Talos Energy Inc. (NYSE:TALO) Q1 2024 Earnings Call Transcript

Talos Energy Inc. (NYSE:TALO) Q1 2024 Earnings Call Transcript May 7, 2024

Talos Energy Inc. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good morning, ladies and gentlemen, and welcome to the Talos Energy First Quarter 2024 Earnings Call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions] This call is being recorded on Tuesday, May 7, 2024. And I would now like to turn the conference over to Clay Jeansonne. Thank you. Please go ahead.

Clay Jeansonne: 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 obligations 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.

Tim Duncan: 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 focus on oil-weighted assets, and two, we think it’s critically important that we operate our deepwater infrastructure, and 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 in 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 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. 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. 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 that 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 two times our money and immediately take those proceeds and accelerate 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.

So as we turn to Page 6, let’s hit some of the highlights of the quarter. We average 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 at $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 one times 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 is it allows us to control two things. One, we can control the assets operationally, which is important as we plan to Katmai well, that I’m going to discuss later in the slide deck. The other thing is we can get to the work of 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’ll also see some synergies that flow through operating costs.

But even so far, since we closed the transaction, we’re 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 go on to Page 8, we can talk a little bit about the second quarter, it also relates to the first quarter. The second quarter is where we’ll have the HP-1 drydock in our Phoenix field, which includes our Tornado asset. We thought there would be a couple of days late in the first quarter, but ultimately that got delayed. So it’ll kind of be a clean 55 days within the second quarter. It’ll have an impact to the quarter of 5,000 to 6,000 barrels equivalent a day. Sergio will talk about broader patterns for the second quarter.

Just a reminder, this is a dynamically positioned vessel that hosts several of the production from Phoenix and Tornado. So it has to go into drydock 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 you’re 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 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 is our facilities that we control and operate. And if you look at the gold-colored 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 and where we can develop inventory around these facilities. And what you notice is 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 there is a 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. And then we start our drilling campaign with the Katmai project. I’m going to talk about that. And then the Daenerys project, which is a high-impact sub-salt well. But ultimately we’re going to try to get into this year, it could work into next year as well. And then 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, and 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. But what Lime Rock and Venice has always showed is really good execution on our strategy. These are locations that we’ve identified after we bought the asset. You can see the impact on the right side of the page, and 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 sub-salt 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. And 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. Now, you’ll notice in the first quarter we had some planned downtime, and 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. And that’s causing us to have more confidence in how we think this field will get developed.

Let’s continue the conversation around Katmai and talk about the Katmai West number two well, and why we think it’s so important. And there’s a lot going on in the slide, but it helps understand how we think about better defining and expanding the resource when you have a deepwater discovery like Katmai. So if you go on the graphic on the left, what we’re showing you visually is where the Katmai West number one well was drilled geologically in the structure. And then on the right, we’re trying to help you understand how that better defines lowest known oil, which defines our proved reserves. And so you have a 400-foot pay column that helps to find proved reserves and then to 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 Katmai West number two well. We’re going to extend the geological column and with that information and the pressure of data and the production data, we’re going to have a better understanding on 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. And to talk more about capital allocation outside our drilling program, I’m going to hand it over to Sergio.

Sergio Maiworm: 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 one times or below, and we’re actually able to achieve one times at the end of the first quarter. So we’re way ahead on our target there, and I expect that 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 on our RBL and $1.25 billion in bonds.

In the first quarter, a combination of cash flow generated by the business and its 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 as expected. On Page 15, I wanted to highlight three metrics that shows how compelling of a value opportunity Talos is to investors. First, we have one of the highest oil contents or highest oil exposures in the entirety of the E&P sector in the United States. And as a continuation of that, we also have one of the top margins in the business, and that 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 having one of the highest free cash flow yields in the entirety of the 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. And 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. And 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, which combined with our industry-leading netback margins that we talked about earlier and our streamlined capital program for 2024, puts us in a great path to deliver on that — on the business plan this year.

Regarding our full-year guidance, we’re reiterating our operational and financial guidance and we continue to expect an average production for the year between 89,000 barrels 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, as well as expected downtime estimates for the HP-1 drydock 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. And that includes the expected planned downtime for the HP-1, which as we said earlier is roughly 5,000 barrels 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. In our capital investments for 2024, we have a mixed 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. And now I’d like to turn the call back to Tim to wrap up with our key takeaways for the quarter.

