Hello, and welcome to the Talos Energy third quarter 2023 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touchtone phone. Please note this event is being recorded. I would like now to turn 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. 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'll 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 two additional wells. 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, if successful, could bring in 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 non-operated projects with our partners in the basin. The Marmalard well, operated by Murphy, found pay and 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 Claiborne #1 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-I and associated infrastructure in the Phoenix and Tornado fields. The impact of these Loop Currents caused a deferral of approximately 2.4 thousand barrels of oil equivalent per day for the quarter in the Phoenix field, or 0.8 thousand barrels of oil equivalent per day for the full year of 2023. The issues have since abated and production from the field is back online. The Claiborne non-operated well was also shut in during the quarter, contributing to an additional 1.2 thousand 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 exciting start to 2024. On the exploration front, Talos and Repsol 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's 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 in Zama 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 established a baseline valuation for Talos Mexico of approximately $250 million, while preserving significant upside to Talos's remaining 50.1%. We expect Talos's 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 that our first EPA Class VI permit application, submitted in August for our Harvest Bend CCS project, where Talos owns a 60% interest, received administrative completeness status in October. This first step of the EPA's permitting process determines that the permit application contains all the required information. The next step is the technical review. Also, in October, TLCS filed its second Class VI permit application for two 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 offshore stratigraphic 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 onshore stratigraphic well in the first half of 2024. We also 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 by 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 and unprecedented growth in blue hydrogen production from the region, which will require permanent CO₂ sequestration. Bayou Bend is in an advantaged position to help bring this this sequestration ambition to reality. We are continuing to explore a 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 portfolio 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 skill sets and strategies, are accretive to our shareholders, and preserve or improve 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 the 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 covered in our 10-Q filed yesterday. Where appropriate, I will highlight these impacts in these different businesses in my discussion of the financials. During the quarter, Talos generated production of 63.7 thousand 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 Netb ack Margin of close to $45 per BOE, which we believe ranks very 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, or $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 the 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 booked 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 66,500-68,500 barrels of oil equivalent per day, which puts us within guidance range for the year, but towards the low end of our full year 2023 production guidance of 66,000-71,000 barrels of oil equivalent per day. For the full year of 2023, cash operating and G&A expenses are tracking toward the lower half of the current range of $410 million-$430 million, and $90 million-$95 million, respectively. CapEx, including plug 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-$675 million. Our CCS investments are projected to be at or below the low end of the current range of $70 million-$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 coming in higher. It is now estimated to be between $120 million-$130 million, primarily driven by inflationary pressures in that market, as well as additional third-party decommissioning spending activity. We expect this category will normalize some in 2024, but 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 investment substantially 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, as well as organic 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 investment, 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. We will now begin the question-and-answer session. To ask a question, you may press Star, then one on your touch-tone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press Star, then two. At this time, we will pause momentarily to assemble our roster. The first question comes from Nate Pendleton from Stifel. Please go ahead. Good morning. Morning. Morning. Can you provide any thoughts on the further delay of Lease Sale 261 announced last week, specifically how this impacts the industry and your expectations for any resolution there? Yeah, you know, look, it's interesting. It's 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 the 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, you know, the frustration, obviously, on the offshore side of the house, again, that's Interior, is that it feels like they're doing that. Now, again, the Inflation Reduction Act and IRA requires us having lease sales coinciding within the same year