Talos Energy Inc. (TALO) Q2 2023 Earnings Report, Transcript and Summary

Good day, and welcome to the Talos Energy Second Quarter 2023 Earnings Conference Call. [Operator Instructions]. Please note, this event is being recorded. I would now like to turn the conference over to Sergio Maiworm, Senior Vice President and Chief Financial Officer. Please go ahead.

Thank you, operator. Good morning, everyone, and welcome to our second 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 get started, I'd like to take this opportunity 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 in 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 the call, we may present GAAP and non-GAAP financial measures. A reconciliation of GAAP to non-GAAP measures was included in yesterday's press release, which was 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. Before I begin, I want to congratulate Sergio in his new role as our Chief Financial Officer. Sergio has been in a leadership role at Talos since we became a public company over 5 years ago, and I'm confident his significant experience in finance, treasury, accounting and investor relations and his deep understanding of our business are extraordinarily valuable to us as we continue to grow and drive Talos forward. The second quarter was highlighted by solid execution by our operations team that led to high margins in our upstream business, another discovery in our infrastructure-led drilling program, a partial monetization and renewed progress in Mexico, a Class VI permit filing in CCS and opportunistic share repurchases. So quite a bit was accomplished since our last call. And we are excited about the direction of our business. Concerning our second quarter results, Talos generated production of 73,000 barrels of oil equivalent per day, which led to $367 million in revenue and $253 million in adjusted EBITDA in our upstream business. That equates to an adjusted EBITDA netback margin of close to $40 per BOE, which we believe is in the top quartile amongst public E&P companies in the second quarter. Capital expenditures during the second quarter were $189 million in our upstream business, while we also invested about $2 million in our CCS business, leading to a positive free cash flow generation of $13 million in the quarter. Our leverage stayed on track at around 1x, including the pro forma last 12 months EBITDA contribution from EnVen prior to closing in February. Finally, we made additional progress in our opportunistic share buyback program, buying 1.5 million shares in the second quarter. Sergio will provide more details and commentary in his remarks. I'll now discuss some important recent upstream and CCS development since our last market update. In July, we made a successful discovery in the Talos operated Sunspear exploitation prospect. This is an excellent prospect that was a recent addition from the EnVen portfolio. Our preliminary post-drill analysis indicates approximately 260 feet of gross vertical thickness of oil pay including 149 feet of net oil pay in the main target, in line with pre-drill expectations. The project will flow to the Prince platform with the first oil expected in the next 18 to 24 months. We own 48% working interest in this project. This result gives us confidence as we continue to work through the acreage position that we acquired. Consistent with our strategy of reprocessing seismic data around our acquired production facilities, we'll use the data collected from the Sunspear drilling in our seismic reprocessing efforts to develop additional high-quality inventory around the Prince, Neptune, Cognac and Brutus facilities. Other projects we are very excited about are the Lime Rock and Venice exploitation discoveries located near Talos', a 100% owned and operated Ram Powell facility. The two prospects, completion, construction and installation operations remain on track, and we anticipate first production from both wells by the first quarter of 2024. These projects could deliver a combined gross rate of 15,000 to 20,000 barrels of oil equivalent per day, contributing to the highest gross production rate achieved in the Ram Powell facility in the last 15 years. We own a 60% working interest in both wells. It's worth noting one of the benefits of both the Sunspear and Lime Rock, Venice discoveries is that by securing working interest partners in these projects, we will collect production and handling fees, which together with new production dramatically lowers the fixed cost structure of these assets. During the second quarter, we completed the well intervention in our operated Bulleit and Mount Hunter wells following some unexpected operational challenges we experienced in the late first quarter and early second quarter. These interventions successfully improved overall reservoir productivity. Additionally, on our operated Neptune facility, we continue to work on optimization efforts, including new chemical treatments and topside modifications expected to be completed in the fourth quarter. On the Pancheron subsalt exploration wells spud in April, we did not find the reservoir quality sands we were hoping for even though this project was well executed operationally by the operator. It had the potential of large reserves. However, the pre-drill probability of success was close to 30%. We have completed plugging and abandonment operations following unsuccessful results. On the Longhorn prospect, we encountered over 50 feet of net pay across two legacy field pays but found noncommercial