Talos Energy Inc. (TALO) Q3 2022 Earnings Report, Transcript and Summary

Good morning, and welcome to the Talos Energy Third Quarter 2022 Earnings Conference Call. All participants will be in a listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note that this event is being recorded today. I would now like to turn the conference over to Sergio Maiworm, Investor Relations. Please go ahead.

Thank you, operator. Good morning, everyone, and welcome to our Third Quarter 2022 Earnings Conference Call. Joining me today to discuss our results are Tim Duncan, President and Chief Executive Officer; Shane Young, Executive Vice President and Chief Financial 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 today 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 Form 10-Q for the quarter ending September 30, 2022, filed with the SEC yesterday. Any forward-looking statements that we make on this call 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 both GAAP and non-GAAP financial measures. A reconciliation of GAAP to non-GAAP measures was included in yesterday’s earnings press release, which was filed with the SEC and which is also available on our website at talosenergy.com. And now I’d like to turn the call over to Tim.

Thank you, Sergio. Good morning, everyone, and thank you for joining our call today. As we discussed in our second quarter earnings call, we knew we were going to have substantial planned downtime in the third quarter with the HP-1 dry dock and the Shell Odyssey pipeline maintenance. But despite these planned production outages, we surpassed our internal expectations for the quarter by controlling our operating costs, allowing us to generate substantial free cash flow in the quarter and to continue to rapidly delever our balance sheet. Over the last 6 quarters, Talos has repaid approximately $450 million of its debt, which equates to approximately $5.40 per share outstanding in debt repaid over the period. In the third quarter alone, Talos paid back $140 million in our credit facility. This is another record-breaking quarter on the balance sheet front for Talos. Our leverage metric is now at 0.8x, the lowest level in the company’s history, and Talos’ liquidity is now more than $800 million, the highest in the company’s history. We continue to generate and cultivate several catalysts to make our business unique, which include a robust organic drilling inventory, growth in our carbon capture and sequestration business and the pursuit of accretive M&A opportunities. On the drilling side, we kicked off our deepwater drilling campaign in the third quarter, which is expected to continue into 2023 and which exposes Talos to significant additional organic resource upside. If successful, these opportunities could represent tens, if not hundreds, of millions of barrels of oil equivalent of additional resources on a gross basis. Because most of these projects are not currently in our reserve report, they could add significant growth to our proved reserves and add multiple years of reserve replacement, which makes for exciting times in the months ahead. It should be noted that most of the prospects we expect to drill in the coming months were generated in-house by a very talented team of geoscientists. These leases are typically acquired in M&A transactions or through federal lease sales and our initial ownership levels are usually very high, often 100% working interest. After applying our seismic reprocessing techniques to better define the project’s potential, we then look to farm them down to a Talos ownership level that fits our capital allocation strategy. I think the fact that we were able to attract such sophisticated partners for these projects to include BP, Chevron, Oxy, Ecopetrol and Walter Oil and Gas, among others, speaks to the quality of these opportunities. Another major catalyst that we continue to be excited about is our Talos low carbon solutions business focused on carbon capture and sequestration. In this business, we are primarily focused on 4 parallel priorities: working with our industrial partners to secure long-term contracts for the transportation and sequestration of their CO2, securing additional storage capacity, strengthening existing partnerships and forging new ones; and finally, advancing the engineering and FEED work in our existing portfolio of projects. Since the inflation Reduction Act was passed in the law, we have seen a renewed enthusiasm by industrial emitters and a heightened commitment to moving forward with their decarbonization goals. We believe several of these workstreams will lead to positive milestones by year-end, and I’m extremely confident that our CCS business will be a significant contributor to Talos’ earnings and cash flow in the coming years. Lastly, we believe that acquisition opportunities are also a key catalyst for us as a logical acquirer. In late September, we announced the strategic acquisition of EnVen Energy, a private Gulf of Mexico operator for $1.1 billion through a combination of stock and cash consideration. We are very excited about the industrial logic of owning these assets, which consist of deepwater oil-weighted production through operated infrastructure across the basin. We expect the transaction will bring significant additional scale, including approximately 24,000 barrels equivalent a day to 2022 estimated production and approximately 78 million barrels equivalent of proved plus probable reserves as well as increased asset diversity, reducing field level concentration and doubling our operated deepwater facility footprint. The transaction is financially attractive to Talos shareholders as well. It is expected to be