Good morning, ladies and gentlemen, and welcome to the Talos Energy First Quarter 2024 Earnings Call. This call is being recorded on Tuesday, May 7, 2024. And I would now like to turn the conference over to Clay Johnson. Thank you. Please go ahead.

Thank you, operator. Good morning, everyone, and welcome to our first quarter 2024 earnings conference call. Joining me today to discuss our results are Tim Duncan, President and Chief Executive Officer; Sergio Maiworm, Executive Vice President and Chief Financial Officer. For our prepared remarks, we will refer to our first quarter 2024 earnings slide presentation which is available for viewing and downloading on Talos' website. Starting on Slide 2, cautionary statements. I'd like to remind you that our remarks will include forward-looking statements. Actual results may differ materially from those contemplated by these forward-looking statements. Factors that could cause these results to differ materially are set forth in yesterday's press release and our Form 10-Q for the period ending March 31, 2024, filed yesterday with the SEC. Forward-looking statements are based on assumptions as of today, and we undertake no obligation to update these statements as a result of new information or future events. During this call, we may present GAAP and non-GAAP financial measures. A reconciliation of GAAP to non-GAAP measures is included in yesterday's press release, which was filed with the SEC and is available on our website. And now I'd like to turn the call over to Tim.

Thank you, Clay, and welcome aboard. We're going to start this presentation on Slide 3. We're going to discuss how we've repositioned ourselves over the last year with the last two M&A deals. We're the fourth largest acreage holder in the Gulf of Mexico, and we're the fifth largest operator in the Gulf of Mexico. And we have two tenets to our strategy that we think are important. One, we're focused on oil-weighted assets. And two, we think it's critically important that we operate our deepwater infrastructure. It allows us to focus our prospect inventory around this infrastructure and allows us to shorten our cycle times when we think about drilling these wells and getting them with first oil. Let's go to Slide 4 and talk about what might have been one of our busiest quarters in the company's history. We ended the year by bringing on Venice and Lime Rock ahead of schedule and with sustained rates at over 18,000 barrels equivalent a day. And in January, we announced the QuarterNorth transaction, our second transaction of over $1 billion in the last year, adding important scale to our business. Immediately after that transaction, we announced a couple of capital markets transactions, including lowering the cost of capital of our debt by refinancing our high-yield notes. We were able to close the QuarterNorth transaction within 45 days, which helps us accelerate our synergies, and we were also able to update our financial guidance, increasing our production guidance. And then later, we also updated our debt guidance from $400 million to $550 million of debt repayments for the year. Also, within the quarter, we announced the divestiture of our CCS business to TotalEnergies. I'll speak more about the importance of that transaction on the next slide. So on Page 5. We went through a lot of these highlights on Page 4, but let me focus on a couple of bullets on each side of this page. So first, on the left side of the page, we had record production in the first quarter at the high end of our guidance. And you're going to see this go up tremendously in the second quarter, and Sergio will talk about that later in the presentation. Some of these other bullets I just discussed, but let me focus a little bit on the sale of TLCS business. We're bullish about what CCS can be long term. But we did notice that emissions reductions were slowing down within these facilities and the capital requirements were going up. So we thought the right move for us was to transact on this business; we got a solid return over 2x our money and immediately took those proceeds and accelerated our debt repayment. As we get to the right side of the page and focus on what we're trying to do from here, we think it's important to continue to remind the market that even though we're projecting 35% to 40% year-over-year increases to our total corporate production base, we're doing that with a lower capital program relative to our Talos legacy business last year. And what Sergio is going to talk about later in the presentation is how that impacts the free cash flow yield of our business. I'm also going to talk about in this presentation why we're so excited to get this drilling program going, particularly in the Katmai field, as we think it's an enormous catalyst for our business. As we turn to Page 6, let's hit some of the highlights of the quarter. We have 79,600 barrels equivalent a day, again, on the high end of our expectations for the quarter. And you'll see that number continue to go up as we own these QuarterNorth assets in full now for the rest of the year. We're very much oil and liquids weighted. We had upstream EBITDA of $268 million for the quarter, which has a netback margin of $42 per BOE. Now, that doesn't include workovers, which are heavy in the first quarter but will taper off through the rest of the year. Upstream CapEx was $112 million, and upstream adjusted free cash flow, not inclusive of some expenses that we still had in the first quarter related to TLCS, was $78 million. Now the sale of that TLCS business that I mentioned earlier allowed us to accelerate our debt reduction. And so we had debt repayments of $225 million for the quarter that also allowed us to reach our leverage goal of 1x within the quarter, and so we should lower that continually throughout the year. As we move to Slide 7, one of the more important things about closing the QuarterNorth transaction as quickly as we were able to do is it allows us to control two things: one, we can control the assets operationally, which is important as we plan the Katmai wells that I'm going to discuss later in the slide deck. The other thing is we can get to