levels of hydrocarbons into deep zone. We have suspended the well and we'll analyze it further for completion alongside the next Lobster field development well, which is projected to spud in the third quarter. With these projects and others like them, we're continually fine-tuning our long-term drilling calendar and reevaluating our inventory of opportunities to develop annual capital programs that balance risk and reward while offering exposure to short spud to production cycle time exploitation wells and high-impact exploration opportunities. With the recent success at Sunspear, our operated drilling program has had a success in 3 of our 4 last exploitation projects resulting in discoveries, including Venice and Lime Rock. Exploration projects such as Pancheron bring a statistically lower probability of success, but can lead to impactful results as they did in our Tornado discovery from 7 years ago. To this date, Tornado still has the highest producing wells at the company. Another example of technical success is Zama, which we still believe will lead to a successful economic outcome for shareholders. On a long-term basis, having a portfolio of high-impact projects provides attractive risk-adjusted returns and exposures to company and shareholders to exploration upside and additional resources. We are looking forward to drilling our next high-impact opportunity in our Daenerys prospect in 2024. In Mexico, we're excited about our new partnership with Grupo Carso, a conglomerate publicly listed in Mexico. As previously announced in May, we agreed to divest a 49.9% minority stake in our Talos Mexico subsidiary, which owns 17.4% of Zama to Grupo Carso for $125 million. Approximately $75 million of the purchase price will be paid at closing, with the remaining $50 million at Zama's first production. The transaction is expected to close in the third quarter of 2023. Carso's investment is a strong endorsement of the economic potential of Zama, Talos' strong technical capabilities and our ability to influence the project's outcome through our co-lead roles and drilling and offshore installations within the integrated project team. The deal established a baseline valuation for Talos Mexico of approximately $250 million while preserving significant upside as we advance the project toward FID and first production. We are working hard to progress towards FID following the completion and final review of engineering design or FEED, securing project financing and in final approvals. At peak production, we anticipate gross production of approximately 180,000 barrels of oil equivalent per day, making it an important project for Mexico and for Talos shareholders. Turning to our Talos Low Carbon Solutions business. Last week, we filed our first EPA Class VI permit application for our Harvest Bend CCS project, formerly known as River Bend, where Talos holds a 60% interest. This is an important milestone as we look forward to progressing the permitting process. We also intend to file at least 1 additional EPA Class VI permit application across our CCS portfolio by year-end. We are also preparing to drill our first Talos operated offshore stratigraphic well at Bayou Bend during the second half of 2023. Additionally, the partnership expects to drill a Chevron-operated onshore stratigraphic well in the first half of 2024. These test wells will provide critical data to demonstrate the superior quality of our poor space and our ability to store large quantities of CO2. As well as provide additional support for our permitting application process. Talos owns a leading carbon storage portfolio with well-understood geology with the superior rock properties required for CO2 sequestration along the U.S. Gulf Coast. Our footprint is strategically located close to large clusters of concentrated industrial emissions markets. And we believe the industrial complex has the right economic incentives to capture their CO2 emissions to make these projects viable. We continue to have discussions with potential industrial customers as they continue to understand the retrofitting required to meet their decarbonization goals. We also continue to explore whether a capital raise for the CCS business makes sense for Talos. And while that is ongoing, we believe our recent operational execution in the carbon storage portfolio will help create long-term value for shareholders and enhance that process. Robin is here to take any questions on the progress of our CCS business, but I'd also like to highlight her achievements in her additional role as Talos' Chief Sustainability Officer. Recently, Talos was recognized for our continued effort to strengthen our commitment to ESG and sustainability. We were honored to receive the 2023 Hart Energy ESG Award for a Public Producer, one of only two recipients in the public producer category. The award recognizes advancements in sustainable operations, local community engagement and a positive workplace culture. We are proud of our employees' commitment to industry best practices. Whether in our operational execution, health, safety and environmental progress, community outreach or our recent governance enhancement. They all contribute to advancing Talos' ESG journey. On the M&A front, we 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 technical business development, bolt-on opportunities and larger strategic transactions. With these key updates on our 2023 plans and goals, I'll turn it over to Sergio to address our financial details for the second quarter.