timeframe as wind sales, and we know this government wants to have wind sales, and we certainly, you know, are supportive of that, and so we fully expect to have these lease sales. But very frustrating to see, you know, this particular issue around the Rice's Whale and the idea that there's, you know, kind of the migration paths of the whales move from the eastern Gulf of Mexico, where they're typically found, to the western Gulf of Mexico and arbitrarily drawing a line across the basin and then 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. You know, I think, you know, kind of further frustration is around the broad five-year leasing plan, where, you know, traditionally that plan is always in place when the previous five-year plan rolls out. This one was delayed, you know, three years into the administration, and then it's been, you know, kind of reinstated with less lease sales than the traditional plan. So, you know, look, I think energy policy is important. I think it needs to be balanced. I think we all, you know, see and applaud some of the things happening on the low-carbon side, and I think we're equally frustrated at what feels punitive on the traditional side. But again, part of, part of the Inflation Reduction Act mandated these lease sales. We're prepared to lease in the upcoming lease sale, kind of when it happens. ... We just got to go through this process. Got it. Thanks for the detail. 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 that one across your acreage? Yeah, well, look, and I'm glad you brought that up. I can kind of, kind of go on long dialogues around federal government energy policy and not bring it back to where, you know, what do you do about it? And what you do about it is things of what we're doing with Repsol. And so 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, you know, 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 an acreage set that we didn't allocate value in when we bought the transaction. So all of those are very positive. But look, I think this is more longer-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, you know, 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. You know, the second part of your question, which is, are there more to do? Yeah, I think, you know, there's two types to JVs. How do you find partners with the acreage you have? And again, you know, when we closed EnV en we were almost up to 1.5 million gross acres. And then 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." And we're working some of those as well, and hopefully, those will, you know, come to fruition in the coming months. So two ways to play it when you're trying to manage upcoming leasing or a lack of leasing, but you have a large acreage position. Everybody else has, you know, kind of similar challenges and opportunities. How do you find built-in partners, and how do you pull acreage? We're trying to do both in our business development activities. All right. Thanks for taking my questions. You got it. The next question comes from Michael Scialla from Stephens. Please go ahead. Yeah. Good morning, everybody. Wanted to investigate your decision to slow down here a bit. You were talking at one point about high single-digit production growth for a three-year plan. You said you're tempering that a bit, but you still expect growth. So, want to see if what you're thinking there. Is it a 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? Yeah, let me, let me give you some initial thoughts on that, Michael. Sergio can follow up with any, any of his thoughts. You know, look, this year really spent a lot of effort. When you think about something like Venice and Lime Rock, you know, we discovered that less than 12 months ago. So installing all that infrastructure, doing that inside a year, it's been fantastic, but it's also a material amount of capital where you don't see any revenue and production generation out of that, you know, for a subsequent 12 months. And so I think, you know, 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, and I think we want to see 2024 to be a material cash flow generation year. We think the first thing, the first step in that is as we bring this new production on, you know, kind of take our foot off the gas, have a breather from a rig perspective, particularly in the first half of the year. Then as we kinda think about the second half of the year, right now, let's kinda reinstate some of our operated drilling, you know, kind of opportunities. You also have a rig market that's tightening, and I do think as we think about that, you know, we look at, you know, one reason we've always kind of been a survivor in this basin and someone who's grown and thrived in this basin, is you look at those in the past who didn't make it, and sometimes it's because they didn't hedge, sometimes it's because they took on too big of a working interest in a project. Sometimes they just took on a bad rig contract over a long period of time, and the commodity turned around. So, you know, we haven't wanted to walk into a, you know, a long-term rig contract at these inflated prices, and so we might have to work with where there's rig opportunities and rig openings. So between, you know, wanting to take a breather after a long-dated 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, you know, when it's hot, I think that just speaks to coming off the capital program substantially year-over-year and making sure we're really spending our efforts at generating free cash flow, you know, which we can use to pay down debt ahead of potential refinancing. So all sorts of ways to think about it. Look, as we wrap that up and those thoughts with the board in the coming months and kind of