work on the synergies, and in the first quarter, we immediately were able to work on synergies related to G&A, including personnel and IT. In the second quarter, we're going to work on the insurance-related synergies, and then you will also see some synergies that flow through operating costs but even so far since we closed the transaction, we were able to realize what will amount to $20 million of run rate synergies in the first quarter on our way to achieving $30 million by the end of the year and $55 million as we get into 2025. As we discuss the second quarter, it's worth noting the connection to the first quarter. In the second quarter, we will perform the HP-1 dry-dock in our Phoenix field, which includes our Tornado asset. We initially expected to be a few days late in the first quarter, but that was ultimately delayed. This will result in a clear 55 days in the second quarter. We anticipate an impact of 5,000 to 6,000 barrels equivalent per day during this period. Sergio will cover the broader values for the second quarter. It's important to remember that this is a dynamically positioned vessel that supports production from Phoenix and Tornado, necessitating dry dock every 2.5 years. Let's go to Page 9 and talk about the recent lease sale. Now the sale occurred in the fourth quarter of 2023. But ultimately, we were awarded these blocks in the first quarter of 2024, and we were able to achieve 17 blocks with high bids. All were awarded. It adds up to 95,000 acres. But I think if I focus you on the map, it's important to play through how this fits our strategy that I referred to back on Page 3. So light blue is our seismic. Again, it covers most of the Gulf of Mexico. Dark blue is our acreage. I mentioned earlier, it's one of the biggest acreage positions in the Gulf of Mexico. And then those light blue dots are our facilities that we control and operate. If you look at the gold call-out boxes, these are the leases that we picked up in the lease sale: notice how they're peppered around those facilities. By owning and controlling and operating these facilities, it focuses our team on where we can develop inventory around these facilities. We think we've added 12 to 15 potential locations just in this last lease sale, growing our overall location count for the company. Let's go to Page 10 and talk about the drilling program for the year and how things are going. I mentioned Venice and Lime Rock at the beginning of the presentation. If you read the earnings release, you might have seen our reference to the Lobster Waterflood project. That was successful in the first quarter, and we expect to see that rate start to hit us in the third quarter and throughout 2024 and 2025. We had a stimulation campaign weighted in the first quarter, then we'll take a break and have another project in the third quarter. The Claiborne Sidetrack, which is non-op, was successful; we'll see that rate increase in the second quarter and really get full rate in the third quarter. Then we start our drilling campaign with the Katmai project, and I'm going to talk about that. Then the Daenerys project, which is a high-impact salt well. But ultimately, we're going to try to get into this year, and it could work into next year as well. Again, we have the Sunspear completion, which is important so we can see that production from that discovery of last year be available to us in the first half of next year. As I mentioned, on Page 11, we give you a little update on Venice and Lime Rock, and you can see it here. Again, the Ram Powell facility is a facility that we bought in 2018. We own 100% of that facility. It's an important host facility, not only for our drilling campaign, but it can be a host facility for third-party discoveries that might need to utilize the asset. What Lime Rock and Venice have always shown is really good execution on our strategy. These are locations that we identified after we bought the asset; you can see the impact on the right side of the page. Then you can see that we brought those wells online, and they're relatively flat still as we think about this 90 days later. Let's go to Page 12 and talk about the Greater Katmai area. I think it's important to note that this is a discovery, a subsalt discovery at 27,000 feet below the surface. The initial reservoir pressures were over 20,000 pounds. It's a big geological complex that we're still learning about today. It could have as many resources as 180 million to 200 million barrels. Although it's a fairly recent discovery, it's already produced 17 million barrels, and it's doing so at a facility constraint of 27,000 to 28,000 barrels equivalent a day that you can see on the right side of the chart. You'll notice in the first quarter, we had some planned downtime. Although that's frustrating, it's an important planned downtime because it lets us work on the facility. It also lets us collect critical information on the pressures that we see downhole. That's causing us to have more confidence in how we think this field will get developed. So let's continue the conversation around Katmai. I talked about the Katmai West #2 well and why we think it's so important. A lot is going on in the slide, but help us understand how we think about better defining and expanding the resource when you have a deepwater discovery like Katmai. If you go on the graphic on the left, we're showing you visually where the Katmai West #1 well was drilled geologically in the structure. On the right, we're trying to help you understand how that better defines the lowest oil, which defines our proved reserves. You have a 400-foot pay column that helps define proved reserves and better expand what the resource could be. You have to have a combination of good production data, good pressure data, and then ultimately another geological test. That next geological test is the Katmai West #2 well. We're going to extend the geological column, and with that information and the pressure data and production data, we will have a better understanding of whether the potential of 100 million barrels is available to us. We think this is a very important well; it's a great use of capital allocation.