Thank you, Tim, and good morning, again, everyone. I'm very excited to take on this new role. Talos truly has a world-class team, and I'm proud to be a part of the outstanding team members that we have in our finance, accounting and IT teams. I've been with Talos for over 5 years now and have built strong relationships with the different internal teams as well as gaining the trust of investors and analysts over the last several years. I'm ready for this new expanded role, and I'm also very grateful to Tim and the Board for trusting me with such an important job. Before addressing the quarterly results, I just wanted to provide a high-level overview of how we're seeing the rest of the year progressing. We're confident in our ability to deliver on the guided financial results, so our financial guidance remains unchanged for the remainder of the year. In fact, we're currently tracking in the lower half of our upstream CapEx range. As our operation continues to improve efficiencies in our drilling operations, and managing costs appropriately. We're also tracking lower on CCS investments, partly due to cost savings and partly due to choosing to delay some activities into 2024. On the flip side, P&A costs are running higher than we initially estimated, which is mainly driven by a tighter market for those services. I also wanted to highlight the team's top-notch execution over the last several months. We had a tough message last quarterly call, but I feel like we've turned a corner and we're on our way to delivering what we said we were going to deliver. The Venice and Lime Rock project execution have been ahead of schedule and under budget. Drilling operations have been incredibly efficient and the production teams are pulling every lever to continue to deliver value and free cash flow to our shareholders while fully integrating a major acquisition earlier this year. Kudos to the various operations team for their delivery. In addition to the many upside opportunities in our business, I wanted to remind everyone of the oil and liquids weighted content of our production. I believe we're one of the highest oil-weighted independence. So to the extent you're bullish on oil prices as we are, I would like to invite you to look at Talos stepway as well. Now turning to the quarter. A quick reminder that our consolidated results include the results of our upstream and CCS businesses as further covered in our 10-Q filed yesterday. Where appropriate, I will highlight the impacts in these different businesses in my discussion of the financials. During the second quarter, we produced 70,300 barrels of oil equivalent per day. Our oil and liquids weighting for the quarter were 75% and 83%, respectively. Pricing from our production in the second quarter reflected the relative softening in the commodity markets with realizations of approximately $70 per barrel of oil and NGLs at approximately 23% of our realized oil prices. Natural gas production realized over $2.40 per Mcf in the same period. This resulted in total revenue of $367 million for the quarter. Net income for the quarter was approximately $14 million or $0.11 per diluted share. Our adjusted net income during the quarter was approximately $12 million or $0.09 per diluted share. During the second quarter, we generated adjusted upstream EBITDA of $253 million excluding CCS and corporate and allocated costs. On a per barrel of oil equivalent basis, this translated to adjusted upstream EBITDA margins of approximately $40 per barrel of oil equivalent. Upstream capital expenditures for the quarter were $189 million, including plugging and abandonment expenditures. Additionally, CCS CapEx was approximately $1.9 million. CapEx was lower in the second quarter as a result of drilling efficiencies, but also due to activities being pushed into the second half of the year for the upstream business and some CCS activities deferred to 2024. Adjusted free cash flow for the quarter, inclusive of our CCS investments was a positive $13 million. Turning to our balance sheet. At the end of the second quarter, net debt stood at roughly $1 billion. The drawn balance on our RBL was $200 million at June 30, a little higher than the first quarter mainly due to working capital adjustments and additional share repurchases, partially offset by positive free cash flow generation in the second quarter. We expect to pay down debt and reduce our RBL balance in the second half of the year as we close on the partial sale of Talos Mexico and received the proceeds associated with that transaction. We also expect to delever further in 2024. In fact, we will continue to focus on reducing leverage as the primary use of our free cash flow in the near term. As of June 30, our leverage metrics stood at approximately 1x, and our liquidity remained high at over $770 million. Opportunistically, during the second quarter, we repurchased approximately $21 million or 1.5 million shares, equating to roughly 1.2% of the total shares outstanding. As of June 30, Talos had approximately $53 million remaining authorization under our $100 million share repurchase program. We will continue to monitor the markets and be opportunistic when it comes to share repurchases, balancing our priorities of investing in our business, reducing our leverage further and providing returns of capital to shareholders if and when appropriate. Lastly, I wanted to remind everyone that our internal plans and financial guidance to the market includes weather-related downtime in the third quarter. It also includes workover and construction-related projects in our facilities, which would typically accelerate in the summer months. We are now entering peak hurricane season in the Gulf of Mexico, and even though we have experienced a mild season so far, it's still too early to assume any possible upside. Additionally, mild hurricane seasons in the Gulf of Mexico can lead to loop currents, and we're starting to see some of that activity intensifying, which could impact our operations. I'm very excited about the overall trajectory of the business as we look forward. Our credit position remains strong and near its all-time best. We also continue to be excited about the investment opportunities in our upstream and CCS businesses for the remainder of 2023 and beyond. We believe these investments will deliver and accelerate long-term value to Talos' shareholders. With that, operator, we will open the line for Q&A.