roll out guidance for next year, you know, we'll think about how that impacts kinda broader production growth just on an absolute basis, but I think it's really around free cash flow generation in the near term. Got it. Okay. I guess on your production, I realize the fourth quarter is impacted by, you know, non-operated well. Just wanted to get some more color on that if you could. Is that intervention that the operator is talking about there something that's fairly routine, or do you see that as carrying some risk that could affect the well coming back online in the first quarter of 2024? You know, look, it's fairly routine. I mean, you have, you know, these big wells and these big completions, and from time to time, you know, you might have something happen downhole that requires either repair or sidetrack. You know, obviously a little different because you got to recycle that planning. If that happened in shallow water, if that happened onshore, you can get on that pretty quick. It's pretty easy to move around resources and do that. When you do it in deepwater, it's just a different planning exercise. It takes more time. You've got to figure out how that typically fits in an intervention vessel or the rig you're using. So it's just a different dynamic. But the idea that, hey, look, we've got a, we got a large resource base.... And we want to either repair a well or sidetrack a well, you know. Look, that happens, I think, in everyone's portfolio through the course of the year. And so, I think we're fully confident that comes back online. But, you know, Mike, part of the guide on the fourth quarter, and we could have, we probably should have been a little more specific about this, was, you know, when we looked at bringing on Venice and Lime Rock in the first quarter, there's downtime related to ramp out to get those wells online. We're trying to accelerate that. We're actually, you know, seeing if there's a possibility we can sneak a little bit of that into the last parts of this year, which then pushes that downtime into this quarter. So there's a little bit of certainly a non-op well that we want to get back online. There's 1,200-1,300 b arrels a day, you know, net to our interest on a full quarter run rate there. And then there's some downtime related to ramp out that if we can push that really early into 2024, push that production, sneak a little bit into the exit rate, that downtime shifts into the fourth quarter. Okay, that's helpful. Then I wanted to just ask one last one on Zama. Where do you stand with the FEED work there now? And I know at one point you were debating between the FPSO and fixed platform. Where's that, how does that look at this point? Yeah, look, it's an active discussion. I mean, I think, you know, part of the challenge in this has been, you know, time was lost, and it's unfortunate. And the struggles around the initial formation of the unit, our views on that, obviously, fairly well documented, you know, frustration that we were giving up operatorship, and then how do we kind of claw that back into the partnership to where, you know, we can build an integrated project team. And again, we've talked about that. Keep in mind, you know, when we were operator, we had a different development plan than PEMEX was proposing when they took over operatorship, and then we had to come up with a blend of that. Ultimately, the government reviewed that, and they approved the new blended plan, but there's some engineering details that underneath that, that we had to start over with. And so, you know, part of the, part of the pulling in the full unit and, and going through the process, you know, ultimately led to changes in the design, and some of that has to be, you know, kind of brought through the feed. And then now, now it has to be thought through as we think about, you know, total capital and financing. So, you know, some time was lost there, frustrated around that. Happy, though, that, that we're back on track. Happy to have Carso in. I think we're probably at a better place with that asset and with that partnership than we've ever been. Certainly, some of the debates and some of the frustration is behind us, and so now it's really more about a key focus on what do we need to do to wrap up. Still a little work there. Look, next year is an important year for that asset. It's certainly been long enough. It's time to kind of get that thing to FID. It's time to get the ball moving on that. It's important to a lot of stakeholders. It's important to our shareholders. We're glad we've been able to monetize and realize some value, but, you know, we've got some work to do to get that kind of in the right spot. And again, I think we're in a better place with that asset than we've been in the last couple of years. Okay, great. Thanks, Tim. Thanks, Mike. The next question comes from Subash Chandra from The Benchmark Company. Please go ahead. Hey, good morning, Tim. Just curious, you know, as you have these 4 Q events, these wells, plus, of course, Lime Rock, Venice, what do you sort of anticipate as a base level of production? You know, one that might not be subject to downtime, some of the, you know, 3 Q hurricane effects, et cetera, et cetera, but is sort of a number that you might bounce around off those? Well, you know, Subash, thanks for calling. You know, it's, look, it's difficult to always find that perfect run rate in the Gulf of Mexico. I've always kind of said in the past, you know, there's, it's a basin where just by the nature of... And we answered in the last kind of question a little bit, you know, you have something that when you have downtime, the ability to bring that back online isn't as quick as you see with some of the onshore