Tim Duncan: Thanks, Sergio. So, 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 and Sergio mentioned how we’re thinking about M&A and certainly an important part of our strategy. But really, 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 on 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 modeled through the downtime, but the capacity of these assets are great. We think — 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 to deliver free cash flow yield that we’re generating right now. We’re committed to low leverage and we’ve accelerated our debt reduction program. And we anticipate getting as high as $550 million. And that’s important because it’s fully based of the RBL, which gives us flexibility for the future. We believe in the growth potential that we have. And we talked about in this presentation, 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 this while we continue to be committed to safety and sustainability. You know, we’ve been putting at out our ESG reports as one of the leaders in the Gulf of Mexico on how we think about sustainability. We’ll continue to do that, even though we don’t own TLCS. We’re committed to the idea of the ecosystem that we’re involved in and we’re proud of our efforts today. With that, I’ll hand it over for questions.

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Q&A Session

Operator: [Operator Instructions] Your first question comes from the line of Tim Rezvan from KeyBanc Capital Markets. Please go ahead.

Tim Rezvan: Good morning, folks, and thank you for taking my question.

Tim Duncan: Hi, Tim. Good morning.

Tim Rezvan: I want to start on — I want to start on Sergio’s comments for Jan to prepare a script about actively seeking further M&A opportunities. Obviously, the integration has gone pretty well here. So I was curious, Tim, can you kind of give updated thoughts on what you’re seeing in the M&A landscape both kind of within the Gulf and outside it? As you think about it, oil is run here, but there’s a lot of backwardation on the strip. So just curious, kind of what you’re seeing out there?

Tim Duncan: I think it’s maybe a little slower than where we were a year ago. We knew in the Gulf of Mexico particularly, there was a couple of key privates, and ultimately that was EnVen and QuarterNorth that we were focused on. And we knew they could bolster the business, and so we’re proud of how we executed those. There is not those obvious candidates today. And so I think our focus has been really execution, which we’re proud of the first quarter. We’re excited about the rest of the year. There is 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. And certainly, 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. And so probably a little slower on that front than maybe in the last couple of years, where we knew kind of what was coming. There is 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.

Tim Rezvan: Okay. Okay. I appreciate that. And then 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 or excuse me net debt below $1 billion, how do you think about maybe repurchases kind of re-entering the equation or kind of 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? Thanks.

Tim Duncan: Yes. Look, it’s a good question. I can tell you the Board’s thoughts and our thoughts today are just get that RBL paid off, just because I think it provides maximum liquidity and flexibility. Look, we still have a $50 million authorization on stock repurchases, and we could think about that. But I do think we’re hyper-focused on getting through the year and make sure that revolver is paid off. You can build up a little cash kind of for some of these tactical ideas we have, and I wouldn’t hold back. Right now, it’s harder to restart your own operated capital program, but we do see a lot of opportunities out there as people are thinking about high grading, their exploration in their drilling joint ventures, and their drilling inventory.

And 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 think about 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 are we on the schedule. How do 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? And sometimes, if you have $25 million to deploy on a stock purchase versus an opportunity that comes your way, that can generate a 30%, 40%, 50% rate of return, you’ve got to think about each of those opportunities individually. So the near-term focus again getting the RBL paid off, I think everything can be on the table once we accomplish that goal.

Tim Rezvan: Okay. Thank you.

Operator: Thank you. And your next question comes from the line of Subash Chandra from Benchmark. Please go ahead.

Subash Chandra: Yes. Hi, Tim, could you kind of talk to the production trajectory from now to year-end? And I think in your March presentation, you sort of had a slide talking about 105 to 110. You referenced 105, I think, in your comments, but 105 to 110 sort of being, it was a proforma. But is that the baseline that we return to and if you can kind of talk through that and what we should be expecting, say, as an exit rate for the year?

Tim Duncan: Yes. Thanks, Subash. Yes. You know, 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? And so even when I talked about, I think, in the last call the first month, the assets together even before we close, averaging 106, and before drydock averaging 105, there’s a little downtime in there. There’s always some downtime in the system as we’re doing rotating equipment, doing some kind of other construction projects around these assets. From there, then you’re trying to plan out when this downtime can occur. What’s in your control?