[Operator Instructions]. Our first question comes from Leo Mariani with ROTH MKM.

I wanted to just hit on Sunspear real quick. What type of production do you expect from that discovery? I know it's going to be 18 to 24 months before you get it. But just trying to get a sense of magnitude in terms of impact at Talos and would you have a potential oil cut for that as well?

Yes. So, I think our pre-drill guide was 8 to 12 in 1,000 barrels equivalent a day gross. So before you net all that out, I don't think we would change that. It was a -- we expected a thick sand here, and it's nice when the model works. There's a lot of work we need to do to kind of tie out exactly what it looks like when it arrives to the platform. It's going to be a little more oilier than we thought. So that's interesting. And so I think it's -- we think we'll be in range. We think we'll be oilier than we anticipated. I think the GORs we captured there were around 1,000, 1,100 there's a little more pressure than we thought, which is actually why the equipment may take a little longer to procure. But we're working through all that. I mean this is really fresh and the guys are excited about it. Again, nice when you can revitalize an old facility, which is what we're trying to do at Prince. It kind of opens up the door to really look at some other ideas around that facility. So any time you have a discovery, it's going to be a tieback to something you just acquired. It puts a little energy around that acquisition, puts a little energy around what else you can do with that facility now that you know you're really reinvesting in it. So when you tie in a new well like that, you're going to make some investments in that facility to handle that production and get you thinking about other things you can do once you make that commitment. So it's really right in line, and frankly, that's great.

And then just I wanted to get a sense, obviously, you folks have announced a presence in the CCS business a few years back, you had some significant milestones. You picked up new storage sites, you just follow the permit. Chevron's you're kind of full-fledged partner on a number of these sites here at this point. It seems like the one thing that maybe we haven't really seen is some deals with some of these industrial CO2 emitters. I mean just wanted to get a sense in terms of whether or not you're confident, you think you can get a deal or two on the board here in 2023? And then just additionally, do you feel like you need to have a couple of deals under your belt before actually doing a potential financing here?