operations or even back, you know, 20 years ago when the, you know, kind of the predominant round of our portfolio was in shallow water. So it's a little bit, you know, kind of tough to answer. Obviously, you know, second quarter was a cleaner quarter. We were in the low 70s there, you know, and so good weather and typically a little cleaner. So I think we know what a clean quarter looks like. I think we know what projects we're trying to add on, and then you kind of have these downtimes. A nd sometimes that downtime can be, you know, 2%-3% in a quarter, sometimes it can be 10% in a quarter. The third quarter is always tricky, you know, and what we're learning is, you know, Loop Currents, which generally around El Niño, are, you know, that's now going to be forecasted into weather-related downtime. And so, I think the second quarter was a relatively clean quarter. It's a good way to anchor things. And then you have kind of what's the decline and then how do you stack on from there, you know? And again, we have some things we're stacking on in the near term, more than just Venice and Lime Rock. The reason we put in some of those non-ops, and although smaller impact, smaller working interests, but we have three or four different operators out there actively in these activities. We had a nice little development well work over the weekend that also stack on into 2024, which is another reason why we think we should focus on free cash flow generation and don't feel compelled to have to go at the pace we've been going at for the last two quarters in the first half of next year. But, you know, I think second quarter was a good place to start, and then it's really what are we adding on in the next, what I would call, three or four months. But as we look out in the total year, as we pull CapEx down next year, it may change how we think about the full year outlook, but we got to really wrap up that program. Okay, right. So as you, I guess the outlook for substantially lower CapEx, is that a sort of an upstream comment that might be partly offset by a CCS spend, or is that an enterprise comment? ... I think more, look, I think more of an enterprise comment. I mean, you know, look, I think this year, as we last year, in 2022, we generated a significant amount of free cash flow, paid down our debt at close to $4-$5 a, you know, a share or something of that nature. This year, we knew we weren't going to generate as much as we really focused the capital program on putting some things online. And then we saw a little bit of a bubble in PNA with some non-op related stuff, you know, kind of associated with some bankruptcies. And so, you know, when you have a year, which I think we've done a pretty good job managing expenses and a pretty good job managing capital, and, you know, so I want to make sure I make that point. But when you have a year where you're not generating as much free cash flow, you want to see yourself go back to that. And so that's the focus. And I think that's the focus somewhat mutually exclusive than CCS. You know, Robin and her team, and we're happy to take questions around that, are executing that, and there's a process around monetizing, you know, and bringing some value forward on that business as well. I would call those separate. I think, I think broadly from an enterprise perspective, you know, how do we make sure the upstream business is generating the right levels of free cash flow, knowing that this was a year where we were going to really accelerate capital into some developments? We don't have to do that next year. You've got a rising rig market. How do we want to manage all that and make sure that, you know, we're putting our shareholders in a place where we can be opportunistic, as we were in some moments this year on buybacks and things of that nature? Hey, Tim, just one final one, if I can. So, you know, number one question out there, onshore is M&A. So would like to give you an opportunity as well, or Andy, to comment what the offshore outlook looks like. I mean, you know, look, we get it. You know, we understand how people are thinking about it. We, you know, it starts with that free cash flow generation comment. I mean, we want to have a business that's generating material amounts of free cash flow. We want, you know, as we grow that business, to have, as we add assets, to be accretive to that goal. We know we want to scale in size. It's going to deliver capital back to shareholders. I mean, I think we all, as executives, understand what the model is, and M&A ultimately fits into that model if it can add the appropriate types of scale and diversity. Now, our skill set is conventional geology, it's offshore operations, it's full life cycle. If you step back from that and you think about our basin, you know, we think our basin is filled with sellers ultimately. They may not be sellers in the next 6 months, but the majors may not want to own some of their assets across the life cycle. They may want to decarbonize, they may not be reinvesting at the rates they did 10 years ago. And so we actually think the Gulf is a great role at play, and they've got to have a trusted counterparty, and we think we've passed that test. These guys are partners with us in our wells. We just can't predict when that's going to be. We've talked about looking outside the Gulf of Mexico, because, again, I think there's, you know, other companies thinking about this the same way we are. And so, you know, I would say when you look at our, our skill set and you look at where we can transfer that skill set, I think it's in a pretty broad and diverse set of opportunities that are sustainable over the long run versus being in one unconventional play where you can see the ceiling of what's available for you to roll up. So I'm, I'm bullish long term on how we think about M&A relative to our strategy and relative to our skill set. From quarter to quarter and year to year, you just can't predict exactly how that's going to go. Thank you. Our next question comes from Jeff Robertson from Water Tower Research. Please go ahead. Thanks. Good morning. 