accretive to 2023 free cash flow per share and to be immediately deleveraging to our already strong balance sheet. Lastly, the acquisition improves our GHG intensity metric and will be a catalyst to declassify our Board of Directors and enhance its independence to better align with shareholder interest going forward. We are convinced that this transaction checks all the boxes that investors expect from M&A deals. The overwhelmingly positive feedback we received from shareholders and our stock performance since the announcement reinforces that belief. As an update on the regulatory process to close the transaction, we received overwhelming support from Talos noteholders in obtaining consent to bring EnVen’s assets and bonds into the Talos’ credit profile at the closing of the transaction. Having all assets on one balance sheet allows us to speed up and maximize the capture of the synergies we expect to achieve. After the expiration of the Hart-Scott-Rodino review window, last week, we filed our Form S-4, our registration statement with the SEC. Depending on the potential SEC review timelines, we expect to close the transaction in either December or January. I’ll briefly address the third quarter and provide key operational updates before turning the call over to Shane to walk through the quarter in detail. The production for the quarter was 53,000 barrels of oil equivalent per day, which is 67% oil and 75% liquid. This is inclusive of the planned dry dock and maintenance for our HP-1 floating production unit and the planned maintenance of the Shell’s Odyssey pipeline system in Mississippi Canyon. The combination of these 2 planned downtime activities resulted in production deferrals of approximately 8,000 barrels of oil equivalent per day for the quarter. In the third quarter, we experienced very strong loop currents in our production operations and drilling operations, specifically in the Green Canyon area of the deepwater Gulf of Mexico. These loop currents only affect dynamically positioned vessels since those vessels rely on their own thrusters to maintain their position, while moored and fixed platforms are not impacted by these current. Because floating production units like the HP-1 and deepwater drilling rigs are dynamically positioned, they are impacted by loop currents. Stress created by constant loop currents caused several extended shut-ins on the HP-1 in the third quarter. This production intermittency in the Phoenix Field related to the loop current resulted in an additional 1,000 barrels of oil equivalent per day for the quarter of unplanned deferred production. The loop currents continued to impact production from the HP-1 in the first few weeks of the fourth quarter as well, although conditions have recently improved and currently running as expected. On the drilling operations front, we took possession of our deepwater rig, the Seadrill Sevan Louisiana in August. The first operation was an uphole recompletion in our bullet project. After very encouraging completion results of the targeted zone, we encountered operational difficulties associated with similar loop currents in the area. We decided to temporarily suspend operations on that project and move the rig from the Green Canyon area to the Mississippi Canyon area. We planned to return the recompletion project in the first quarter of 2023 to finalize the work and bring the well online. Our drilling campaign in the Mississippi Canyon area started with our Lime Rock prospect, near our operated Ram Powell facility. Lime Rock will be followed by our Venice project, also by our Ram Powell facility. We will then wrap up the Bulleit recompletion before starting our Rigolets prospect, which, if successful, could be tied back to our Pompano facility. And each of these new drill exploitation projects, we have secured joint venture partners. Talos will participate at a 60% working interest in each. And each of these projects could deliver 5,000 to 15,000 barrels of oil equivalent per day gross within 12 to 18 months of achieving a successful result. We have additional options with the rig and we’re finalizing the planning for our 2023 capital program. We are confident this exciting rig program will lay a solid foundation of production growth and additional organic reserve growth in 2023 and 2024. Beyond our operated rig program, we’re also participating in a number of interesting non-operated exploration projects. We spud the appraisal well for our Puma West project into Green Canyon in October and anticipate those results in early 2023. Additionally, we completed a multi-block cross-assignment trade with Oxy, covering over 46,000 acres in the Green Canyon and Walker Ridge areas and expect to drill a high-impact sub-salt miocene prospect called Penteron, on that acreage in early 2023. We highlighted some attributes to that project in our Analyst Day presentation back in May under the project named Camellia, but we hope to share more details on that project as part of our 2023 guidance, which we intend to roll out at the closing of our EnVen transaction. In summary, it was a busy quarter, and the team has managed through the downtime challenges by focusing on operational execution while continuing to use our excess free cash flow to put our balance sheet in the healthiest position it has ever been. Now we are well-positioned to focus on key catalysts as we close out the year and exciting deepwater drilling program and closing and integrating in a very attractive M&A transaction and the continued development of our carbon capture and sequestration portfolio. With that, I’ll turn the call over to Shane to address some additional details for the quarter.