What’s out of your control? Obviously, for example, HP-1, the timing of when that vessel gets to drydock is not within our control, when we’re waiting on something like thrusters that they have to replace. So we had some downtime. As soon as we own 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. And these aren’t small downtimes, you’ve got a facility like the HP-1, where net to us were 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 kind of walk through that in that deck that’s on the site as we laid out our guidance. So everything’s 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 the assets. So again, the assets are performing very well. This is really around the cadence of that downtime. Some of that in your control, some of that could slip. We will try to make sure we guide that every quarter. But 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’s weather-dependent as well. So, look, I think if that ticks up, you can expect operating costs as a unit of production to go down.

And so I think, you know, we’re really happy with the first quarter, we had beats in production and EBITDA and CapEx and free cash flow. You expect that we would expect that to continue as we go throughout the year.

Subash Chandra: Okay. Got it. So it looks like, is it fair to say the downtime is mostly or maybe entirely legacy assets and that we should be thinking…

Tim Duncan: Yes. Well, look, Katmai was the big piece of the downtime in the first quarter, you know, and I think I showed that on the graph, and look we couldn’t be more excited about that asset. And honestly, there was some repairs and maintenance that we did during that downtime, which is actually a third-party pipeline downtime. We actually did a couple of things that actually raised production 1,000 barrels a day on that facility as a result of doing some repairs during that downtime. So, you know, this downtime is for the benefit of these assets. Let’s be clear about that. Now, in the second quarter, yes, that’s going to be more a Talos legacy. As we go into the third quarter, it could be a mix of both assets. So, you know, it’s not, I don’t want to say we’re pinning it on either of these asset sets because it’s just part of the aggregate pro forma business.

I think what we’re trying to do is be more transparent to you guys and more transparent to the market on how we think about production in offshore assets relative to onshore assets, and how you should try to think about modeling downtime and modeling weather, starting with a clean run rate. And I think that was the purpose of the slide we had in the last deck, and we’ll continue to have that slide in our future decks.

Subash Chandra: Okay. Got it. Thanks, Tim.

Operator: Thank you. And your next question comes from the line of Leo Mariani from ROTH MKM. Please go ahead.

Leo Mariani: Hi. Wanted to talk a little bit more about Katmai. Number two, how do you kind of think about the potential risk associated with that? Well, you guys basically certainly expect it to 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?

Tim Duncan: Well, look, when you’ve got what I 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 perforations. And so we know exactly what’s happening when we flow a well, we know how that well is declining. And 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 then we’ve got better seismic data. We’re going through a lot of reprocessing that, you know, Leo, we do all the time. So we think we’ve got a good picture of the structure geologically.

You’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 go see what this feature looks like as we get further away from the current well. And certainly, nothing is guaranteed. I mean, you could go down there and learn something different than what you anticipate. But what we hope is that 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 significant amount of reserves. And that’s where you get into the full upside picture. So if you can imagine, you know, as we work with an auditor like Netherland and Sewell, we’re working with them to try to say, hey, look, how do 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. And just based on the data we have so far, there could be a meaningful resource there. You can wait and produce it and it’s going to take you a while to convince everybody that, that resource has that full potential or you can do a combination of producing, analyzing, and drilling for it. And I think it makes sense for us to drill for it. So we look, we think that this kind of fits in that combination of probable and possible categories and so kind of in that more than 50% more likely than not. But you know, we are at 27,000 feet and so you know, I think we’re going to have to go find out, but I think we’re very optimistic about what we’re doing this year on Katmai.

Leo Mariani: Okay, now that was great, very thorough there. And I just wanted to follow up on QuarterNorth in the synergies. I think you mentioned that you thought you’d get to kind of $30 million kind of run rate by the end of the year, kind of at $20 million now and you get the full $55 million next year. Is the $30 million this year primarily just the kind of the G&A savings and maybe some of the interest that you might have got and is the ops stuff kind of the extra $25 million next year? I know you’re talking about potentially being able to lower some of the OP costs as the year goes on. Just want to get a little bit more color around the numbers here.