Yes Leo, thanks for the question. Emissions and securing those emissions remains our key focus. And so everything we're doing is sort of in that effort. So even when we're going out and collecting data, drilling some of these stratigraphic wells, that supplemental information that will be part of the exhibits of these permits. Following the permits and showing that you've got a robust permit is a key marker and milestone because these customers are also looking backwards to figure out when will our store be ready for the CO2. And so also keep in perspective, as you scan the Texas and Louisiana Gulf Coast, there's more than 100 facilities that emit more than 1 million ton per annum. In fact, there's more than 225 million ton per annum being emitted today. That's just brownfield. And so the opportunity is very large with all some of these new greenfield announcements and planned projects and it only takes a few million tons per annum to underwrite any one store. So while we're not overly concerned, we're very active on that front. And I'll say we're in various bid processes, have developed term sheet discussions with our JV partners or emitters in all three of our kind of regional hub that we talk about.

And I think the answer to the question on the financing, I mean, I think the ambition for Robin and the team is to not try to prefer one project over the other. It's great, we have Chevron. They're very focused on and talked about it in our last call. We're very excited about the position over and Harvest Bend, what was River Bend, and we're working aggressively in Corpus Christi. If we're going to advance all of those at the same time. That could be quite a bit of a capital increase. And I think that's where you think about, hey, how do I think about capital allocation because we don't want to slow down the progress when we get those emitters ready?

Yes. And it's always great when you can partner with someone that's got their own ambition to develop projects that could generate CO2 in some of these regions as well.

Our next question comes from Subash Chandra with the Benchmark Company.

On the CapEx side, can I ask on the individual buckets and how you see them shaping out. Sergio, I think you said there's some deferred activity on the upstream side. But I guess specifically between the actual D&C P&A and asset management, how you see that in the second half?

Yes, Subash. So we're seeing some of the drilling efficiencies, as I talked about. So I think, as I mentioned, we're tracking lower in the guidance range. Some of the deferrals were more between second and third quarter. Some of the activities took a little bit to start. So we're seeing more of that in the third quarter. So -- but you should think about that range being in the lower part of guidance. So I think D&C is on track, we have a couple of activities now in the second half of the year that we're going to perform, including the completion on Venice and Lime Rock. And we have a lobster well that we're drilling. We have a couple of wells, non-operated wells that we're drilling as well. So that's all going as expected. But like I said, with some additional efficiencies, which is always good. On the P&A side, as we mentioned, that's kind of running a little hot. So the market is pretty tight. There's a lot of activity in the Gulf and not enough equipment and personnel to actually do all of that. So we still expect a pretty healthy amount of P&A in the second half of the year. But again, that's kind of what we were expecting anyways. On the asset management side, we typically do a lot of those things in the summer months. So some of that we were expecting in the second quarter. Some of that has moved to the third quarter. But again, all of that is within our expected range. The D&C one is the one that's tracking a little lower. P&A is the one that's a little hot right now. But the cadence is exactly like we expected. Third quarter should be relatively in line with second quarter, with fourth quarter stepping down from there in terms of overall cost.

On for Neptune, what sort of impact are you expecting on that work?

I think we expect to see a boost from kind of where we are today as we get closer to the fourth quarter, and there's a couple of wells there that we can bring back online. I think as we tried to solve this problem, I think we started from scratch and at first shut in the field, changed some of the chemical processes, actually add some equipment that we think can handle some of the influx of water that they expected, but just changed the dynamics of the fluid content. And so they did that work. We're seeing progress on that side, actually saw some progress in the second quarter on that side. But we also had a couple of wells that we decided to bring in after we kind of sorted that out. So to get it back to full rate, not only do you have to kind of create more uptime, but then you have to introduce all the wells that we shut in as we solve it. But the team -- I think I said on a previous call, when you have something like this, you gave a good -- really good flow assurance engineers, which we have about 6 months to solve a problem, and they're going to go solve it. But you've got to figure out how that impacts kind of quarter-to-quarter. But we saw more upside in the last month than we saw two months ago, but we haven't seen the total rate impact, which is a couple of thousand barrels net a day that we could see later in the year.