Thank you, Tim, and good morning, everyone. Thank you for joining our call today. As Tim mentioned earlier in the call, we have increased our debt reduction target from $400 million to $550 million by the end of the year; also a couple of months ago, in our last earnings call, we guided the market to expect a leverage target at the end of the year of 1x or below, and we're actually able to achieve 1x at the end of the first quarter. So we're way ahead on our target there, and I expect the number to continue to go down as we make additional debt reductions throughout the year. At the closing of the QuarterNorth transaction, our debt stood at $1.8 billion, and that was a combination of $550 million drawn on our RBL and $1.25 billion in bonds. In the first quarter, a combination of cash flow generated by the business and the sale of TLCS allowed us to pay $225 million to achieve a debt balance at the end of the first quarter of $1.575 billion. We expect to continue to pay down debt throughout the year, and at year-end, we expect the revolver to be fully paid down. So another $325 million of debt reduction this year is expected. On Page 15, I wanted to highlight three metrics that show how compelling of a value opportunity Talos gives to investors. First, we have one of the highest oil content or highest oil exposures in the entirety of the E&P sector in the United States. Continuing from that, we also have one of the top margins in the business. This allows us to generate a tremendous amount of free cash flow that we don't believe is being recognized in our market cap now, which shows itself as one of the highest free cash flow yields in the entire E&P space. This includes every single E&P company above $1 billion of market cap, excluding the majors. So this includes all of the very large E&P companies as well. Talos is consistently a top decile performer on all of these metrics. On Page 16, I want to talk about our priorities for maximizing free cash flow and how we're going to utilize our free cash flow. First and foremost, we're laser-focused on delivering and executing our business plan. That is the main focus for 2024. As Tim mentioned, the QuarterNorth integration is well underway and going very well. We believe the QuarterNorth acquisition adds a significant amount of scale to the business as well as high-margin oil-weighted production for our portfolio. This, combined with our industry-leading netback margins that we talked about earlier and our streamlined capital program for 2024, puts us on a great path to deliver on that business plan this year. Regarding our full year guidance, we're reiterating our operational and financial guidance. We continue to expect average production for the year between 89,000 and 95,000 barrels of oil equivalent per day, and that is about 71% oil and about 80% liquids. As I mentioned previously, this includes a little less than 10 months of contribution from the QuarterNorth assets and expected downtime estimates for the HP-1 dry dock and Katmai facilities work, among others, and unplanned downtime for weather-related events and potential downstream events from us as well. In the second quarter production, we expect 93,000 to 96,000 barrels of oil equivalent per day and about 70% oil; this includes the expected planned downtime for the HP-1, which is roughly 5,000 to 6,000 barrels of oil equivalent per day. We also remain steadfast in our debt reduction goals, as we mentioned earlier, and we have increased that goal from $400 million to $550 million. Our capital investments for 2024 have a mix of development and exploration, and we believe that is the right mix to create the most value for shareholders in the long run. Lastly, M&A continues to be a pillar of our strategy, and we continue to actively seek further accretive M&A opportunities to accelerate our growth trajectory, deliver on our strategy, and create further value for shareholders.

Thanks, Sergio. Let's move to Page 17, which I think is a great wrap-up slide. We think we're one of the most important counterparties in the Gulf of Mexico. Sergio mentioned how we're thinking about M&A and certainly an important part of our strategy, but as I think about us as a counterparty, that includes business development activities, such as the JV we announced in the fourth quarter with Repsol. The other JV we announced with BP and Chevron are prospect swaps. We have partnerships with critical private companies in the Gulf of Mexico. It's important that we take on this leadership position for a strategy that's focused on offshore infrastructure. We've got a high-quality and stable asset base. When we have these deepwater discoveries and they come online and we bring on those new wells, it helps us better manage our base decline, which is around 20%. When these assets are flowing at full rate, they're flowing at over 105,000 barrels equivalent a day. We've modeled through the downtime, but the capacity of these assets is great. As Sergio talked about just in the last couple of slides, we think we have one of the highest EBITDA margins in the E&P space based on our oil exposure, and we think it's underappreciated the levered free cash flow yield that we're generating right now. We're committed to low leverage, and we've accelerated our debt reduction program. We anticipate getting as high as $550 million, and that's important because it fully pays off the RBL, which gives us flexibility for the future. We believe in the growth potential that we have. We talked in this presentation about the good work we did in the last lease sale, the drilling JVs we have actively ongoing, and the drilling program we have ongoing. So a lot of catalysts in the system that we're very proud of, and we're doing all of this while we continue to be committed to safety and sustainability. We’ve been putting out our ESG reports as one of the leaders in the Gulf of Mexico and how we think about sustainability. We'll continue to do that even though we don't own PLCS, we're committed to the idea of the ecosystem that we're involved in, and we're proud of our efforts to date. So with that, I'll hand it over for questions.

Your first question comes from the line of Tim Rezvan from KeyBanc Capital Markets.

I just want to start on Sergio's comments towards the end of the prepared script about actively seeking further M&A opportunities. Obviously, the integration has gone pretty well here. Just curious, Tim, can you kind of give updated thoughts on what you're seeing in the M&A landscape, both within the Gulf and outside it as you think about it. Oil's run here, but there's a lot of backwardation on the strip. So just curious kind of what you're seeing out there.

I think it’s maybe a little slower than where we were a year ago. We knew in the Gulf of Mexico, particularly, there were key private players. Ultimately, that was EnVen and QuarterNorth that we were focused on, and we knew they could bolster the business, so we're proud of how we executed those. There aren't those obvious candidates today, and so I think our focus has been really on execution, which we're proud for the first quarter. We're excited about the rest of the year. There are some tactical small things that we're thinking about when we think about our infrastructure and how to do things that are accretive to what we currently own tactically in the Gulf. There might be some activity outside the Gulf, but I would tell you that's a slower churn, and it's not where our focus is today. So probably a little slower on that front than maybe in the last couple of years where we knew what was coming. There's a little less knowing of what is coming, and that's fine. We've got a team that's focused on it. But I think it's more tactical; it's more business execution if I'm thinking about the near term.