Thank you, Tim, and thank you, everyone for joining us on our call this morning. I’m also very pleased with our performance during the third quarter, and this morning, I’ll focus on 3 topics. First, I’ll provide further details on our financial results for the quarter. Next, I will focus on the strength of our balance sheet. Finally, I will provide some guidance on the balance of the year. During the third quarter, we produced 53,000 barrels of oil equivalent per day, inclusive of approximately 9,000 barrels of oil equivalent per day of mostly planned deferred production from the HP-1 dry-dock and third-party midstream downtime as well as other operational developments, which Tim referred to earlier in the call. We received strong pricing for our production in the quarter with realizations of over $90 per barrel of oil, NGLs at 36% of our realized oil price and over $9.35 per Mcf on natural gas production. This resulted in total revenue of $377 million. Net income for the quarter was approximately $251 million or roughly $3 per diluted share, and adjusted net income was approximately $63 million or $0.75 per diluted share. In the third quarter, we generated adjusted EBITDA of $197.6 million or $278.7 million before the cash impact of hedge settlements. On a per barrel of oil equivalent basis, this translated to adjusted EBITDA margins of approximately $41 per BOE and adjusted EBITDA margins, excluding realized hedge losses of approximately $57 per BOE. Those represent 67% and 74% margins, respectively. After capital expenditures of $129 million and interest expense, we continued to generate strong free cash flow before changes in working capital, generating $39.4 million during the quarter. This brings total free cash flow generation for the first 9 months of the year to $265 million. Turning to the strength of our balance sheet. During the third quarter, we repaid another $140 million of borrowings under our revolving credit facility or approximately $1.70 per share, reducing the balance of the RBL to just $60 million outstanding at quarter’s end. This is down from $375 million at the beginning of the year and leaves our RBL approximately 93% undrawn relative to our commitments. As of September 30, total debt stood at approximately $665 million. Since the first quarter of 2021, when we refinanced our bonds, we’ve reduced debt outstanding by approximately $450 million or approximately $5.40 per share. At quarter’s end, liquidity stood at over $800 million, while leverage stands at 0.8x net debt to adjusted EBITDA, the lowest level in the company’s history. We’re very pleased with our rapid deleveraging and repayment of outstanding debt in recent quarters. I expect deleveraging to continue through the remainder of 2022, albeit at a slower pace as our capital program has ramped up with the addition of our open water drilling program. I expect further deleveraging into 2023 as our legacy hedges roll off. Moreover, the closing of our transaction with EnVen is expected to further strengthen our credit profile going forward. Currently, we are launching our fall borrowing base redetermination process, and we’ll update the market after we have concluded it later in the month. Finally, turning to our financial guidance for the remainder of the year. As outlined in our earnings press release from last night, we expect production for the fourth quarter of between 56,000 and 57,000 barrels of oil equivalent per day. This is inclusive of 3,500 to 4,000 barrels of oil equivalent per day of anticipated deferrals from ongoing loop currents and downtime at non-operated Delta House, putting us slightly below our full year production guidance provided at the beginning of this year. Fourth quarter production is also impacted by the timing shift on the recompletion that Tim mentioned from the fourth quarter to the first quarter of 2023 as well as by lower royalty relief for gas volumes, given the higher price realizations we’ve experienced in 2022. We continue to expect cash operating costs and general and administrative expenses to be within our original guidance range with inflation pushing them towards the upper half of that range. Lastly, as previously discussed during our second quarter earnings call, we expect capital expenditures towards the high end of our guidance range due to continued inflationary pressures and non-operated capital project timing. We currently expect fourth quarter capital expenditures to be between $170 million and $180 million, inclusive of P&A expenditures. We’ll have more to say about the 2023 outlook around the time of the closing of the EnVen transaction. With that, I’ll now turn the call back over to Tim.