Just real quick to just add. I will say that platform is going to be a center piece. If you go look at one of our investor materials, and I think we have locator maps, look at that platform, and look at all the acreage around that platform. We've launched some reprocessing. I mean our focal point around that is not isn't just to restore production, that's unbelievably important for us, but we think that can be a centerpiece asset in what we're trying to do in our drilling program for the next 3 to 4 years. So you can see the acreage position and you can envision how hard the team is working on drilling ideas around that facility which is another reason why we're spending a little more time on topside equipment on that facility.

Got it. And then on the Zama project financing, should we assume that of the net upstream CapEx that you're projecting that perhaps some chunk of that, some healthy chunk of that is project financed and is not -- doesn't come out of cash flow.

It's a good question, and it's one that we're going to have to fine-tune as we get a little further really right around FID, post-FID in Zama because there's 2 ways you can look at this. You can kind of do a traditional project financing with a bank group that's syndicated or you can look at infrastructure project financing where you're working with an infrastructure company that actually might own the facilities and then they're recovering that kind of through a tolling fee. Those have different types of advance rates in terms of how you think about where the capital flows preproduction, post-production. Traditional one, you're going to have a little more equity dollars upfront, a little more advanced rate when you bring on production, the infrastructure, you can get more advanced rate early. So long-winded answer, Sergio can add some elements, but I think we're looking at both and seeing where that market is for both as we really fine-tune the FEED study and get closer to FID. But look, I think there'll be some spend next year. Obviously, having a partner helps mitigate what that spend might look like, but exactly the quantum relative to the financing is really what we have to fine tune.

The next question comes from Jeff Robertson with Water Tower Research.

Tim, you alluded to reworking seismic in response to Subash's question. But -- and I know it's way too early for 2024 guidance. But can you just talk about where you are ranking the opportunities that you identified on the EnVen and Talos asset bases as you start to construct the kind of prospect mix that you expect to drill?

Right. Yes. So the way you should think about it is we have kind of an evergreen process where we find areas that we have a lot of regional data and then we look at, what I would call more subregional or local reprocessing. And so there's a queue, and we rotate around the Gulf using our infrastructure as the centerpiece of that. And so there's ongoing projects immediately and there's ongoing projects across our portfolio. But once we integrated EnVen, if you look at that Neptune facility and you look at what's happening and you look at the acreage position that they were able to procure, we thought that's a great area. And so we've launched a large reprocessing project around all that acreage around Neptune. That typically takes 9 to 12 months to get through. A lot of times, we'll look at bringing in partners. It could be a drilling partner in that area. So that could be something from a business development side that you might hear about by the end of the year. And so that would be a bonus. We're also looking around that Prince area. With the Sunspear discovery, there's some ideas around the Prince area, and then you just think, hey, look, if we're going to spend some money on that facility to hook up Sunspear, why don't we launch a reprocessing around there as well. So you're seeing kind of that benefits when you buy something and you have some success and you think about what you think you can enhance with the team you have and the history you have and just attacking it from the seismic and reprocessing side is what we've always done. It's what we did in Ram Powell that led to those discoveries. It's what we did in Phoenix that led to Tornado and it's what we're trying to do on these assets as well. So it's a rotating pipeline, you may not see as much drilling activity in those assets next year as you receive the data, you mapped it and then you put it into the 2025 pipeline. 2024, will really be about the reprocessing projects we launched effectively this year on our assets. Does that help?

Yes, it does. On the CCS, just to be clear, financing would be for all 3 of the hub projects as opposed to individuals. Is that accurate?

We set up the Talos Low Carbon Solutions business and a ring-fenced away from E&P and a wholly owned unrestricted subsidiary. We're certainly exploring opportunity to invest across that platform. But even if bringing in someone at the top, I think there's still going to be opportunities as we take these projects to FID for project level financing as well. So for us, it was kind of maintaining that optionality and putting everything into a structure that affords us some flexibility as we determine what the best path is for each project and for the platform itself.

Yes, Jeff, I think one thing to remember is each of these projects have different working interest partners. And so each of those are separately financeable once you have the contracts in place. So I think what we've been talking about is exploring something in that subsidiary to tell us about low-carbon solutions that Robin mentioned.