Sergio Maiworm: Hi, Leo, this is Sergio. I’m happy to answer that. Yes, I would say, 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. And as the year progresses, we do expect to start realizing some of those operational synergies. But most of those operational synergies should materialize in 2025, but we should start seeing some of that as the year progresses as well.

Leo Mariani: Okay. And I guess, just on the OP 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.

Sergio Maiworm: 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 is 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. And 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, et cetera. So most of the operational synergies that I talked about just a minute ago, I was referring more to LOE. I think as we plan for 2025 and beyond, you should start seeing more and more of that in capital as well.

Tim Duncan: Yes, I would say, Leo, a little different than onshore, where we might have somebody has assets in Eagle Ford with multiple rig lines, multiple frac lines, and then they just figure out how to bring those together. You see a little less of that offshore because how we pull these rigs in can be unique to any one budget year. So, as Sergio said, a little more on LOE, but ultimately it hits both sides.

Leo Mariani: Okay. I appreciate it. Thanks.

Sergio Maiworm: All right. Thanks, Leo.

Operator: Thank you. And your next question comes from the line of Jeff Robertson from Water Tower Research. Please go ahead.

Jeff Robertson: Thank you. Good morning. Tim, to follow up on your comments around, Katmai West. Am I right in thinking that the combination of the pressure data and the minimal drawdown that you’ve seen over eight months of production, plus reprocessed seismic? Makes you think that the container is bigger, which justifies drilling the number two well to try to test that theory and maybe add reserves and accelerate production.

Tim Duncan: Yes. Look, I don’t know if it’s — the answer to that is yes, Jeff. But I would say, we’ve always been optimistic about this asset. It’s one of the reasons we went and bought — executed on the transaction in the first place. I mean, when we — we’ve been — we’ve had our eye on this asset since it was discovered. You know, we had a chance to potentially buy a working interest in it in a transaction in ’19, and we waited and got better data and feel good about adding it to the portfolio when we did the transaction in 2023. So we’ve been bullish about the area. But when you get down to the very details of what you’re allowed to book, improved reserves, you and the auditor you’re working with need to see something more than just your intuition, right?

And so at some point, you’ve got to expand, physically expand that geological column into reasonable certainty, either through that information or ultimately getting physical data, like drilling a well and getting the data yourself. And so, for us to accelerate that value in the proved, it’s going to require a well. And so then you have to decide, where are you. You know, how do you feel about the risk of drilling that well? Which is a question I think Leo asks, and we feel good about it. So we’ve always been bullish in the area. It’s time to go put some capital to it so we can go back to the auditors and show why we think this feature is as big as we hope it is. And you’re right, look, there is going to be some pressure declines. You want that.

It’s the pace of those declines relative to the volume it might be seeing that gives you the confidence as you go design a well.

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

Tim Duncan: It certainly wasn’t into underwritten purchase price. I mean, look, we were buying this asset, it almost proved developed. And so I can tell you right now that just the minimum volumes coming through the current production is what we’re able to get into approved, it is still a young discovery in that regard. So there is no doubt that what we’re trying to go execute here is outside the underwritten economics, is tarnished, or not reflected in the stock price. As Sergio talked about, we obviously, we think we have a totally underappreciated valuation on the stock price. So all of this is upside to either how we financed and fundamentally put together the transaction, and certainly all of this is a catalyst for the stock.

Jeff Robertson: And then just to follow, you talked about infrastructure and the importance of owning infrastructure, and you’ve seen that at ramp out. So with Tarantula, I think you all own or Talos owns a 50% interest in it and hasn’t 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’ owned margins?

Tim Duncan: Yes, well, it’s interesting. And that’s another one we’re following on maybe where Leo’s question is, as you think about these volumes. So we own that Tarantula facility at 100%. So 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 private company, a great partner of ours, and they’re going to pay us a handling fee to manage their production, and that ultimately that offsets our operating costs. So we get the benefit of the economics of drilling the well. We get a secondary benefit when we own a facility at a greater working interest than the wells coming to that facility. That means some other party is paying us production handling.

This one, it manifests itself in an override. So there is different structures on how that works, but ultimately they all contribute to lowering your overall lifting costs setup and increasing your net back per BOE margins, which again Sergio talked about on the call. So that’s the benefit of infrastructure. Not only do they aid in your own breakevens and lowering those breakevens, and giving yourself a chance at more inventory than you may not have in the Gulf of Mexico if you didn’t operate this infrastructure. There is a secondary benefit when you’re collecting what we call production handling or PHA revenue or offsetting our operating cost. And so all of that works itself through in Katmai. The bigger that might be, the more of that secondary benefit.