Okay. I appreciate that. As my follow-up, you partially answered my question in your prepared comments saying that your goal is to have the credit facility paid off by the end of the year. So I'll follow up with something I asked last quarter. When you see leverage potentially getting below $1 billion, how do you think about maybe repurchases reentering the equation? Or what are the Board's thoughts? I know you don't want to put the cart in front of the horse. But you have line of sight on these leverage reduction targets. How are you thinking about using incremental free cash flow after that?

Look, it's a good question. I can tell you the Board's thoughts and our thoughts today are just to get that RBL paid off because I think it provides maximum liquidity and flexibility. Look, we still have a $50 million authorization under stock repurchases, and we can think about that. I do think we're hyper-focused on getting through the year and making sure that revolver is paid off. You can build up a little cash for some of these tactical ideas we have. I wouldn't hold back; right now it's harder to restart your own operating capital program, but we do see a lot of opportunities out there as people are thinking about high-grading their exploration and their drilling joint ventures and their drilling inventory. I don't think we would lose sight of if an opportunity came our way and we had cash available to invest in a new opportunity, we would consider that. So I think we're going to have multiple Board meetings throughout the course of the year. We're going to think about where we are in the schedule, how we think about some of those capital return policies against the opportunity set, and really what's the best decision that creates long-term value. Sometimes, if you have $25 million to deploy on a stock purchase versus an opportunity that comes our way that can generate a 30%, 40%, 50% rate of return, you have to think about each of those opportunities individually. So the near-term focus, again, is getting the RBL paid off; I think everything can be on the table once we accomplish our goal.

Your next question comes from the line of Subhasish Chandra from Benchmark.

Tim, could you discuss the production trajectory from now until the end of the year? In your March presentation, you mentioned a range of 105 to 110. You referred to 105 in your comments, but was that the baseline we are returning to? Can you elaborate on that? What should we expect as the exit rate for the year?

Yes. Thanks, Subhasish. Look, I think it's an important slide because what we're trying to talk about there is kind of unencumbered production. So when everything is running right, how do you start the concept around where you get to ultimately where we landed on guidance? In the last call, the first month, the assets combined, even before we close, were averaging 106 and before dry-dock dragging 105; there's a little downtime in there. There's always some downtime in the system. As we're doing rotating equipment and some other construction projects around these assets. From there, you're trying to plan out when this downtime can occur, what's in your control, what's not in your control. Obviously, for example, HP-1, the timing of when that vessel gets to dry dock is not in our control when we're waiting on something like clusters that they have to replace. We had some downtime as soon as we owned the assets in QuarterNorth around Katmai; we knew that downtime was important to help us set up what we're excited about in drilling that well. Now we're in the second quarter, we're going to have downtime in HP-1, some third-party downtime, downstream of our Pompano facility. These are small downtimes. You've got a facility like HP-1, where net to us, we're close to 9,000 barrels equivalent a day, or the Pompano facility where it's over 10,000 barrels equivalent a day. So they're chunky downtimes, but that's why we wanted to walk through that in that deck that's on the site as we laid out our guidance. Everything is on track. I think even the QuarterNorth assets for the quarter have been averaging well over 30,000 barrels equivalent a day, which we talked about when we bought those assets. All the assets are performing very well. This is really around the cadence of that downtime; some of that is in your control, and some of that could slip; we'll try to make sure we guide that every quarter. If we're not changing anything relative to the annual guidance, you can expect that to kind of tick up as we go throughout the year. Again, some of that is weather dependent as well. So look, I think as that ticks up, you can expect operating costs as a unit of production to go down. We're really happy with the first quarter. We had beats in production and EBITDA and CapEx and free cash flow; you should expect that to continue as we go throughout the year.

Okay. Got it. So is it fair to say the downtime is mostly or maybe entirely legacy assets and that we should be thinking?

Katmai was a significant contributor to the downtime in the first quarter, as illustrated in the graph I shared. We are very enthusiastic about that asset. During the downtime, while conducting some repairs and maintenance related to third-party pipeline issues, we implemented a few measures that increased production by 1,000 barrels a day at that facility. The downtime ultimately benefits these assets. In the second quarter, we expect the focus to be primarily on Talos legacy assets. Moving into the third quarter, we anticipate a blend of both asset types. It's important to note that we don't want to attribute performance solely to either asset set, as it's part of our overall business operations. We aim to be more open with you all and the market regarding how we approach production from offshore compared to onshore assets and how you should consider downtimes and weather impacts, starting from a clean run rate. This was the intention behind the slide in our previous presentation, and we will keep including it in future presentations.

Your next question comes from the line of Leo Mariani from ROTH MKM.

I wanted to talk a little bit more about Katmai #2. How do you kind of think about the potential risk associated with that well? I mean you guys basically expect it to kind of be incremental to production? Is it maybe just a matter of how much production and reserves it's going to potentially add? Maybe just can you give us a little more color on that?