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? Yeah. If 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 you know 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, and we say, look, you know, amongst this area, let's go out and think about generating inside that acreage set, you know, and then let's think about finding new opportunities around that broader AMI. So it's a simple concept. I don't believe, and I should double-check, they're contributing acreage, but you know really it's we have close to 100,000 acres. We put a halo around that, and part of that's you know commensurate with how you think about reprocessing seismic data so you got the appropriate coverage from just a you know from a from an imaging perspective. And then how do we want to kind of develop inventory around that entire kind of area of mutual interest or AMI, for those that aren't familiar with the concept. So, that's how this comes together, Jeff. And with respect to M&A, are you seeing things or do you... Not necessarily seeing things today, but 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 balance sheet possible to just have options? Yeah. Yeah, for sure. I mean, look, I mean, part of, you know, wanting to make sure that we keep the leverage stat where it needs to be, we try to, you know, have the appropriate levels of liquidity. I think even next year, you know, I think what's the first use of proceeds on free cash flow? It's going to make sure we pay down debt, you know, and then we can think of all the other capital allocation ideas of reinvesting in the business, having liquidity available for M&A. And look, in some of these combinations, they're speaking to it directly, you know, and so we don't know where that plays out. I think, you know, for example, Chevron and Hess is a fascinating combination. I'm a, I'm a Hess alumni. I think they certainly, you know, the Gulf of Mexico is a core area for Chevron, but ultimately, what is the right asset mix for a company like Chevron, for a company like Exxon? You don't know the answer to that, but you do know that if and when they might want to think about M&A, particularly on the asset side, they're probably going to want cash, and they're going to need a counterparty that they trust. And what we have to do is be available to pass that test. While we look at other M&A ideas that might have more flexibility on sources and uses. So you know, we're thinking about it. Look, we certainly understand why you see the current trends.... We're not rushing into anything, but we have to be prepared to be thoughtful on how we build out the firm and get to where, you know, we have a platform that's got more scale and diversity and ultimately leads to a shareholder return model that's sustainable. A question on the CCS business. Does Equinor add anything that makes that project more marketable to potential anchor customers? Or maybe Robin, can you provide an update on where commercial discussions are with potential emitters? Well, let me. Yeah, look, I'm going to hand it over to Robin. I think real quick on the conversation around Equinor, and then Robin will take it and provide her thoughts. You know, when we set this up, I think the initial idea was setting it up in a way that it attracted the strategics, if you will. You know, not too different from what we just did, you know, in acreage. We can put together an acreage position, but we're not going to go drill that $100 million subsalt well. You know, we want a strategic involved in that with us to share that risk with us. And so, you know, Chevron came in, now Equinor came in. So it's great to have the strategics there, and Robin can talk about the benefits they bring when we think about conversations with emitters and execution. Yeah, both partners have projects that are ongoing around the world. I mean, Equinor is one of the pioneers in CCS there in the North Sea. So certainly bringing that long-term experience and expertise to the project is a really great and encouraging thing. You know, both of our large partners too have the ability to go and invest in some of these other blue commodities as well. So I think that's exciting. The announcement of the Department of Energy's grant to the Hy Velocity Hub, which is around the Southeast Texas and Southwest Louisiana region, is very encouraging as we think about the counterparties here, the customers. What that grant will do is basically providing that integrated hydrogen ecosystem, where we've got more investment coming into not just, green hydrogen, but also being able to retrofit existing gray hydrogen facilities, and encouraging additional investment in new blue hydrogen facilities, where the, the CO2 capture is actually designed on the front end. And so we're having discussions with folks, out of both categories as we're thinking about, brownfield facilities, being able to address their CO2 emissions and some new greenfield investment. And so those are—those conversations are ongoing, and we've got, quite a few of those. So we're very excited about continuing to advance that project, and as we mentioned in our release, still expecting to go drill that first stratigraphic well later this year in the offshore portion, which will help supplement our first permit for that project, hopefully sometime in 2024. Thanks. Tim or Robin, how long does it take to gather the data once you've drilled a strat well to... 