Yes. And we have launched that process working with an adviser and has quite a bit of interested parties. So that's really good news.

And Robin, on the offshore well that Talos will operate in the onshore well that Chevron will operate, how long will it take to evaluate the results of those and formulate those into your permit process?

Yes. Thanks for that question, too. So you're referring to Bayou Bend. So yes, Talos will be drilling the offshore stratigraphic test well. So it's really a data acquisition well and that data will be used as supplement to -- and part of the exhibits to that Class VI permits that the team and the joint venture is working right now. Onshore, we'll follow that, as you mentioned, with Chevron drilling that well sometime next year, and we will be pursuing both onshore and onshore development in parallel processes. We're just a little bit further ahead with the offshore because it's picking up that lease back in 2021 from the Texas General Land Office. And so it's a little bit of an independent process. But again, the data is to help supplement that permit timing but the developments are moving alongside each other. And it should be confirmatory. We've already got a lot of data. In fact, the submission that we made to the GLO. We had our seismic data, that was the Talos advantage of getting into these plays. There's offsetting wells, this geology is well mapped in here. So it's really confirmatory as a supplement to the permit.

Yes. It's description work. I don't think we're wondering if there's going to be thick porous sands in the area. I mean I think it's really more description work to fine-tune the product -- to fine-tune the application.

Yes. And to fine tune the modeling when you're doing reservoir simulation.

And lastly, those are separate containers that each well will evaluate, it's not part of the same one, is it?

They're separated, yes. So we've got 40,000 contiguous acres in the offshore in the state waters and then we've got another 100,000 contiguous acres in the onshore. They're kind of sitting right in between the Beaumont Port Arthur and Eastern Houston Ship Channel Industrial corridors.

I think our view there in Chevron, certainly can speak to it and would agree and then I think they're speaking about it, I think, quite a bit lately is we think there's redundancy, we think emitters want optionality and you want -- you've got different emitters in different locations. You've got the eastern side of the Houston Ship Channel. You've got Beaumont Port Arthur. So these are different wells in the different acreage sets that Robin described just to give the customers different options.

Exactly. Bayou Bend is uniquely poised to support all emissions within that East Texas region.

Our next question comes from Michael Scialla with Stephens.

Yes. Sergio, you gave some detail on the CapEx, and I realize you didn't change guidance. I guess you surprised us a bit. I think Street as well with free cash flow in the second quarter. If you exclude the proceeds from Zama and based on Street prices in the midpoint of your guidance, are you anticipating generating free cash flow in the second half?

I mean that's a general idea, Mike. We don't typically include the either capital that we use to acquire either assets or working interest and things of that nature in our free cash flow. So we won't include the proceeds from the sale of the partial sale of Talos Mexico either. But in our oil and gas operations in the U.S., we absolutely expect to generate a little bit of free cash flow in the second half of the year. But having those proceeds from the Talos Mexico divestiture just kind of further bolster that cash position in the second half.

If I heard you right, it sounds like the priority in the second half is debt reduction over share buyback at this point?

Look, that -- we're always analyzing the market, right? So if the market changes at some point, maybe those priorities will change. But as we sit here today, that is the priority. We'll continue to delever, continue to improve our credit position, which is already strong as it is. But that is the priority to continue to strengthen that. But if the market shifts and we have the ability to acquire additional shares in the second half that is also on the table.

Yes. I think it's worth noting, Mike, that it was never intended to be prescriptive. It was an authorization by the Board. In response to our views of our business and a depressed stock price at the time. And so I think we did some good last quarter. We're seeing some appreciation. We don't think it's near -- really where we think it ought to be. But relative to other priorities and being able to pay down some debt. I think that's just the decision we communicated with our Board, and we'll see where we land. But I think the key note there is it's not prescriptive. I think we've done some good and I think we can really look at our options in the second half.

