Hello, and welcome to the Talos Energy Third Quarter 2023 Earnings Conference Call. I would now like to hand the conference over to Sergio Maiworm, Chief Financial Officer and Senior Vice President. Please go ahead.

Thank you, operator. Good morning, everyone, and welcome to our third quarter 2023 earnings conference call. Joining me today to discuss our results are Tim Duncan, President and Chief Executive Officer; and Robin Fielder, Executive Vice President, Low Carbon Strategy and Chief Sustainability Officer. Before we start, 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 most recent annual report on Form 10-K and our quarterly reports on Form 10-Q filed 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 filed with the SEC and available on our website. And now I'd like to turn the call over to Tim.

Thank you, Sergio, and welcome, everyone, to our call. We appreciate you listening in. I plan to briefly cover some of the key operational highlights of the quarter and then turn it over to Sergio for final commentary ahead of Q&A. During the third quarter, we were pleased with our advancements on several aspects of our business. We continue to advance our Lime Rock and Venice discoveries toward first production. We closed our previously announced Zama transaction in Mexico with Grupo Carso. We reached a new milestone with our first EPA Class VI permit application and filed our second EPA Class VI permit application for 2 additional wells. So quite a bit was accomplished since our last call, and we're excited about the direction of our business. On the drilling and completions capital program, we are in the process of completing the Venice and Lime Rock wells before bringing them online in early 2024. Additionally, we are drilling another development well from our Lobster platform, which is successful to bring incremental production late in 2023 and help contribute to production growth in 2024. Beyond our operator rig program, we are also participating in several interesting nonoperated projects with our partners in the basin. The Marmalard well operated by Murphy was successful over this past weekend. We expect production to commence in the first quarter of 2024. The odd job subsea pump project operated by Kosmos continues to progress and remains on track to be in service by mid-2024. Lastly, the well operated by Beacon is scheduled for a rig intervention in the fourth quarter of 2023 to reinstate production in early 2024. The third quarter is typically a quarter impacted by weather-related events. And even with a quiet hurricane season, loop currents unfortunately impacted our production and drilling operations during the quarter, requiring intermittent shut-ins of the HP-1 and associated infrastructure in the Phoenix and Tornado field. The impact of these loop currents caused a deferral of approximately 1,500 barrels of oil equivalent per day for the quarter in the Phoenix field, or 1,000 barrels of oil equivalent per day for the full year of 2023. The issues have since been resolved and production from the field is back online. The Claiborne nonoperated well was also shut in during the quarter, contributing to an additional 1,200 barrels of oil equivalent per day of downtime in the quarter. As we mentioned, the operator hopes to reinstate production in the coming months, so we should expect this downtime in the fourth quarter as well. Even with this downtime, as Sergio will discuss, the oil-weighted nature of our assets allowed us to maintain extremely competitive margins. And with several key wells being restored or added in the near term, we are looking forward to a strong exit of 2023, and an exciting start to 2024. On the exploration front, Talos signed a joint venture agreement to reprocess seismic data over 400,000 acres, of which close to 100,000 acres is controlled by Talos in a prolific area in deepwater Gulf of Mexico. We hope to develop an inventory of prospects to drill over the next few years that could be tied back to Talos' infrastructure. This is an important development that we hope will generate significant value over time. In Mexico, we are excited about our partnership with Grupo Carso, a conglomerate publicly listed in Mexico. In late September, we closed a previously announced sale of a 49.9% minority equity stake in our Talos Mexico subsidiary, which holds a 17.4% working interest for approximately $75 million in cash at closing with an additional $50 million due upon first production for an aggregate price of $125 million. The deal is a baseline valuation for Talos Mexico of approximately $250 million while preserving significant upside to Talos' remaining 50.1%. We expect Talos' strong operational track record, combined with Carso's critical local presence and global commercial reputation, will enable us to further advance Zama toward FID and first oil. We are working hard to progress towards FID following completion and final review of the engineering design work or FEED, securing project financing and final approvals. We have always understood the importance this project has for local stakeholders in Mexico, and we are optimistic about the incremental value this project will create for our shareholders. Turning to our Talos Low Carbon Solutions business. We are pleased with our first EPA Class VI permit application submitted in August for our Harvest Bend CCS project, where Talos owns a 75% interest that received administrative completeness status in October. This first step of the EPA's permitting process indicates that the permit application contains all the required information. The next step is a technical review. Also in October, TLCS filed its second Class VI permit application for 2 additional wells at its Harvest Bend CCS project. TLCS aims to file additional Class VI permit applications in 2024 for its Bayou Bend CCS, Harvest Bend CCS, and Coastal Bend CCS projects. Our first Talos-operated well at Bayou Bend is expected to spud during the fourth quarter of 2023. As previously announced, the Bayou Bend partnership also expects to drill a Chevron-operated stratigraphic well in the first half of 2024. We welcomed Equinor to the Bayou Bend partnership following its purchase of a 25% interest from Carbonvert, a transaction that further underwrites the quality of our carbon storage portfolio in Southeast Texas. We are pleased with the news from the Department of Energy that they will invest up to $1.2 billion in a regional hydrogen hub in Texas, with the investment expected to be matched by key partners. This announcement outlines the benefits unique to the U.S. Gulf Coast and an expected unprecedented growth of hydrogen production from the region, which will require permanent CO2 sequestration. Bayou Bend is in an advantageous position to help bring this sequestration ambition to reality. We are continuing to explore capital raise for TLCS. We will continue to update the market as that process advances. While that is ongoing, we believe the operational execution in the carbon storage part will help create long-term value for shareholders and enhance the marketing process. Lastly, on the M&A front, we will continue to actively evaluate business development opportunities that fit our strategies and are accretive to our shareholders while preserving or improving our strong credit position. This spans tactical business development, bolt-on opportunities, and larger strategic transactions. In summary, it was a busy quarter, and we're pleased with the advancements we have made driving shareholder value creation in both our upstream and Low Carbon Solutions businesses. In addition, by focusing on operational execution, we successfully managed through the production and operation challenges associated with loop currents while continuing to use the excess free cash flow plus the proceeds secured in a partial sale of Mexico to keep our balance sheet in a healthy position. With these key updates in our 2023 plans and goals, I will turn the call over to Sergio to address our financial details for the third quarter.

