Talos Energy Inc. Q2 FY2023 Earnings Call

Good day, and welcome to the Talos Energy Second Quarter 2023 Earnings Conference Call. 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 on 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's 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 in the deep zone. We have suspended the well and will 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 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 the 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 in 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 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 one 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 pore 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 independents. So to the extent you're bullish on oil prices, as we are, I would like to invite you to look at Talos' stepwise approach 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 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 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.

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 at 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 and 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 filed 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 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 backward 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 hubs 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.

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 do you see that in the second half?

Yes, Subhash. 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. 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. We have a lobster well that we're drilling. We have a couple of 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 the second quarter, with fourth quarter stepping down from there in terms of overall cost.

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

We anticipate seeing an increase as we approach the fourth quarter, particularly with a few wells that we can bring back online. In addressing this issue, we started fresh by shutting in the field, modifying some chemical processes, and adding equipment to manage the expected influx of water, which altered the fluid dynamics. Progress is being made; we noticed improvements in the second quarter and have also brought in additional wells after resolving these issues. To return to full capacity, we need to increase uptime and reintroduce all the wells we previously shut in while addressing the problem. As I mentioned in a prior call, we have skilled flow assurance engineers working to solve this within about six months, but we need to understand how it affects our quarterly performance. We observed more positive developments recently than we did two months ago, but the total rate impact, estimated at a couple of thousand barrels net per day, will likely become clearer later in the year.

Just real quick to just add. I will say that the platform is going to be a centerpiece. If you go look at one of our investor materials, I think we have locator maps, so 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 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 does not 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 are 2 ways you can look at this. You can 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 pre-production, 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 a 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 mentioned reworking seismic in response to Subhash's question. Although it's early for 2024 guidance, could you discuss how you are prioritizing the opportunities you identified within the EnVen and Talos asset bases as you begin to shape the prospect mix you plan 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 are ongoing projects immediately and there are 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 opportunities 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 have quite a bit of interest from 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, thank you for the question. You're asking about Bayou Bend. Talos will be drilling the offshore stratigraphic test well, which is primarily a data acquisition well. The data collected will contribute to the Class VI permits that the team and the joint venture are currently developing. Onshore, as you mentioned, Chevron will drill that well next year, and we will pursue both onshore and offshore development simultaneously. We are slightly further ahead with the offshore project because we obtained that lease back in 2021 from the Texas General Land Office, making it somewhat independent. The data will help align with the permit timeline, but the developments are progressing together. This data should be confirmatory; we already have a significant amount of information. For instance, the submission we made to the GLO included our seismic data, which is an advantage for Talos as we enter these plays. There are offset wells, and the geology is well mapped. So, this will indeed serve as a confirmatory supplement to the permit.

Yes. It's more about providing detailed descriptions. I don't think there's any uncertainty regarding the presence of thick porous sands in the area. It's really focused on refining the product and its 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 believe that at Chevron, we view the situation similarly and have been discussing it frequently. We perceive there to be redundancy, and we understand that emitters prefer having options. Different emitters are located in various areas, such as the eastern side of the Houston Ship Channel and Beaumont Port Arthur. These represent different wells across the various acreage sets that Robin mentioned, providing customers with a range of choices.

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 the 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?

We are always analyzing the market, so if there are changes, our priorities might shift. However, for now, our focus is on continuing to reduce debt and enhance our already strong credit position. That remains our priority. If the market changes and we have the opportunity to buy back shares in the second half, we will consider that as well.

Yes, I think it's important to mention that it was never meant to be a strict guideline. It was an authorization from the Board, reflecting our perspective on the business and a low stock price at that time. I believe we made some positive moves last quarter and are experiencing some appreciation. However, we don't believe it's close to where it should be. Considering other priorities and the need to reduce debt, we made our decision known to the Board, and we will see how it unfolds. The key takeaway is that it's not a strict guideline. I think we've made some progress and we can explore our options in the second half.

And I wanted to ask one on CCS. I wanted to get your thoughts on 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?

No, I don't think so. There are two points I want to address. Regarding our plans, our business strategy emphasizes the importance of being close to emission sources and customers. We take pride in our offshore site, which is the first dedicated offshore sequestration site, located near the coast and close to emitters. We believe this approach is effective. Interestingly, the process that led to this site was managed by the General Land Office of Texas to assess bids and understand the commercial potential of this process. When looking at offshore leases, those are classified as mineral leases, and it’s unclear how to transition them into a commercial process for carbon capture and storage (CCS). The goal of the interiors department seems to be to maximize the federal government’s asset value in the Gulf of Mexico, which we understand in terms of mineral leases, but not in relation to CCS. We certainly support new leasing and bidding for CCS, but we are uncertain about converting a mineral lease, which typically involves structures and bidding for mineral extraction. While it can include saltwater injection and disposal for minerals, integrating third-party emissions into a third-party process requires a different commercial arrangement entirely. I believe it would necessitate a completely different process, and I would be surprised if those leases were converted.

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?

Certainly, rig rates in the offshore market have increased, which is well recognized by companies operating in that space and reflects the demand for those rigs. We're observing this trend globally, particularly in regions like Brazil. While there seems to be some availability in the Gulf of Mexico, the overall market is under pressure. It's uncertain whether this situation will persist through 2024, 2025, and 2026. Our main focus is on our assets and the types of rigs that can meet our inventory requirements. We're also making progress in the non-operated sector. Despite the stress in the market regarding rig rates, we don't believe it will significantly affect our business outlook for the coming years. However, we are still witnessing moderated investment, and how this will affect long-term contracts remains to be seen. Companies in the rig sector have experienced challenging years but are currently enjoying better performance, highlighting the cyclical nature of the industry. Our oil-focused asset base should be capable of supporting commodity 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.