Thanks, Shane. When we built Talos, we made a decision to stay in the Gulf of Mexico because we believe that over time, it would generate more significant investment opportunities in other basins. As I reflect on where we are in the life cycle of Talos, we celebrated our 10th anniversary and over 4 years as a public company, I’m extremely excited about the opportunities ahead of us. Our team continues to deliver impactful drilling opportunities. We believe we have positioned ourselves as a counterparty of choice in an assortment of business development opportunities. And we’ve used our in-house skill sets to build out a low-carbon business that we think will differentiate ourselves from other small and mid-cap public E&Ps. In market terms, I believe we have one of the largest alpha generation opportunities out there to continue to build long-term shareholder value now and in the future. With that, operator, we’ll open up the line for Q&A.

We will now begin the question and answer session. [Operator Instructions] And our first question here will come from Subash Chandra with Benchmark Company.

Good morning. Tim, so it’s been addressed that the loop current issue, quantified it, thank you for that. But would you speculate what exit rate could look like in the fourth quarter with some of those loop current issues, I guess, subsiding and maybe even further into first quarter when you add the recompletion?

Yes, it’s interesting on the loop current. I would tell you just as a general matter, they haven’t really impacted us over the last couple of years. Those are things that are seasonal. They hit different parts of the Gulf of Mexico. I think last year, they were lingering around the Mississippi Canyon area. This year, they’re lingering around the Green Canyon area. So frustrating and hard to operate. And again, it doesn’t impact everybody. It impacts those vessels that are dynamically positioned. And obviously, we have one of those in the HP-1. So we knew the quarter would have the HP-1 volumes a lot -- removed for most of the quarter. And then we thought, hey, we’ll get the ship back up and get a lot of those volumes back and then the loop currents challenged that thesis. Things have returned to normal, I would say to think about how to build that rate back up. So we have some non-operated facilities that are doing some repairs and maintenance that we generally knew about. The loop currents were something that’s a bit of a surprise. Those have subsided, so we should get those volumes back as we exit the year. And then we had that Bulleit recompletion, which is several thousand barrels a day of volume that we would think to get back in the first quarter. Now keep in mind, we’ve got a platform rig running. It’s doing a project called Mount Hunter. We think that could come back in the first quarter. So I think as you think about building back production, you’ve got some of the planned non-op. These are compressor change out projects that are in this fourth quarter guidance. We knew about a lot of that. That’s fine. That builds back up. But there’s some contingency on any potential weather, maybe we don’t need that contingency. That builds back up. And then the Bulleit recompletion getting back on that, which is also a victim of the loop currents. You see that build back up in the first quarter and then Mount Hunter, which I just talked about. And then if you go forward from that, Subash, and just start thinking about where this all goes over the next kind of 12 to 18 months. We work on our drilling program, again, we have a platform rig program on the Pompano area. We have an open water rig program. We talked about Mount Hunter. We talked about the Bulleit recompletion. Then it goes and execute 3 straight, and actually, maybe even 4 straight of these really simple tiebacks. And these are right off the Ram Powell facility. I’ve talked about one off the Pompano facility. If these are successful, they can add 5,000 to 15,000 barrels a day equivalent gross. We own 60% of those. And so you can start to see how these things could stack up in the second half of ‘23 and into ‘24, that’s what we get pretty excited about. What we’re doing on the non-op side in open water, Puma West, the [indiscernible] prospect with Oxy. Those don’t have immediate impact on production, but they have a really big impact on potential reserves. So there’s a lot of moving pieces. But if you really start to stack the catalyst together, I think it’s pretty exciting. And then when you look to where we’re trying to go with the EnVen assets, they have their own platform rig program. They’ve done great work in the Lobster Field. And then they have an open water program that’s going to be delivered in the first quarter to go to a couple of interesting tiebacks similar to what we’re doing with our tiebacks. So when I look at the combined businesses, a little choppy fourth quarter, I get it. Nobody loves it, but you got to be pretty excited on where this is going as you get into the first quarter and you look out the next 12 to 18 months.