You've got kind of what I would call operational risk, and then you've got broadly what's happening from the subsurface perspective, Leo. Operationally, the one thing that we tried to harp on here, without getting too nerdy about it, is we've got these bottom hole pressure gauges right there at the perforation. We know exactly what's happening when we flow a well. We know how that well is declining. When we shut in a well, we know how that pressure is building up. That helps us with the planning of a well. We kind of know exactly what we're entering into, and we've got better seismic data. We're going through a lot of reprocessing that we do all the time. We think we've got a good picture of the structure geologically. We've got a good handle on what's happening from a pressure environment. The team can design the well. The purpose of the well, though, is just to try to see what this feature looks like as we get further away from the current well. Certainly, nothing is guaranteed. You could go down there and learn something different than what you anticipate. We hope we're going to expand the geological column, and we're going to open up that geological structure, and by doing so, we have a chance to add a significant amount of reserves. That's where you get into the full upside picture. So if you can imagine, as we work with an auditor, we’re working with them to see how we think about proved, which is just the column that you found in the first well. How do we think about probables and possibles? All of that gets into that broader resource. Based on the data we have so far, there could be a meaningful resource there. You can wait and produce it; it'll take a while to convince everyone that resource has that full potential, or you can do a combination of producing, analyzing, and drilling for it. It makes sense for us to drill for it. This fits in that combination of probable and possible categories. More than 50%, more likely than not. We are at 27,000 feet. We’re going to have to go find out, but we're very optimistic about what we're doing this year on Katmai.

That was great, very thorough. I wanted to follow up on QuarterNorth and the synergies. You mentioned that you expect to reach about a $30 million run rate by the end of the year, up from the $20 million currently, with a full $55 million projected for next year. Is the $30 million for this year mainly from G&A savings and possibly some interest, with the additional operational efficiencies contributing to the extra 25% next year? I know you're discussing the possibility of reducing some operational costs as the year progresses. I’d like to get more details on these figures.

Leo, this is Sergio. Happy to answer that. In 2024, the majority of those synergies are going to come through G&A savings. We do expect some of that to be from insurance cost reduction as well as we put the two portfolios together. We have meaningful savings there. As the year progresses, we expect to start realizing some operational synergies, but most of those operational synergies should materialize in 2025; however, we should start seeing some of that as the year progresses as well.

Okay. And I guess just on the operational synergies, is that largely going to show through in LOE and maybe some in CapEx as well? Just trying to make sure I understand how that hits the financials.

Yes, you're going to see it in both. I think we can optimize some of the logistics with helicopters and vessels, some of the supply chain. There are some yards and how we manage spare parts and things of that nature. That is going to be the majority of those savings on the LOE side of things. On the capital side, obviously, we can optimize rig lines. We can better manage how we drill wells and how the sequence of those wells, etc. Most of the operational synergies that I just talked about refer more to LOE; as we plan for 2025 and beyond, you should start seeing more of that in capital as well.

I would say, Leo, that it's a bit different offshore compared to onshore, where someone might manage assets in Eagle Ford with several rig and frac lines and then integrate them. Offshore, we see less of that because the way we deploy these rigs can vary significantly from year to year based on the budget. As Sergio mentioned, there is a bit more impact on LOE, but ultimately, it affects both areas.

Your next question comes from the line of Jeff Robertson from Water Tower Research.

Tim, to follow up on your comments around Katmai West, am I right in thinking that the combination of pressure data and the minimal drawdown that you've seen over 8 months of production, plus reprocessed seismic makes you think that the container is bigger, which justifies drilling the #2 well to try to test that theory and maybe add reserves and accelerate production?

Yes, I believe the answer to that is yes, Jeff. We've always been optimistic about these assets. One reason we went ahead with the transaction is that we've been monitoring this asset since its discovery. We had the opportunity to buy a working interest in it back in 2019, but we chose to wait for better data, and now we feel confident about adding it to our portfolio. The transaction took place in 2023. We're optimistic about the area. When it comes to the specifics of what you can book as improved reserves, you and your auditor need more than just intuition. You need to convert that geological observation into reasonable certainty either through that information or by gathering physical data, such as drilling a well. To realize that value quickly, we will need to drill a well. You have to evaluate the risks associated with that well, which ties back to a question Leo asked, and we feel good about it. Our outlook on the area has always been positive. Now is the time to invest some capital so we can return to the auditors and demonstrate why we believe this feature is as significant as we suspect. You're correct; there will be pressure declines that we need to monitor. It's the rate of those declines in relation to the volume being produced that will give us confidence as we design the well.

Tim, do you think it has the potential to add value that might not have been fully quantified when you purchased QuarterNorth?

It certainly wasn't into underwritten purchase price. We bought this asset at almost pre-developed. Just the minimum volumes coming through the current production are what we're able to get and approve. It's still a young discovery in that regard. No doubt what we're trying to execute here is outside the underwritten economics, and it's currently not reflected in the stock price. As Sergio talked about, we think we have a totally underappreciated valuation on the stock price. All of this is upside to how we financed and fundamentally put together the transaction, and certainly, this is a catalyst for the stock.