Thank you, Tim, and good morning again, everyone. As a quick reminder that our consolidated results include the results of our upstream and low carbon solutions businesses as further detailed in our 10-Q filed yesterday. Appropriately, I will highlight these impacts in these different businesses in my discussion of the financials. During the quarter, Talos generated production of 63,700 barrels of oil equivalent per day which was 76% oil and 83% liquids. This led to $383 million in revenue and $255 million in adjusted EBITDA in our upstream business alone. That equates to an EBITDA netback margin of close to $45 per BOE, which we believe ranks high amongst public E&P companies. The company also reported a net loss for the quarter of approximately $2 million or $0.02 net loss per diluted share. Our adjusted net income during the quarter was approximately $19 million, $0.15 adjusted net income per diluted share. Capital expenditures, including plug and abandonment and settled decommissioning obligations during the third quarter were $181 million in our upstream business. We also invested about $14 million in our CCS business, leading to a positive free cash flow generation of about $9 million in the quarter. Additionally, we received approximately $75 million in cash from Grupo Carso when we closed the partial sale of Talos Mexico in late September. CapEx in the third quarter included spending on a few key items. First, we had ongoing operations related to completions, installation, and hookups for Venice and Lime Rock. Second, the quarter included significant decommissioning spending on an inherited third-party project, which primarily drove the $38 million of spending for the quarter in that category. As laid out in our 10-Q, this spending in the third quarter completed most of our book liabilities in this category, and we do not expect this spending trend in future quarters. Turning to our balance sheet. At the end of the third quarter, net debt stood at roughly $1 billion. The drawn balance on our RBL was $215 million on September 30, and liquidity remained very high at over $750 million. As we mentioned before, in September, we closed on the partial sale of Talos Mexico and received approximately $75 million in cash, and those proceeds were used to pay down the revolver. The increased investment activity in 2023 continues to drive an increased working capital requirement in the business which we expect to abate in the fourth quarter and into 2024 as we significantly slow our capital investment pace. I'll address more of that slowing down in just a few minutes. As of September 30, our leverage metrics stood at approximately 1.1x. I also wanted to provide a high-level overview of how we see the final months of the year progressing and how we're seeing 2024 shaping up. As outlined in our earnings release, we expect production for the fourth quarter to be between 66,500 and 68,500 barrels of oil equivalent per day, which puts us within the guidance range for the year but towards the low end of our full-year 2023 production guidance of 66,000 to 71,000 barrels of oil equivalent per day. For the full year of 2023, cash operating and G&A expenses are tracking towards the higher end of the current range of $410 million and $430 million and $90 million to $95 million, respectively. CapEx, including plug-in and abandonment, settled decommissioning obligations, and CCS investments are expected to be within our current guidance range. Specifically, our upstream CapEx, including drilling and completions, asset management, and other spending is tracking at the low end of the guided range of $650 million to $675 million. Our CCS investments are projected to be at or below the low end of the current range of $70 million to $90 million due to timing shifts of spending into 2024. As I mentioned in the last earnings call, plugging and abandonment spending for the full year on our portfolio is now estimated to be between $120 million to $130 million, primarily driven by inflationary pressures in that market as well as additional third-party decommissioning spending activity. We expect this category to normalize somewhat in 2024, and we will continue to fine-tune those estimates over the next few months. I'd also like to talk about how we're seeing 2024 starting to shape up. It's too early to go into specifics, but philosophically, we see next year's capital investments considerably lower than 2023. We continue to evaluate the right levels of reinvestments into our business, and we believe that taking our foot off the gas on the CapEx side and taking a breather is likely the right path for Talos next year. Despite this reduced investment, we still expect solid production growth next year, albeit with a tempered long-term growth trajectory. That allows us to increase near-term optionality for shareholder return, debt reduction, and inorganic growth opportunities. When weighing these options, we think this approach creates the most value for our shareholders. Overall, I'm very excited about the trajectory of the business as we look to 2024. Our credit position remains very strong, and we are excited about new production early next year from Venice and Lime Rock as well as attractive investment opportunities in both our upstream and CCS businesses. We believe the combination of attractive future events, a solid balance sheet, and an ever-present focus on M&A opportunities in line with our track record will deliver and accelerate long-term value to Talos shareholders. With that, operator, we'll open the line for Q&A.