Jeff Robertson: Thank you.

Tim Duncan: Thanks.

Operator: Thank you. And your next question comes from the line of Nate Pendleton from Stifel. Please go ahead.

Nate Pendleton: Good morning. Thanks for taking my questions.

Clay Jeansonne: Good morning, Nate.

Nate Pendleton: My first question regarding future partnership opportunities, that somewhat of what you just alluded to there. And 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?

Tim Duncan: Yes, look, that’s a good question. I mean, you know, we do start with what are the things that can help manage corporate decline over the next 12 to 15 months. And so what can we do on the development side, there might be a little higher working interest. It might not really require some of those joint ventures. So what we’re doing in the Lobster field is an example of that. And again referenced in the deck, that’s a really cool project. And so we want to — our first priority is making sure we’re identifying portfolio around those types of opportunities. And then we get to what I would call that middle market, more likely than not two of every three work, and that’s the Venice and Lime Rock types, the Sunspear types.

Those prospects can be 12 million to 20 million barrels. They’re one, well tiebacks. Typically, we don’t want to do those at 100%. We’d like a partner for those. But we may lean in and have a 50%, 60% working interest again, what you saw in Venice and Lime Rock. And then at least once a year, depending on the year, maybe twice a year, we want to kind of put a test out there that could have a really high impact, and Daenerys is an example of that. Those are typically sub-salt. When you look at the landscape of those types of risk-reward opportunities, they have a higher well cost and we should probably have. And they have a, you know, kind of a lower chance of success, but they can be impactful if they work, and they can have a long resource life.

And Katmai, at some point, was that kind of high-impact prospect. It’s now a high-impact discovery, but we’re probably going to have a little less working interest, maybe 25% to 30%, which is where we are at Daenerys at 30%. So it’s just a little bit of 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 could have a very busy year, both in the drilling and hookup side, one year and then a lighter year the next year. So you kind of have to think about our portfolio and two-year cycles, depending on kind of what the success is on the wells we drill. But that gives you an example of the risk-reward mix.

Nate Pendleton: That’s great detail. I appreciate it. And 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 kind of stepping out of either seismic coverage area or the existing footprint?

Tim Duncan: Yes. So there is a deep play that we think is evolving down in that area. And we’ve got — there is some ancillary seismic in there that we have that probably should have shown up on this map. And so that’s a longer hold. So a lot of what we do, there is some things that we can identify and say, hey, look, I know exactly what that does. It’s geophysically driven, meaning we think it’s got a hydrocarbon indicator or an amplitude, depending on, Nate, who you talk to. And that’s one that you’re going to start permitting and defining and get on your drill calendar in the next three years. And then there is other things you’re doing where you say, hey, look, there is a big geological play here. We can see why the Majors are looking at it.

If this takes off, we want to have an acreage position, and these are longer holds. They’re 10-year leases. And so you’re trying to grab it while you can, knowing that it may be something that bears fruit down the road. And so there is always a little bit of that every time we go to a lease sale. And I think that’s an example of that. So, deeper play, I actually do think we have a little data down there that might be a misprint on our side. But I can just tell you just by saying the words, Walker Ridge, it’s going to be a little deeper play, a little longer hold. But, I mean, this is a basin where the minute you focus too much on one of those risk-reward strategies, if you focus too much on development or focus too much on that middle market prospect and don’t think about some of these deep evolving plays, you’ve missed the benefit of what the basin has to offer.

So we’re always thinking about all of those categories when we go to the lease sale.

Nate Pendleton: All right. Thanks for taking my questions.

Tim Duncan: All right, Nate. Thanks.

Operator: Thank you. And your next question comes from the line of Jarrod Giroue from Stephens. Please go ahead.

Jarrod Giroue: Hi, good morning, guys.

Tim Duncan: Good morning.

Jarrod Giroue: Hi, 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 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? Thanks.