Just to follow up, you talked about infrastructure and the importance of owning infrastructure, and you've seen that ramp out. So with Tarantula, I think you all own, Talos owns a 50% interest in it and it has an override. Can you talk about the margin impact of adding barrels through owned facilities and the kind of fees you collect and how that enhances Talos' own margins?

Yes. It's interesting. That’s another one we're following on maybe where Leo's question is, as you think about these volumes. We own that Tarantula facility at 100%. You referenced Ram Powell; we own that facility at 100%. We drilled Lime Rock and Venice at 60%, so that other 40% was with a private partner, a great partner of ours. They're going to pay us a handling fee to manage their production, and that ultimately offsets our operating costs. We benefit from the economics of drilling the well, also get a secondary benefit when we own a facility at a greater working interest than the wells coming to that facility, meaning some other parties paying us production handling. This manifests itself as an override. There are different structures on how that works, but ultimately, they all contribute to lowering your overall lifting cost setup and increasing your netback per BOE margins. Again, as Sergio talked about on the call. That's the benefit of infrastructure. Not only do they aid in your breakevens and lower those breakevens, giving you a chance at more inventory than you may not have in the Gulf of Mexico if you didn't operate this infrastructure, there's a secondary benefit when you're collecting what we call production handling revenue offsetting our operating costs. All of that works itself through in Katmai; the bigger that might be, the more of that secondary benefit.

Your next question comes from the line of Nathaniel Pendleton from Stifel.

My first question is regarding future partnership opportunities that some of what you just alluded to there. With offshore back in the spotlight a bit, how should we think about the sweet spot working interest for Talos on a given prospect, more from a risk tolerance perspective going forward?

Yes. Look, that's a good question. We start with what are the things that can help manage corporate decline over the next 12 to 15 months. What can we do on the development side? There might be a little higher working interest. It might not require some of those joint ventures. So what we're doing in the Lobster field is an example of that. We want to, as our first priority, make sure we're identifying a portfolio around those types of opportunities. We then get to what I would call that middle market more likely than not; two of every three work. Those are the Venice and Lime Rock types, the Sunspear types. Those prospects can be 12 million to 20 million barrels or one well tiebacks. Typically, we don't want to do those at 100%. We'd like to partner for those, but we may lean in and have a 50% to 60% working interest. You saw that in Venice and Lime Rock. At least once a year, depending on the year, maybe twice a year, we want to put a test out there that could be a really high impact, and the Daenerys is an example of that. Those are typically subsalt. When you look at the landscape of those types of risk/reward opportunities, they have a higher well cost, and we should probably have a lower chance of success, but they can be impactful if they work, and they can have a long resource life. Katmai was at some point that kind of high-impact prospect; it's now a high-impact discovery. We're probably going to have a little less working interest, maybe 25% to 30%, which is where we are at the Daenerys at 30%. That gives you an education on how we think about that. We want to make sure we've got the right reinvestment rate. We want to make sure we have the right shots on goal. One thing I've talked about in previous calls is we can have a very busy year, both in the drilling and hook-up side one year and then a lighter year than next year. You kind of have to think about our portfolio in two-year cycles depending on what the success is on the wells we drill.

That's great detail. I appreciate it. For my follow-up, referencing Slide 9 that you touched on in your prepared remarks, it looks like most of the blocks you acquired are in areas that have existing seismic or adjacent to current acreage, with the exception of the blocks at the bottom in Walker Ridge. Is there anything you can share about those blocks or blocks in general where you're stepping out of either seismic coverage area or the existing footprint?

Yes. There's a deep play that we think is evolving down in that area. There’s some ancillary seismic in there that we have that probably should have shown up on this map. That's a longer hold. A lot of what we do is identifying things we can see. It's geophysically driven, meaning we think it has a hydrocarbon indicator or an amplitude, depending on who you talk to. We want to grab it while we can, knowing it may bear fruit down the road. You're always thinking about all of those categories when we go to lease sales.

Your next question comes from the line of Jarrod Giroue from Stephens.

I was just curious about the Daenerys prospect. Tim, in your prepared remarks, you said that you guys could get to it late this year or it could push into early next year. I guess what's the determining factor for a 4Q or an early 2025 spud? And with that post spud, about how long until you expect first oil?

It’s really dependent on rig deliveries more than anything else. Will we get the rig kind of right where we want relative to Katmai and then the execution of Katmai? We have flipped the order; earlier in the year, we were thinking Helm’s Deep, but I do think Daenerys is high impact enough. We have a partnership that's excited about it. We will probably move that to the head of the line. So rig delivery will be a part of that. The rig we're utilizing there is on one of the prospects we announced; it had some recent success in Claiborne. They've got to wrap that project up and then we have a chance to get that rig hopefully on time. Very well could be on time, but again, rig delivery is rig dependent. Getting that hooked up would take a little longer. That is a deep test that has a tremendous amount of potential. We're designing in there to try to get two penetrations into the structure. Again, that is a type of project that has more engineering study, more long leads, more of a kind of get to an FID, and some of the things we do in our typical portfolio; a little longer cycle time. The big catalyst on next year, if we think about production next year, is the Sunspear discovery from last year that we're trying to get online in the first half of the year. If Katmai is successful as we anticipate, we hope it will be; it will be online in the first half of next year as well.