Tim, you feel comfortable putting any numbers around, sort of the first quarter expectations?

No, I think hopefully, that gave you enough anchors to start to build some of that out. I mean what we’re trying to do is get this transaction closed as fast as we can, and we’re working through kind of the S-4 filing, and hoping that goes effective. And then when we get this closed, I think we’re going to roll out a lot of things with our closing, our vision of the pro forma of business, how we think about guidance for next year, how do we think about capital allocation. All those things will come through closing, which at the end of the day, could be by the end of the year or just sneaks into January. But I would say the active programs that we put together is going to build everything back up to a point that we’re going to be pretty satisfied with.

Okay. Look forward to that. A follow-up, perhaps for you and Robin. So now we’re seeing the U.S. sort of dominating CCS projects globally, a whole bunch of different announcements, et cetera. Broadly, can you sort of put Talos in context of that? Where your competitive advantages are in this? We know the projects you have, et cetera. But as you go forward, I’m assuming you’re seeing a lot more competition out there. What your brand provides that others don’t?

Yes. Let me start with that, Subash, and I’m going to hand it over to Rob, and maybe piggyback that. I think congrats on some of these announcements we’ve seen from some of our peers and friends and competitors. I think they would tell you, whatever you might have written in the last 2 weeks, probably took months and months and months to negotiate. These things aren’t quick. And so that’s why I pick up the call I talked about. I’m pretty excited that we still have some milestones that we intend to try to achieve by the end of the year. And so I think there’s a lot still coming from us on what we’ve been putting together. I think generally, our advantages, and we took it very early as we really understand the Gulf Coast geology and the geology that extends into the state waters. We’re nimble. We move fast. And I think that was reflected in why Chevron chose to partner with us. Just for example, Robin and Southeast Texas. And so what I talked about in the call was these parallel paths Robin’s team is working on between enhancing the storage space, which is really geology-based, getting our things permitted, talking to emitters, even enhancing partnerships. And I think you’re going to see more milestones around that and Robin provide some of your views as well.

Yes. I’ll echo that. I think our advantage of being a first mover here, getting some very strategic leasehold, we’re approaching 1 billion metric tons of CO2 storage across the U.S. Gulf Coast when you look at what we’ve got in 4 announced project areas. And so that is allowing us to have those good discussions with partners, whether they be customers, attracting additional equity partners. As you know, we brought in Chevron into our Bayou Bend project with ourselves in Carbonvert’s last quarter. And so it’s very exciting right now. We are seeing others start to build their positions. I feel like they are a few quarters behind. And so for us, it’s continuing to progress on some of the other milestones as we collect the data we need for permits and advancing pre-FEED and FEED activities.

I think we’ve mentioned just the enormity of the level of emissions from if you just would call that more of an addressable market, even though, obviously, you’re not going to remove all of them. The enormity of that market relative to the amount of different places where you can have a good storage kind of unit, kind of good carbon storage infrastructure. I think the point that you’re going to say, if you look out 5 years from now, the announcements you’ve been reading this week, there’s going to be just a large amount of those types of announcements. There is absolutely plenty of room for our peer companies to achieve their goals on CCS, for us to achieve our goals on CCS and still needing to do more to address the broader emission storage. So it’s a big market, and I think we’re well-positioned. And again, well-positioned with a partner like Chevron and one of those, and I think we’re going to enhance those partnerships in some of the other areas as well.

Okay. So you talked about year-end type announcement on CCS. Could you specify in what category that might be?

Hopefully, multiples. When you’re working in 4 kind of parallel things, you’ve got things you’re doing with respect to the projects you already have such as get the strat well done, get that classic permit filed. You’ve got more carbon storage you’re trying to get around your project areas. You’ve got different partnerships discussions you’re having and then ultimately, emitter discussions. It could come from any one of those 4 places. And I am certainly not going to preview any one of those in particular. But they move at different speeds. And I think that’s part of the point, too. Somebody then can come together pretty quickly and somebody is just the conversations dragged out because we’re thinking of these negotiations on something for the first time. So there’s a lot that’s happening out there in this space. They really are first-time type contracts. And I think we’ll all admit they go a little slower than we anticipated, but not for the lack of effort. So I don’t know which of those 4 gives you the next milestone, but I’m pretty confident it will be 1 or 2 of those.