Tim Duncan: So I think that is really dependent on rig deliveries as much as anything else. And so we will get the rig kind of right where we want to get it relative to Katmai and then the execution of Katmai and then we go straight to Daenerys. And 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’ll probably move that to the head of the line, so rig delivery will be a part of that. The rig that we’re utilizing there is on one of the prospects we announced that had some recent success in [clapboard], they’ve got to wrap that project up, and then we have a chance to get that rig, hopefully on time. So very well could be on time.

But again, rig delivery, rig dependent. Getting that hooked up would take a little longer. That is a deep test that has a tremendous amount of potential. What we’re designing in there is to try to get two penetrations into the structure and almost to talk about the Katmai. If we can get two penetrations into the geological structure in this first test, we’ll learn more and it’ll help us design what the, you know, what the outlook is. There are some host facilities in the area, it could be big enough that people could think about new construction, but let’s see what the results are. Our focus is always on tiebacks, but that one’s going to take a little longer. That’s more of a two- to three-year cycle time than opposed to kind of the 18-month type of cycle time that you see with things that are a little closer to infrastructure where you feel like you know exactly what you have.

So this is a — this is the type of project that has more engineering study, more long leads, more of an — kind of get to an FID, as some of the things that we do in our typical portfolio. So a little longer cycle time. I think the big catalyst on next year, if we think about production next year, is the Sunspear discovery that we had last year, that we’re trying to get online in the first half of the year. And then again, if Katmai is successful, as we anticipate and hope it will be, that we get online in the first half of the year, next year as well.

Jarrod Giroue: That’s perfect. Thank you for the color. 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?

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

Jarrod Giroue: Yes. I think, perfect…

Tim Duncan: I think that I thought you were asking we should anticipate more transactions, and if we do more than four a quarter, I think, Sergio, I reach across this desk and hit me. So, yes, there could be some lingering one-time cost.

Sergio Maiworm: Yes.

Jarrod Giroue: Perfect. It’s cool. Thanks for the answers.

Tim Duncan: You got it.

Operator: Thank you. And your next question comes from the line of Paul Diamond from Citi. Please go ahead.

Paul Diamond: Thank you. Good morning, all. Thanks for taking my call. Just wanted to quickly touch on those 17 blocks that we talked a little bit about splitting them between kind of shorter cycle in that three-year kind of time horizon, those longer cycle. How should we think about the breakdown of those? Is it 50:50 or is it 70:30, just how does that — how is the breakeven…

Tim Duncan: Yes, that’s a good question, Paul. And it’s important that we keep asking those and kind of keep that education. I think, I talked about those three buckets kind of that development, again what I would call that middle market, one well tie-back, and then the broader multiple wells, bigger projects. The development stuff typically is pretty quick. I would say, six to 12 months. There’s infrastructure in place. We’re right around our own facility, maybe within two miles of our facility, or maybe we’re actually drilling it from our facility. Those turnaround quickly, those middle markets, Venice, Lime Rock, Sunspear. I would say those are, you know, kind of 18-month turnarounds. You know, if it takes a little longer for new equipment, maybe as much as two years, but more of that 15 to 18-month turnarounds.

And we’re trying to, you know, it’s effectively what we’re trying to do in Sunspear. And then again, you’ve got the longer run. The vast majority of our portfolio is designed for those first two categories. Again, if we were to drill six offshore wells a year, and we’re not quite doing that this year, we’ll probably do that again next year. You could expect four or five out of the six of those wells to be in those first two categories, are those shorter windows utilizing that infrastructure.

Paul Diamond: Understood. Thanks for the clarity. And then 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 is where it is?

Tim Duncan: I mean, look, it’s nothing where it is 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, look, I think we feel good about where we are. We’re into the drydock period. It’s down in Galveston. So for anyone local that wants to look at Pier 21 and you can go visit, you know, at least look at the HP-1. It’s been there for a couple of weeks. It’s on schedule. And so there’s two pieces, three pieces of this, leaving the field offshore and arriving at drydock. And there is a period around that, doing drydock itself. And then there is a third period where you do some sea trials before you hook everything back up. Right now it’s on track. And, you know, there’s maybe a little weather dependency as we get back offshore.

You know, 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. But, you know, I think we feel good about where we are right now in the drydock schedule.

Paul Diamond: Understood. Thanks for the clarity.

Tim Duncan: All right. You got it.