That's perfect. And then one more. My second question relates to the transactions during the first quarter. Do you expect any more transaction-related costs in the second quarter?

We might have some severance costs and some other minor transaction costs in the second quarter, Jarrod, but the bulk of it should have already been recognized in the first quarter. We might see a few things in the second quarter, but not a lot.

I thought you were asking if we should anticipate more transactions. If we do more than four a quarter, I think Sergio will reach cross success. So yes, there could be some lingering onetime costs.

Your next question comes from the line of Paul Diamond from Citi.

I just wanted to quickly touch on those 17 blocks. You talked a little bit about splitting them between kind of shorter cycle in a 3-year time horizon and this longer cycle. How should we think about the breakdown of those? Is it 50-50? Or is it 70-30? Just how does that break up?

That's a good question, Paul. It's important that we continue to ask these questions and focus on education. I mentioned three categories: the development phase, which I consider the middle market, and then the broader multiple wells or larger projects. Typically, development is quite swift, around six to twelve months, especially since we have infrastructure nearby—usually within two miles or we might be drilling from our facility. Those projects usually turn around quickly. The middle market projects, such as Venice, Lime Rock, and Sunspear, generally have turnaround times of about eighteen months. If new equipment is needed, it could extend up to two years, but typically it's within the fifteen to eighteen months timeframe, and that's what we're aiming for in Sunspear. Then there's the long-term aspect. Most of our portfolio is structured for those first two categories. If we were to drill offshore wells this year, which we’re not fully doing, we expect to do so next year. You can anticipate that four or five out of the six wells will fall into those first two categories or those shorter timelines that leverage the existing infrastructure.

Understood. Excellent clarity. Just one kind of quick one on HP-1 and the 55 days of downtime. How solid is that number? Should we think about any potential to slip either quicker or longer? Or is it pretty much 55 days as where it is?

I mean, look, nothing is verdict. If it's 55 days, it's like the old Einstein quote, right, 'every good model is wrong the day you produce it.' But yes, we feel good about where we are. We're into the dry dock period. It's down to Galveston. For anyone local that wants to look at, you can visit or at least look at HP-1. It's been there for a couple of weeks. It's on schedule. There are two pieces; three pieces to this. Leaving the field offshore and arriving at dry dock. There's a period around that, doing dry dock itself, and then there's a third period where you do some sea trials before you hook everything back up. It's on track right now, and there’s maybe a little weather dependency as we get back offshore. Maybe we can beat it by a couple of days and get that production back. So I'm optimistic; I don't want to guide anything other than it's on track, and I feel good about where we are right now on the drydock schedule.

And your next question comes from the line of Kevin MacCurdy from Pickering Partners.

It sounds like the QuarterNorth acquisition is going well, and you're pleased so far. When you think about your consolidation strategy, what was different about the QuarterNorth integration versus the EnVen acquisition? What have you learned that you can apply to future M&A?

I believe our experience with the EnVen acquisition and integration has taught us valuable lessons. We've completed twelve transactions, and as we grow, we learn to quickly unify the organization. In the case of QuarterNorth, we chose a 50-50 cash to debt transaction to expedite the process. Given the uncertainty of oil prices, we aimed to maintain a strong balance sheet while closing swiftly. The urgency was particularly due to the critical Katmai well that needed design and execution within the year. Our goal was to transition to operational mode as quickly as possible. This integration was different because we had more experience in organizing the company and a stronger focus on closing speed, allowing us to operate the asset and realize synergies sooner. While we may not be able to replicate this approach every time, it was the right strategy for QuarterNorth.

Great. As a follow-up, do you have the current production from the assets acquired from EnVen? What is the current production from the QuarterNorth assets?

Yes. I haven’t owned EnVen long enough to provide specific numbers. However, I can share that regarding those assets, we faced some downtime after opening the facility following the closure in Neptune, but I’m pleased to say that the facility is operating at full capacity now. The Neptune facility is producing at the same levels as before we acquired the EnVen assets. This is significant because we have a joint venture with Repsol in that area, primarily related to the EnVen acreage. We didn’t factor a large joint venture with Repsol when we completed the EnVen transaction, so any value that can be generated there is beyond the anticipated value. Additionally, the Sunspear discovery represents further potential upside from the EnVen deal. EnVen is performing well, and I’m more familiar with QuarterNorth, which has also had a strong start as we just closed that. The assets there have been producing 32,000 to 33,000 barrels equivalent per day over the last month. There will be some adjustments in our guidance for the second quarter due to a dry dock, but overall, we are pleased with the performance of this asset.

Your next question comes from the line of Noel Parks from Tuohy Partners.

I just had a couple. I was wondering, on what you're seeing out there in terms of M&A opportunities; your model has been successful focusing on the underused facilities out there in the deepwater. Are the range of opportunities you see out there for your strategy with those facilities a larger subset of what might be out there compared to, say, things where the traction would be more just underutilized technology to an existing but maybe still fairly well-used project?