And I wanted to ask one on CCS. I wanted to get your thoughts on, I guess, some discussion on the BOEM potentially allowing conversion of shallow water leases to be used for storage, would that change your plans at all as you build out that CCS business?

Well, no. I mean, look, so two things you asked on that. With respect to our plans, I mean our general view as a business strategy that you need to be closer to the emission sources, and you need to be closer to the customer. And what we're really proud about in our offshore site that was the first ever dedicated offshore sequestration side is it's right off the coast and it's close to emitters. And we think that will prevail. Now from a -- what's interesting about that is that was a process run by the General Land Office of Texas to develop -- to get bids to understand the commercial viability of what is a commercial process. When you look at what's happening offshore, those leases offshore are mineral leases. I don't know legally how you convert them to a commercial process. And so look, it's the -- the goal of the interiors, we understand, is to maximize the value of the asset that the federal government has in the Gulf of Mexico. We know what that looks like in mineral leases. We don't know what that looks like from a CCS perspective. So certainly, we would advocate new leasing and bidding around CCS. I don't think we understand how you convert a mineral lease that contemplates and has leasing structures and bidding around mineral extraction. It certainly can contemplate salt water injection and saltwater disposal for the purposes of those minerals. But in terms of trying to pull in third-party emissions in a third-party process, that's just a different commercial arrangement. I would think it needs a totally different process, and I'll be surprised if they convert those leases.

Our next question comes from Nate Pendleton with Stifel.

Congrats on the strong quarter. For my first question, can you speak to how the recent M&A in the CCS space impacts your ongoing capital raise for TLCS?

Yes. Sure, Nate, thanks for the question. I mean I think there's a lot of heated interest. We're one of the few CCS platforms out there that folks can come and invest in. There's been a lot of private capital raised. But there's also a lot of players that post the inflation reduction passing last year really want to establish themselves and somehow participate in a CCS platform in the United States. And I think there's a lot of attractiveness of our footprint being on the Gulf Coast where you've got two states seeking primacy. We've got some of the best geology and we've got prime storage sites that sit right adjacent to the emission sources, as Tim was pointing out, which means lower costs. And so we feel like we've got a very compelling business there, and so the interest has really picked up. On that, I also feel like there's going to be some consolidation over time as some folks have gone out and took out some small positions, and so we'll certainly keep our eyes out on more business development opportunities as far as there might be places where we can bolt on some acreage in a few of our regions that aren't quite at the 1 billion metric tons of CO2 storage yet, such as coastal Bend. We're actively looking for some additional leasehold to create that into a nice regional hub for the Corpus Christi region, for example.

I appreciate the color. And then for my follow-up, could you offer some more color on the service environment you're experiencing in the GOM and its impact on your capital investment decisions going forward?

Yes. I mean look, I think certainly, rig rates from an offshore market are up, and I think that's well documented by our friends that are running those companies and the demand on those rigs. And part of that what we're seeing happening globally in places like Brazil. There's a little -- I think there's availability in the Gulf of Mexico, but you have just that pressure on the market. Will that be sustained through '24 and '25 and '26, I think we'll have to see. I mean, from our perspective, our focus is on around our assets and some of the rig types that can service the kind of the inventory that we have. And look, some of the things we're doing around the non-operated side. So I don't -- I don't think it's going to impact kind of how we see our business setting up in '24, '25, but there is some stress in the market in terms of rig rates, and we'll see how sustainable those are relative to overall capital budget. I mean, again, I think we're still seeing moderated investment. And so what does -- how does that really translate to these contracts long term is yet to be determined. But look, our friends in those rig companies had some tough years and they're having some good years. And so we see those cycles. It's not new. I think we've got an oil-weighted asset base that can support the commodity, that can support the prices.

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

Nothing. I want to congratulate my man, Sergio, for getting through his first call as our CFO, and we're proud of his promotion. Thanks, everybody, for joining the call. It was a good second quarter. The team is working hard. Looking forward to talking to you again after the third quarter. So thank you.

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