Operator: Thank you. And your next question comes from the line of Kevin MacCurdy from Pickering Partners. Please go ahead.

Kevin MacCurdy: Hi, good morning. 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 EnVen acquisition and what have you learned that you can apply to future M&A?

Tim Duncan: You know, I think just the fact that we had just been through, I think the EnVen acquisition and the EnVen integration and you know, we figured out, and look we’ve been through a lot of these, we’ve had 12 transactions. But as you mature, you figure out how to put the organization together quickly. I think the one thing we wanted to do, particularly in QuarterNorth and one of the reasons you saw us, we thought a 50-50 cash to debt transaction was the right way to do this. You don’t always have certainty around oil price. We want to make sure that we keep the balance sheet in good shape, but we also wanted to close it fairly quickly. So we made that choice to do the primary offering, to close this acquisition quickly, in part because we had a critical well like Katmai, that needed to be designed.

It needed to get executed this year, in the first year. So you want to flip into operatorship mode as fast as you can. So, you know, a couple things different. A little more experience and kind of in how we put together the organization, and then a little more determination on pace to closing, so we could operate the asset sooner, get to the synergies sooner, and get to the well-designed on critical budget items sooner. So I think that was a choice on our part. We’re not going to be able to do that every time, but I think it was the right way to structure QuarterNorth.

Kevin MacCurdy: Great. And as a follow-up, do you have the current production from the assets acquired from EnVen, and then what is the current production from the QuarterNorth assets?

Tim Duncan: Yes. Well, look, I’ve owned EnVen enough that long enough that I don’t know if I can break down the actual number on that. But I would tell you, just as you think about it, those assets, I would tell you a couple of things that came up last year. We had some downtime, right, when we opened up that right when we closed that transaction in the Neptune facility. And we talked about that getting all the way back, and that facility is all the way back. And so, I’m really proud of how we’ve recovered in that Neptune facility is producing at the rate it was producing at before we bought the EnVen assets. And that’s important because we have a Repsol JV around there, largely with the EnVen acreage. And so that’s, you know, again, we talked about earlier in the call, tell me about some of the things.

Did you pay for them? Did you not pay for them? We certainly didn’t underwrite a big JV with Repsol when we did the EnVen transaction. So that value that could be created there is outside the underwritten value. And then the Sunspear discovery, again upside to the EnVen transaction. So that got to — off to a little bit of a slower start, but it’s had a hell of a recovery, particularly around Neptune and around kind of the upside in the drilling program. EnVen is off to a great — excuse me, QuarterNorth is off to a great start, that I’m a little more familiar with because we just closed it. And I can tell you those assets were producing 32,000, 33,000 barrels equivalent a day over the last month. Again, we had some drydock, and that’s how it all flows through our guidance in the second quarter, but we like where that asset is performing today.

Kevin MacCurdy: That’s a great color. Thank you.

Tim Duncan: You got it.

Operator: Thank you. And your next question comes in the line of Noel Parks from Tuohy Partners. Please go ahead.

Noel Parks: Hi. Good morning. 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 so successful focusing on the underused facilities out there in the deepwater. And are the range of opportunities you see out there, for the — your strategy of the underused facilities, is that pretty, is that a larger subset of what might be out there compared to say, maybe things where the attraction would be more just underutilized technology, say to an existing but maybe still fairly well-used project.

Tim Duncan: Well look, I think the technology advancements that we’ve had in our basin related to seismic technology, related to drilling technology with these seventh generation rigs, related to subsea tiebacks and they’re getting longer. And how you think about flow assurance. We’re not patenting any of this stuff, right? I mean, the best operators in the Gulf of Mexico all understand that. So 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 four names and it’s the three Majors plus Oxy. And so they all have their own economists, they all have their own view on oil price.

They all have their own kind of between Chevron and BP and Shell, how they’re managing their asset set, so there is no predictiveness on when they could come to the market. Now if they do come to the market, we think we’re a good counterparty to be a buyer of those assets, but we simply 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 who would probably know about, we’ve done those transactions. And now you’re going back to, again what we think would be ultimately when they come to the market, underutilized deepwater assets, things that we could find some benefit 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 material 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.

Noel Parks: Right. Thanks. And I wondered if you just had any updated thoughts on the offshore rig market continues to be high utilization there and the pricing power increasingly seems to be to the vendors. So any thoughts there on how that might affect your outlook?