The first question comes from Nate Pendleton from Stifel.

Good morning. Can you provide any thoughts on the further delay of announcements last week, specifically, how this impacts the industry and your expectations for any resolution there?

Yes. Look, it's interesting. We have part of the script and part of what we're talking about earlier is some progress from the Department of Energy on the CCS side. And it speaks to a little bit of a broader frustration when you have, I think, a government that's super supportive of one part of our industry and what we're doing to decarbonize, but then less supportive on the traditional forms of our energy. What we want and what we hope out of our regulators is they're not picking winners and losers. And so the frustration, obviously, on the offshore side is that it feels like they're doing that. Now again, the Inflation Reduction Act requires us to have lease sales coinciding with the same time frame as wind sales. We know this government wants that, and we certainly are supportive of that. We fully expect to have these lease sales. But it's very frustrating to see this particular issue around the leasing and the idea that there's kind of the migration path of the whales moved from the Eastern Gulf of Mexico, where they're typically found, to the Western Gulf of Mexico, and pulling out leasing. And so that's being fought by our trade groups and it's appropriate for them to do so. We expect that to come back, and we hope it will. I think further frustration is around the broad 5-year leasing plan where traditionally, that plan is always in place when the previous 5-year plan rolls out. This one was delayed 3 years into the administration, and then it's been kind of reinstated with less lease sales than the traditional plan. I think energy policy is important. I think it needs to be balanced. I'll say I applaud some of the things happening on the low carbon side, but we are equally frustrated at what feels punitive on the traditional side. But part of the Inflation Reduction Act mandated these lease sales. We are prepared to lease in the lease sale when it happens. We just got to go through this process.

Got it. And on the partnership with Repsol, can you provide any details about the earliest we could see any news from that reprocessing campaign? And if there are other opportunities similar to this one across your acreage?