Look, I think the technology advancements that we've had in our basin related to seismic technology, related to drilling technology with the seventh-generation rigs, related to subsea tiebacks and their getting longer and how you think about flow assurance. We're not patenting any of this stuff; the best operators in the Gulf of Mexico, all understand that. We're all employing that within our execution of our business plan. I do think longer term, as you think about us in that counterparty statement, 70% of the production in the Gulf of Mexico is still operated by 4 names; the 3 majors plus Exxon. They all have their own economists; they all have their own view on oil price. There’s no predictiveness on when they could come to the market. If they do come to the market, we think we're a good counterparty to be a buyer of those assets. But we can’t, as I mentioned earlier, the reason I can’t give you an idea where M&A flow is in the Gulf of Mexico is because some of the private sellers we probably knew about, we’ve done those transactions. Now you're going back to what we think would be ultimately when they come to the market, underutilized deepwater assets; things that we could find some benefits from some of the prospects that we talked about in that middle category can be material to companies like us but maybe a little less to a company like Chevron. That’s really interesting to us. But right now, again, more tactical and smaller things while we wait to see where those potentially transact in the future, knowing that it’s totally unpredictable right now.

I wondered if you had any updated thoughts on the offshore rig market, continuing to see high utilization there, and the pricing power increasingly seems to be with the vendors. Any thoughts there on how that might affect your outlook?

It does a little bit. I think there are a couple of interesting questions here. When I go through those categories of prospects, we try to drill; those deeper ones clearly subsalt that final category—when you're getting 24,000, 25,000 feet, something like Katmai—you do need those big rigs. You need managed pressure drilling systems. You need the best efficiency on those. There’s a part of our portfolio that utilizes that. But there’s a big vast part of our portfolio that doesn't have to have a seventh-generation rig. We had some success with a smaller rig last year that do price out at a different rate. We're going to try to make sure we've got the right rig that fits our portfolio. Look, the other thing we haven't done and I’ll continue to resist doing it is taking on long-term rig contracts. If you think about how companies in the Gulf haven't made it, there are people who have had horror stories around that over the last 10, 15 years. Typically, they didn't hedge when it was appropriate to take on some hedges, and they did that in the second quarter, by the way; it's over $80, or they took on too long, a rig contract or they took too high of a working interest in the deepwater project for a company of their size. We're not going to take on a 2-year rig contract at the current rig rates; we just won't do it. That could cause capital to be a little lumpier and frankly, could generate more free cash flow—a little less predictive on how you think about production. I'd rather take on a little bit of that lumpiness than an obligation. We'll look for windows; if that window is, we can execute something for 180 days instead of doing something for 18 straight months, we’ll do that to make sure we don't take on too big of an obligation for a company our size.

We have a follow-up question from Subhasish Chandra from Benchmark.

I'm revisiting the production outlook. Now that we have an overview of the second quarter and are moving into the third quarter, with HP-1 back, I'm curious about any potential counterbalancing factors for production in Q3, especially considering the uncertainties like storms in the Gulf. Can you share any insights beyond HP-1's return?

Yes. Look, I think it’s the timings of these shut-ins and some of this downtime. You can beat the schedule; we might have 2 weeks in something and realize you can beat it by 4 days and get the production back a little sooner. There might be some performance in a couple of assets that could surprise to the upside. We had some declines in the Tornado field last year, and some of that has stabilized and surprised to the upside. It’s always a combination of how the asset is performing, how are you managing the downtime, can you beat the schedule? There may be some natural slippage, which could be a benefit this year. We’ve gotten to a point with our asset base; you should think about this as a 100,000 barrel equivalent a day business. When you have that asset base, things move around across all these assets with some upsides in some areas, and then again, some downside risk if a third-party pipeline calls the size of the blue and we realize the field shut-in, and we didn't get a lot of warning on that. We’ll do our best to be transparent about it quarter-to-quarter; it’s hard to be predictive three quarters out. We’ve talked about annual guidance and as we enter quarters, we're going to talk about quarterly guidance as opposed to laying out guidance for all 4 quarters when these things can move around.

Got it. And to that, the Od job project, non-op—when do you see that sort of coming back? Or I guess enhancing volumes?

Yes. That's a subsea pump, right? With Kosmos? Yes. Look, I think that's on track. I don't want to speak for them; we don't have as much exposure to that so it's not something I follow day-to-day, but my understanding is it’s on track. Just the technology of that is really interesting. The ability to lower the overall reservoir pressure—it's been a high-performing asset, I know it's important in their portfolio. Even at 17% it's important for us. It’s a better question for those guys.

There are no questions at this time. I will now hand the call back to Tim Duncan, CEO. Please go ahead.

Thanks, operator. Look, great questions. Good Q&A. It's good to see more people covering the story. We're going to get more questions, and we appreciate them; we want to be transparent. We want to give the right amount of color so people understand our business. Really happy with the first quarter; happy to see production, EBITDA, CapEx, free cash flow, kind of all ahead of consensus for transactions, refinancing the debt, driving down our cost of capital. I mean, all those are important milestones as we reposition the company. I'm excited about the second quarter. I'm excited about the rest of the year; we should have some good calls throughout. Thanks for everyone's attendance, and we look forward to talking to all of you soon.

Thank you. This concludes today's call. Thank you for participating. You may all disconnect.