Our next question will come from Jeff Robertson with Water Tower Research.

Good Morning, Tim, will the tornado will have any impact on overall operating costs of early water breakthrough?

Maybe a slight one. I don’t think it’s too bad. A lot of what we’re doing, Jeff, we’re still managing a total liquid number. So these 2 wells were producing gross somewhere between 16,000 and 18,000 barrels a day. You still have 16,000, 18,000 barrels of liquid a day, but part of that liquid is substituted by the water. There are some fees we collect that’s tied to oil, and so you might have some of those fees go down. But at the same token, that facility when it’s running right, has tremendous uptime and again, I do think you’re going to have -- we’re going to have synergies when we put the EnVen assets together that I think, offset some of that. I think it will be negligible when we think about margins broadly. And again, it’s important that we’re transparent about these things. But this is a project, just to put it in perspective. I think it produced about 30 million barrels across those wells when we decided to go ahead and do the water injection project, which is a pretty novel, first of its kind, all intra-water inside the same wellbore. And it’s produced 15 million barrels already since then. And you can imagine the prices in which we produce those barrels. So this is a heck of a project. It’s got a lot of years left. Again, a little more water volume early. That’s really only one of the wells. The other wells is in good shape. And it’s acting like it’s supposed to act. But probably broke through a couple of months earlier than our model, and so speaks to some volumes we felt like flushing through. But I think, again, great project and something we’ll manage.

Can you comment on the EnVen platform rig program they have, I think, in the Lobster area? And also in terms of are those projects that would add production throughout 2023 or like some of the things you spoke of with respect to Talos, would it be more back half-weighted for 2024?

Yes. I would tell you, so that’s an asset in that Lobster Field like many of the assets that the EnVen team owns. We looked at it and tried to bid on it and bid on them, and they kind of beat us in the bid and that’s what makes this so interesting to come back to these assets. And so we’ve admired the work they’ve done over the last 4 to 5 years in that asset. They’ve had a platform rig. And it’s one of those fields that when it’s got the right team focusing on it, they can just continue to turn up opportunities. When you have a constructive oil environment, you can turn up new opportunities. And so they’ve had an active program for the last 4 years. They’ve really done a fantastic job. We don’t see any reason to change that, at least for the next 9 to 12 months. And so that is absolutely the type of program where if you have success, then you turn around and you have production. So that’s a great way to get consistent production from your assets when you have those types of redevelopment opportunities. And so if you look at the combined businesses, you would have 2 platform rig programs going at the same time. You would have 2 open water rig programs going at the same time, starting in the first quarter of next year with their open water rig. Those are going to be that 12 to 18-month tieback type of opportunity. And then we’ll have a non-operated program going, which is for the high-impact stuff like Puma West. So you’ve got the full complement of opportunities, some near-term volume, some what I would call mid-term volume 12 to 18 months. And then the bigger chunkier stuff, but if it works, it may be several years out, but it will be very impactful when it gets there. So I’m pretty bullish on how we’re putting the program together and how it adds both rate and reserves over the next 12 to 18 months.

Shane, a question on the mechanics of the S-4. How long can you go with the SEC before they would require you to drop September 30 financials in?

Yes. We would have to do that today if we refiled today, the September 30 numbers. Now that we file our September 30 numbers, we’re going to have to roll those and as well for EnVen into a subsequent filing.

So at some point, there’ll be an amended filing with September 30?

That’s correct.

Okay.

Our next question will come from Nate Pendleton with Stifel.

Good morning. My first question, maybe for Robin. Going back to earlier on CCS, based on the favorable geology along the Gulf Coast for CCS, do you have any indication about the potential inj activity per well that your projects could achieve? And how would that compare across your projects, especially onshore versus offshore?