Yes. Well, look, and I'm glad you brought that up. I can go on long dialogues around federal government energy policy and not bring it back to what we do about it. What you do about it is to partner with Repsol. What's interesting about that particular partnership is Repsol is coming to the table, not just wanting to participate financially and have a working interest in these projects. They want to actually participate in the geological interpretation of what's happening. They want to bring their expertise to bear and join us in trying to map through all this acreage. And we have a host facility in Neptune. This is a combination of EnVen acreage and Talos acreage. So it's a way that we're trying to pull value out of a transaction in acreage that we didn't allocate value in when we bought the transaction. So all of those are very positive. I think this is more long-term portfolio generation. These are types of prospects you see more in kind of the 2025 range and beyond. But it's absolutely the type of work that you need to do to make sure you're building inventory in the Gulf of Mexico. And when you have a built-in partner that's got that level of technical expertise, that's great. The second part of your question is, are there more to do? Yes, I think there's two types of opportunities. How do you find partners with the acreage you have? And again, when we closed, we were almost up to 1.5 million gross acres. And how do you pull acreage from other parties that also want to say, 'Look, I've got an acreage position, you have an acreage position. Let's pull that together and then let's try to build inventory out of our pooled acreage.' We're working on some of those as well, and hopefully, those will come to fruition in the coming months. So, there are two ways to approach it when you're trying to manage upcoming leasing or a lack of leasing, but you have a large acreage position. How do you find built-in partners and how do you pool acreage? We're trying to do both in our business development activities.

The next question comes from Michael Scialla from Stephens.

I wanted to get your decision to slow down here a bit. You were talking at one point about high single-digit production growth for a 3-year plan. You said you're tempering that a bit, but you still expect growth. So I want to see what you're thinking there. Is it low single-digit growth? And maybe any indication on what the lower activity might lead to relative to what you're doing this year in terms of spending?

Yes. Let me give you some initial thoughts on that, Michael. Sergio can follow up with any of his thoughts. Look, this year, we really spent a lot of effort. When you think about something like Venice and Lime Rock, we discovered those less than 12 months ago. So installing all that infrastructure, doing that inside a year has been fantastic, but it’s also a material amount of capital where you don't see any revenue and production generation out of that for a subsequent 12 months. I think we've had a rig on contract for the better part of the last 15 months, that will start to roll off when we wrap up this work with Venice and Lime Rock. We want to see 2024 to be a material cash flow generation year. We think the first step in that is to bring this new production online and kind of take our foot off the gas. We want to have a breather from a rig perspective, particularly in the first half of the year. Then as we think about the second half of the year, we’ll consider reinstating some of our operated drilling opportunities. You also have a rig market that's tightening. I think when reflecting on this, we look at our history in the basin. Those in the past who haven't made it sometimes did not hedge, took on too big of a working interest in the project, or took on a bad rig contract over a long period of time with the commodity turnaround. We don’t want to enter into a long-term rig contract at these inflated prices. We might have to work with where there are rig opportunities and rig openings. Between wanting to take a breather after a long rig contract that's rolling off, getting new production online, taking our time, and thinking about what's the right way to play the rig market when it's hot speak to coming off the capital program substantially year-over-year. We want to ensure we're spending our efforts on generating free cash flow, which we can use to pay down debt ahead of potential refinancing. We'll wrap those thoughts up with the Board in the coming months and roll out guidance for next year.

Got it. Okay. And I guess on your production, I realize the fourth quarter is impacted by nonoperated wells. Just wanted to get some more color on that. Is that intervention that the operator is talking about something that's fairly routine? Or do you see that as carrying some risk that could affect that well coming back online in the first quarter of ‘24?

Look, it's fairly routine. I mean, you have these big wells and these big completions, and from time to time, something might happen downhole that requires repair. It's a little different because you have to recycle that planning. If that happens in shallow water or onshore, you can get on that pretty quick. But in deepwater, it’s just a different planning exercise that takes more time. You have to figure out how that fits in with an intervention vessel or the rig you're using. It’s a different dynamic. But it’s a common practice. The idea that we have a large resource base and need to repair a well is something other companies experience throughout the year. I think we're fully confident that comes back online. Part of the guidance for the fourth quarter we could have been more specific about was when looking at bringing on Venice and Lime Rock in the first quarter, there's downtime related to ramping power to get those wells online. We're trying to accelerate that. We are seeing if there's a possibility we can sneak a little bit of that production into this year, which would push that downtime into this quarter. So there is a little bit of non-op well that we want to get back online. There’s 1,200 barrels a day, net to our interest on a full quarter run rate there, and some downtime related to ramping up production that if we can push that early into 2024, we can sneak that production a little bit into the exit rate.