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 some core data. We'll take some of that core back. We're participating in the CCS consortium that Core Lab has, so they'll be reviewing some of that. But we'll get some of that data in real time as we're on the location. Again, it's more supplementary to what we'd be filing. We already have the seismic coverage. We've got a model built. In fact, that was part of our initial bid on that offshore General Land Office lease back in 2021. So we, we've got a great data set up there. This is more confirmatory and to really help supplement that application process as it goes into EPA and then hopefully, eventually, the Texas Railroad Commission, as the state achieves primacy down the road. Thank you. The next question comes from Noel Parks from Tuohy Brothers. Please go ahead. Hi, good morning. Morning, Noel. Morning. So just a couple of things. One thing I was thinking about is just the tiebacks that you have are so attractive from a capital efficiency standpoint. I wonder, as you just were looking at planning over the next few years, you know, what sort of inflation have you baked in or assumed as you look at some of these projects? I wonder if even Lime Rock and Venice, where they pretty much set in motion, you know, contracted before the impact of the most recent inflation, or are they examples of something also that, you know, that might also be burdened by them? You know, I think it's look, a lot of it's largely driven by rig and the ancillary services around those rigs. You need the rigs to drill them, you need the rigs, you know, obviously, to complete them, and then some of the ancillary services around vessels related to subsea projects, you know, and things of that nature. And look, there's a, you know, there's demand around global subsea infrastructure installation. You're seeing it in areas like Guyana, you're seeing it in areas like West Africa. So, you know, we certainly have to adapt to the market. I do think, you know, these time frames are typically, when you think of these projects, you're thinking about them in, you know, somewhere between 18-month windows, 24-month windows. Now, again, Venice and Lime Rock, we accelerated. We did that because, you know, we had long leads, and so once those are secured, you're not thinking about the inflation of tubulars and things of that nature. So I do think one of the reasons we want to be thoughtful around the next round, and when we have an inventory that's got some quicker hookups, some development, and then some broader exploitation and exploration, you've got to adjust to where that's going. And I think for us to say, "Hey, look, while we've been working really hard this year and had rigs on contract for the last 15-18 months, let's just step right into, you know, where the rig market's going." I think our idea is, hey, look, let's take a pause in the first half of the year. There's going to be some activity, but not as much operated activity. And then let's think about, you know, where this rig market's going and how do we play in it? And I don't think we play in it by being afraid of slowing down and feeling like we have to speed up, and then we have to go take a contract over multiple, multiple years at, at a rate we haven't seen in the last 10 years. That's not probably the right, responsible risk management decision for a company our size. So, you know, we do think about inflation. We think about where, you know, if we're gonna spud something in 2025, where do we think the market's gonna be in 2025? And, and, you know, and so we do that from a planning perspective. Sometimes you wanna see, look, if we take our foot off the gas and maybe others, does that, does that create, you know, maybe a, a flattening of that market? But, you know, there's a little why don't we wait and see, and if by waiting and seeing, we gotta grab some windows instead of grabbing two-year contracts, then we grab some windows. Right. Well, thanks. I hadn't even been thinking of the sort of cooling next year of your spending around uncertainty in the service environment. But as you say it, it's like... It seems like we're clearly entering one of the most uncertain environments we've seen in a while, because we've, of course, had this huge run-up and then, and now, sort of unprecedented interest rate environment, you know, shift, with us now looking ahead and, you know, with China and everything, some pretty serious concern about, you know, maybe now is when the recession hits. So, yeah, all those combined certainly makes sense. And so I think maybe you're maybe even ahead of some of some other players in the industry with that thinking. Well, I mean, look, I, I think it's just more, what are the things, what are the risks that you need to manage? Again, we're not a large cap. We don't have 250,000 barrels of oil equivalent a day. We don't, you know. That's, that's what we aspire to become ultimately, but we are where we are. We're a company that was founded, you know, 10 years ago. And as we built these things in the Gulf of Mexico, we know where that risk management needs to look like. You need to have appropriate hedges. We've layered on some in the fourth quarter when we had a run-up in prices, and we still have a constructive price environment. But you need to protect yourself from a commodity perspective. You need to protect yourself, you know, from a capital allocation perspective and a contract risk perspective. And those that haven't in the past haven't made it. And we've seen that, and that's not an offshore phenomenon. That's an onshore and offshore phenomenon. We've talked in the