshore drillers around 2027 and maybe even heading into 2028—there is sounding like there is some possibility of maybe producers all crowding through the same door at the same time as far as getting access to rigs. I just wondered how much that might be figuring in your planning these days.

We always look at where we are within the market. Clearly, we plan many years ahead in terms of what slot opportunity sets could be, making sure that we are advancing the procurement strategy that we have along with the technical strategies such that when we are ready to take an investment decision, we have the supply chain lined up, and that is the approach that we will continue to take. Many things, of course, can change the outlook that any company has—certainly commodity price is one of those. As I mentioned before, our focus from a commodity price point of view is to make sure that we build and think about projects that have the lowest breakeven cost possible. That is what we are doing for 2026: driving forward projects that have breakevens in the $30 to $40 range. That gives us the resilience that we need. We clearly see opportunities in terms of capacity in the marketplace as we go into 2026 and through to 2027, but, of course, for us it is important to partner with the right type of providers that share the ethos around safety, environmental stewardship, and ultimately performance. I think you have seen us demonstrate that over the last twelve months or so in the partnership that we have had with the West Vela.

Great. Thanks. And I was wondering about the company’s historical strategy of favoring assets that feature or include underutilized infrastructure. I am just wondering what you are seeing in the sort of market for legacy infrastructure out there. As there is more capital heading to the deepwater, are other producers like-minded in terms of the strategic value of using current infrastructure as a starting point? Or is that sort of a finer point, say, for new or returning entrants who are looking to get a Gulf program rolling or ramped up?

Thank you. I would offer maybe a couple of thoughts. We clearly see more interest in the deepwater in the Gulf Of America. I think I mentioned this when I first came into the role here in terms of, I believe—and we believe—that the low carbon intensity, high-margin deepwater barrel is vitally important in terms of supplying the energy that the country and the world need, and I think it will be here for many years and decades to come. I do think that the technical barrier to entry is maybe higher than some think. The ability to operate in deep water needs key skills and capabilities, which we have got, and therefore that leads to the ability to actually get access to infrastructure and manage infrastructure. Clearly, the infrastructure element will always be a consideration for ourselves as we think about what opportunities to drive within the deepwater, be it in the Gulf Of America or elsewhere. I cannot really comment on how others think about it, but that is certainly the lens through which we look at it.

Okay. Great. Thanks a lot.

This is all the time we have for today’s questions. I will now turn the call back over to Paul for closing remarks.

Thank you, Julie, and thank you all for joining today and for your interest in Talos Energy Inc. I would like to close by recognizing again our dedicated team and their commitment to providing safe, reliable, and responsive energy that really is vital to power our everyday lives and the world. We look forward to updating you as we execute the plans we have laid out today throughout the year. Thank you.