Okay. That's helpful. And I wanted to just ask one last one on Zama. Where do you stand with the FEED work there now? I know at one point you were debating between the FPSO and fixed platform; where does that stand at this point?

Yes. Look, it's an active discussion. I think part of the challenge has been time lost, and it's unfortunate. The struggles around the initial formation of the unit are frustrating. We were giving up operatorship and then trying to claw that back into the partnership to build an integrated project team. We've talked about that. Keep in mind, when we were the operator, we had a different development plan that Pemex was proposing when they took over the operatorship, which had to be reviewed. Ultimately, the government reviewed that and approved the new blended plan, but some engineering details had to be started over. Pulling in the full unit through the process ultimately leads to changes in design, and that has to be thought through as we think about total capital and financing. Time was lost there, but we’re glad we’re back on track, and happy to have Carson involved. I think we’re probably at a better place with that asset and partnership than we have been. There’s still some work to do to get that project to FID, which is important for stakeholders and our shareholders. We’re pleased we’ve been able to monetize and realize some value.

The next question comes from Subasish Chandra from the Benchmark Company.

Just curious, as you have these 4Q events, these wells plus, of course, Lime Rock and Venice. What do you sort of anticipate as a base level of production, one that might not be subject to downtime, some of the 3Q hurricane effects, etc.? But is there a number that you might bounce offloads?

Well, Subasish, thanks for calling. It’s difficult to find that perfect run rate in the Gulf of Mexico. I’ve always said there’s a characteristic of this basin that, just by nature—and we answered in the last kind of question a little bit—you have something that when you have downtime, bringing it back online isn’t as quick as you see with some onshore operations or even back decades ago when the predominant portfolio was in shallow water. It’s a little bit tough to answer. Obviously, the second quarter was a cleaner quarter; we were in the 70s there, so good weather typically yields better results. I think we know what a clean quarter looks like. Projects we’re trying to add on have a mix of potential non-op production, which is another reason we think we should focus on free cash flow generation and not feel compelled to go at the pace we’ve been at the last couple of quarters in the first half of next year.

Right. So as you’re looking ahead to the outlook for substantially lower CapEx, is that sort of an upstream comment that might be partly offset by CCS spend? Or is that an enterprise comment?

I think it’s more an enterprise comment. Look, last year, we generated a significant amount of free cash flow, paying down our debt close to $4 to $5 per share. This year, we knew we would not generate as much as we really focused on the capital program. We’ve seen a bubble in plugging and abandonment activity connected to some bankruptcies. With this year not generating much free cash flow, we want to return to that. That’s our primary focus. I think it’s mutually exclusive to CCS. Robin and her team have their own processes around that, and there’s a method to monetizing that business as well. I would call those separate. I think broadly for our enterprise perspective, our focus is on ensuring the upstream business generates the right levels of free cash flow knowing this year was a year of acceleration.

Just one final one, if I can. The number one question out there onshore is M&A. So we would like to give you an opportunity as well to comment on the offshore outlook for that.

Look, we get it. We understand how people are thinking about it. It starts with that free cash flow generation comment. We want a business that generates material amounts of free cash flow. We want, as we grow, to have assets that are accretive to that goal, we know we need to scale and size. As executives, we understand the model. M&A fits into that model if it adds appropriate types of scale and diversity. Our skill set is conventional geology, offshore operations, and life cycles. If you step back and think about our basin, we believe it has sellers, ultimately. They may not be sellers in the next 6 months, but majors may not want to own some of their assets across their life cycle. They may want to decarbonize or not reinvest at the rates of 10 years ago. The Gulf presents a great roll-up play. They’ll want a trusted counterparty, and we think we pass that test. We just can’t predict when that opportunity will arise. We’ve discussed looking outside the Gulf of Mexico as well. I think there are diverse sets of opportunities that are sustainable over the long run versus being in one unconventional play with a limited roll-up potential. I’m bullish long-term on M&A relative to our strategy, but predicting that from quarter-to-quarter and year-to-year is challenging.

Our next question comes from Jeff Robertson from Water Tower Research.