past, I think there's been over 300 bankruptcies in the last decade since we started this company. So, you know, we think about that risk management a lot. And again, I don't. I think we have to be mindful of where the market is, and if that changes, a little bit of the trajectory of production growth ultimately brings down CapEx, but still generates meaningful cash flow. That's the right risk management strategy if you do have a little bit of uncertainty on what the Fed's doing and things of that nature. I think generally, we're constructive around the commodity. I think this is just what's appropriate risk management. Right. Well, thanks a lot for the perspective. Yep, you got it. The next question comes from Kyle May from Sidoti & Company. Please go ahead. Hey, good morning, everyone. Good morning. So a couple of questions around, A couple of questions around the CCS business, for, for Tim or Robin. You mentioned the first Class VI permit at Harvest Bend reached administrative completeness. Can you give us an update on the overall expected timeline for a Class VI permit now? And then, what are the next steps for Harvest Bend? Yeah, sure, Kyle. I appreciate the question. So yeah, we filed our first application there at Harvest Bend in October. We received that administrative completeness, and so now it's entering what's called technical review. So we think that could last probably the next 12 or so months as they go through the details of that first permit. We did receive some early comments back on that first permit that we were able to incorporate some of that feedback into our second permit, which was for an additional two wells. So we now have three wells sitting with EPA, but also keeping in mind, we co-submitted that through the Louisiana Department of Natural Resources template as well. So we're all set up, hopefully, as the state achieves primacy sometime next year, for a very smooth transition over to that regulatory agency. Again, the plus of primacy is you've got a state that knows their geology very well, lots of resources, and we've seen demonstrated in the two states that have it, the speed of that turnaround to really increase. You know, North Dakota has actually a CCS project that just started up this past week after a permit made it through in less than six months. So we're very encouraged that when the states take over, we can get these onto a more timely timeline. But regardless, even if it's two or three years to process through EPA, it fits within our overall project timeline. Got it. Got it. And then at Bayou Bend, you're planning to spud another or planning to spud the first well in the fourth quarter. What's the estimated cost for a well now, and how long do you think that's gonna take? Yes, so we'll be spudding that first stratigraphic test well. This is a data acquisition well, where we're gonna be doing pretty extensive logging and core collection, again, to help calibrate our model, but really supplement that first application. That'll go to EPA and also eventually into the Railroad Commission, as we'll take a similar approach there, keeping both agencies in the loop. As far as the cost there, I mean, it's just, it's gonna depend. For that one being offshore, obviously, there's a little bit more costly to get a jackup rig to go drill that. In fact, that's what we're waiting on right now, is the rig is still with another operator. As you do these onshore, they're fairly straightforward wellbores. We're talking a vertical wellbore from the range of 6,000-8,000 feet. So nothing very sophisticated in that. The main cost difference will be if we decide for these wells to become keeper wells, where we're gonna reutilize that wellbore for either monitoring an injector, because if we do that, we'll run a corrosion-resistant pipe in those sections, or if it's just a pure data acquisition well, you can just suspend the well and P&A, it would be much less costly. You know, so it'll really depend on where we're at and what that is, but as far as the overall investment in these CCS projects, the drilling of the wells is one of the smallest pieces. Okay, great. Thanks, Robin. 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, and thanks for joining the call, everybody. I think, you know, one of the themes of this quarter is obviously, you know, third quarter is always a noisy quarter with respect to potential downtimes related to weather. We saw that. We're trying to have a strong exit. We're pulling as much value forward as we can. We're trying to get some wells online. We're trying to pull value forward in our TLCS business. We've pulled value forward in our, in our Mexican asset. And so I think it's been a year of really trying to do the blocking and tackling that it's gonna take to create long-term value. And so you-- we've talked about next year. Next year, I think we're gonna focus our attention on materially more free cash flow generation than this year, as we've, you know, had what, what I would call a moving year. So, you know, I think we're happy with where the business is. You know, there's a lot of work to do. There's a lot of things to get online, a lot of more value to pull forward. But I think we're trying to do the right things. And as we think about joint venture structuring, on building long-term, long-term inventory development, as we think about the initiatives, again, to pull value forward on these catalysts, I think the team's doing the things it needs to do that's gonna generate value. We're looking forward to kind of a strong exit and a robust start to 2024 and being in touch with the investor community on how that's going. Thanks for joining the call. The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.