Yes, thanks for the question. We’ve been planning in a range of about 1 million to 1.5 million tonnes per annum of injection per well. It’s really going to be about how you size the wellbore itself and the wellbore construction design. So we see that it could be fairly similar, whether it’s onshore or offshore. There will be a few things that are designed a little bit differently, but that’s part of the beauty of having a portfolio as we really want this approach of design one, construct many where we can build in some efficiencies across our project portfolio.

Yes. It doesn’t change. It’s funny when you go from producing a well to injecting in a well. The theory is really around rock properties and thickness or what we call cage. And so that productivity index that you create when you produce a well isn’t different when you go inject the well. So some areas might have better rock properties, but a thicker section and some areas might have a thinner section, but better rock properties. And so it just depends, and that can change. But generally, when you go 10 miles into the coast or 5 miles off the coast, the geology isn’t dramatically different.

Yes. So these stratigraphy wells that we will go drill in many of these areas will help us get some confirmatory data to better understand the rock properties, we’ll collect some additional data there, not just for the permitting, but also as we’re planning for injection.

Great. Thanks for detail. And as my follow-up, as you talked about earlier, there have been several large greenfield CCS project announcements along the Gulf Coast. Given the significant brownfield opportunity surrounding your projects, can you speak to your appetite for developing additional sequestration sites? Any challenges to adding those sites? And also maybe could you comment on if your team is interested in taking your expertise beyond the Gulf Coast region?

Yes, Nate. I really appreciate the question. It’s a great one. So yes, there is a lot of current industrial emissions in many of these regional corridors, which we’ve already got an established leasehold. But in some of these areas, there will be greenfield investment as well. One of our projects, the Coastal Bend project is still around the Port of Corpus Christi. It’s been a very large energy export hub when we think about hydrocarbons, but they’ve been very vocal about wanting to attract new investments and participate in what we’re calling a blue economy. So if you can decarbonize some of these fuels and products on the front end, the thought is, over time, they will get a premium or at least be a preferred supplier as those types of products are getting exported globally. So yes, we’re certainly having conversations with, I’d say, emitters in both categories. Sometimes those who have existing facilities today, but are looking for new investments. And part of getting to their final investment decision will require a decarbonization solution in place. So that’s where we’ve got a strategic foothold and a storage site in the region. And it really gives us a leg up to have some of those conversations. And so to your second point about other areas, I’ll say yes. We certainly have some of the world’s best geologic rock properties along the Gulf Coast, which is great for hub scale. But as we think about some of these point source solutions where we’re developing and designing a very bespoke solution for a particular customer where you’ve got the emitter upfront, we are exploring some of those opportunities as well, and that’s where we think as an independent, we can play in both worlds and have that diversification in our low carbon portfolio.

Yes. The only thing I’d reiterate there is, and Robin is exactly right. I mean these hubs along the Gulf Coast are super-interesting partnering with folks like Chevron in Southeast Texas, absolutely interesting and excited about that. But because we’re a smaller company, we can work on things that are what are, point store, small, nimble, maybe in an area you wouldn’t immediately think of just because someone is thinking about new construction and wants a solution. And that may not be big enough for some of the majors that are playing in the space. So I think we’re just trying to be flexible and use the expertise we’re building every day to figure out how to monetize that and more value in this low carbon space. So I’m actually excited about how we can build a portfolio of not only participating in hub sequestration, but also point source in different parts of the Gulf Coast and then outside the Gulf Coast.

[Operator Instructions] With no remaining questions, we will conclude our question and answer session. I would like to turn the conference back over to Tim Duncan for any closing remarks.

Great. Thanks for joining us today on the call. And I would tell you what we’re most excited about and hopefully came through is where the capital program is moving with respect to catalysts we think we have in the business, not only on the drilling and the organic side, what we’re trying to do and get wrapped up and announced on the CCS side. And then we just have a big transaction that we can’t wait to get across the finish line. And so the next time we speak with our investor community, I think we’re going to be a bigger company, and we’re going to really roll out the vision of what that bigger company wants to do and what it’s going to look like and what it’s capable of. And I think it’s going to be absolutely extremely exciting. So we really look forward to the next time we get together and talk about the vision of the pro forma company. And until then, thanks for participating in this call and those who have interest really know how to get a hold of us, and we look forward to speaking with you. Thanks.

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