Tim, a follow-up question on the Repsol joint venture. I think Talos is contributing about 97,000 acres to the 400,000-acre joint venture. Is Repsol contributing acreage? Is it an AMI in the area where you all identify prospects you'll go and try to get the acreage? Can you talk about the mechanics of that?

Right. It's a combination of really more our acreage and more of an AMI concept. That's exactly right. That's how you should think about it. So we put a big halo around where our acreage is and where our key facilities are. Amongst this area, let's go out and think about generating inside that area. We want to find new opportunities around that broader AMI as well. I don’t believe I should double-check if they’re contributing acreage. But really, we have close to 100,000 acres. We’ve set a halo around that, commensurate with how you think about reprocessing seismic data, ensuring the appropriate imaging coverage.

And with respect to M&A, are you seeing things? Or do you not necessarily see things today with some of the consolidation that's taking place in the industry? Do you think that opportunities will present themselves in the Gulf of Mexico that Talos wants to have the strongest possible position to just have options?

Yes. For sure. Part of wanting to make sure we keep leverage where it needs to be is maintaining appropriate liquidity. I think even next year, the first use of proceeds on free cash flow will be to ensure we pay down debt. Then we can think about capital allocation ideas of reinvesting in the business and having liquidity for M&A. Some of these combinations highlight that directly. We do not know where that plays out. I find the Chevron and Hess combination fascinating. The Gulf of Mexico is critical for Chevron. But what’s the right asset mix for a company like Chevron? We don’t know the answer. But what we do see, if and when they might consider M&A on the asset side, they may seek cash and a trusted counterparty. We must be prepared to fulfill that test while we also look at M&A ideas that might provide more flexibility. So we’re thinking about it. We understand the current trends. We’re not rushing into anything, but we need to be ready for how we can build out the firm and generate a sustainable shareholder return model.

And a question on the CCS business. Does Equinor add anything that makes that project more marketable to potential anchor customers? And can you just, or maybe, Robin, provide an update on where commercial discussions are with potential emitters?

Yes. I'm going to hand over to Rob. The initial idea was to set it up to attract strategics. Not too different from what we just did in acreage. We want a strategic involved to share the risk with us. Equinor brings long-term experience and expertise, certainly encouraging for us. Both of our large partners also have the capacity to invest in other blue commodities. So that’s exciting. The Department of Energy grant to the high-velocity hub surrounding Southeast Texas and Southwest Louisiana is very encouraging. This will create an integrated hydrogen ecosystem where there will be more investment coming into not just green hydrogen but retrofitting existing gray hydrogen facilities and encouraging new blue hydrogen facilities where CO2 capture is incorporated from the start. We’re having ongoing discussions with emitters to address their emissions.

Yes. Both partners have ongoing projects worldwide. Equinor is pioneering CCS in the Northeast. This is encouraging as we think about customers, given the Department of Energy grant. We have discussions ongoing with both brownfield facilities addressing CO2 emissions and new greenfield investments. We're very excited about progressing this project. We're also expecting to drill that first stratigraphic well later this year offshore, which will help supplement our first permit application hopefully in 2024.

Thanks. Tim or Robin, how long does it take to gather the data once you've drilled that well that you need to put in a permit application?

Some of that data will be captured on site. We’ll be logging the well itself and collecting core data. We’ll take some of that core to participate in the CCS consortium for review. We’ll gather some of that data in real-time as we’re on location. It will supplement what we’ve filed. We already have the seismic coverage and a model built as part of the initial bid in 2021. This is for confirmation and supplementary purposes to help with the EPA process, eventually leading to the Texas Railroad Commission when the state achieves primacy.

This concludes our question-and-answer session. I would like now to turn the conference back over to Tim Duncan for any closing remarks.

Thanks for joining the call, everybody. One of the themes this quarter is that the third quarter is always a noisy quarter with respect to potential downtime related to weather. We’re trying to have a strong exit, pulling as much value forward as we can, and getting some wells online. This year has been about blocking and tackling for long-term value. Next year, I think we will focus on generating materially more free cash flow than this year, which has been a moving year. We’re happy with where the business is. There’s much work to do, and we are focused. We’re looking forward to a strong exit and a robust start to 2024. Thank you for joining.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.