Tim Duncan: You know, it does a little bit. I think there’s a couple. It’s an interesting question. You know, so if when I — again, I go through those categories of prospects, we try to drill those deeper ones, clearly sub-salt that final category. When you’re getting, you know, 24,000, 25,000 feet something like Katmai, you do need those big rigs. You need, you know, managed pressure drilling systems. You need the best efficiency on those. And so, yes, there is a part of our portfolio that does utilize that. But there’s a big, vast part of our portfolio that doesn’t have to have a seventh-generation type of rig. And so we had some success with a smaller rig last year, that they price out at a different price rate. And so we’re going to try to make sure we’ve got the right rig that fits our portfolio.

Look, the other thing that 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, and there’s people that 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 we did that in the second quarter, by the way, at over $80, or they take on too long of a rig contract or somebody asked, they take too high of a working interest in a deepwater project for a company of their size. We’re not going to take on a two-year rig contract at the current rig rates. We’re just not going to do it. And so that could cause capital to be a little lumpier and frankly could generate more free cash flow, maybe a little less predictive on how you think about production, but I’d rather take on a little bit of that lumpiness than take on that obligation.

And so we’re just going to have to be watchful and look for windows. I mean, if the window is, hey, look, we can go execute something for 180 days and 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 of our size.

Noel Parks: Great. Thanks a lot.

Tim Duncan: You got it.

Operator: Thank you. And we have a follow-up question from Subash Chandra from Benchmark. Please go ahead.

Subash Chandra: Just revisiting again that, I guess, the waterfall of production. Just curious as we sort of, now we got a view of Q2. We come out of Q2, HP-1 is back, and we go into Q3, the uncertainties of a storm, et cetera, et cetera, in the Gulf. Are there any counterbalancing drivers for Q3 that you can tell us about on the production side, above and beyond HP-1 coming back?

Tim Duncan: Yes, look, I think some of the timings of these shut-ins and some of this downtime, I mean, look, you can beat the schedule. We might have two weeks and something, and realize you can beat it by four days and get the production back a little sooner. I think there’s 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. And so I think it’s always a combination of how your assets performing. How are you managing the downtime? Can you beat the schedule? There could be some natural slippage, which actually could be potentially a benefit for this year, and then we can model it through kind of into next year.

So we’ve gotten to where our asset base, Subash. Again, you should think about this as 100,000 barrel equivalent a day business. And 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 us out of the blue and we realize the field shut-in and we didn’t get a lot of warning on that. So we’re going to do our best to be transparent about it quarter-to-quarter. It’s hard to be predictive when I think three-quarters out. And that’s why I think we’ve talked about annual guidance. And then as we enter the quarter, we’re going to talk about quarterly guidance as opposed to layout guidance for all four quarters, when these things can move around.

And again it’s a little less in our control.

Subash Chandra: Got it. And to that, the odd job project non-audit when do you see that sort of coming back? Or I guess, enhancing volumes?

Tim Duncan: Yes. No, that’s a subsea pump, right, with Kosmos. It’s Kosmos. Yes — look, I look, I think that’s Kosmos question. I think it’s on track, and I certainly don’t want to speak for them. We don’t have as much exposure to that. So it’s not something, I think we’re around 17% if I remember our working it just right. So it’s not something I’m following day-to-day, but my understanding is on track. And I would tell you just the technology of that is really, really interesting. You know, the ability to lower the overall reservoir pressure, that’s been a high-performing asset. I know it’s important in their portfolio, even at 17%, it’s important in mine. But kind of giving you the date and time, probably a little less certain than the operator. Probably a better question for those guys.

Subash Chandra: I appreciate that. Thank you.

Tim Duncan: Good.

Operator: [Operator Instructions] There are no questions at this time. I now hand the call back to Tim Duncan, CEO. Please go ahead.

Tim Duncan: Thanks, operator. Look, great questions. Good Q&A. It’s good to see with more people covering the story, we’re going to get more questions, and we appreciate those. And 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. Four 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. And so we should have some good calls throughout. So thanks for everyone’s attendance, and we look forward to talking to all of you soon.

Operator: Thank you. This concludes today’s call. Thank you for participating, you may all disconnect.