Carbon Capture & Sequestration Along the Gulf Coast With Talos Energy
Insight by Marc Bianchi, CFA and David Deckelbaum
In the fifth episode of the Energy Transition Podcast Series, CEO Tim Duncan, and EVP of Low Carbon Strategy, Robin Fiedler, of Talos Energy, an upstream oil and gas production company, join Industrial Gas Equipment and Energy Oilfield Services & Equipment Analyst, Marc Bianchi, and Next Generation Materials and Oil and Gas Exploration & Production Analyst David Deckelbaum. They discuss carbon capture initiatives along the Gulf Coast and their outlook for this emerging growth segment. Listen to the episode: [ADD LINK]
Transcript
Speaker 1:
Welcome to Cowen Insights, a space that brings leading thinkers together to share insights and ideas shaping the world around us. Join us as we converse with the top minds who are influencing our global sectors.
David Deckelbaum:
Morning. I’m David Deckelbaum of Cowen’s energy team, along with Marc Bianchi. This is our next installment in Cowen’s Energy Transition Podcast Series. Today, we’re joined by Talos Energy, an offshore oil and gas exploration and production company that’s also engaged in the development of future carbon capture and storage opportunities in the United States, Gulf of Mexico and offshore Mexico. We’re joined this morning by Tim Duncan, who’s the founder, CEO and president. And Robin Fielder is the EVP in charge of low carbon strategy and the chief sustainability officer.
Robin and Tim, thank you both for joining us this morning, and looking forward to talking with both of you.
Tim Duncan:
Thanks for having us.
David Deckelbaum:
Maybe just to get the ball rolling here, by way of backgrounds … I know that looking at CCS, it seemed like it was born out of an ideation process in 2020, 2021 on how Talos was going to get involved in the energy transition. Can you maybe talk about that process, why you started looking at different things outside of just your core gum production opportunities and maybe just the genesis of Talos’ involvement in CCS?
Tim Duncan:
Yeah. No, that’s great. And again, thanks for having us. Look, Talos is a company that’s fairly young, relative to other public companies. We’ve been around 10 years, but 10 years ago was five guys with a credit card and some office space. And we raised some money and built a private company and made it through the downturn of ’15 and ’16. Ultimately, we went public through a reverse merger in 2018. And then as we were entering in 2020, we made a big transaction.
So, I’m catching you all the way up to pre-pandemic. over 65,000 barrels of equipment a day, good balance sheet, and we’re heading into the pandemic. Now, most of our experiences on Federal lands, Gulf Coast, conventional geology, and we came back out of the pandemic, and obviously you saw a paradigm shift in what people wanted to see out of oil and gas companies; bigger companies, consolidation, a dividend. And we get that, and that’s something that we’re trying to build and grow on, on the oil and gas side. But you also saw a increased demand for transitional investments for the de-carbonization.
And we looked at ourselves and said, “Look, as we try to grow the oil and gas side and do that as a consolidator in the Gulf of Mexico, is there any way to play in the de-carbonization space? Is there any way to play in a low carbon vertical business?” And we looked at wind, a little tougher on the Gulf Coast. Electricity prices are cheap. The wind doesn’t blow as hard. And we started looking at CCS, and we said, “Look, we’ve got all this seismic data. We have a ton of seismic data, 90 million acres of seismic. A lot of it from our heritage shallow water.”
Now, Talos generally is a deep water player now, but we have all this seismic. We have this understanding. We know the big land owners along the coast of Texas and Louisiana. We know the state regulators. Obviously, we know all the federal regulators. Why aren’t we playing in this? And then a project came up, which was the request for proposals right off of Port Arthur and Beaumont. It’s called the Jefferson County GLO project with the General Land Office of Texas.
And we decided to put some bids in on that being very creative about thinking about CO2, thinking about how you model a plume, really understanding the geology. And we put what I think was a very thoughtful proposal in front of the State of Texas. And it was the prevailing bid. And it had a lot of bidders. Had some players who you might think would be the obvious candidate that would be a bid, but they picked ours. And when they did, that’s really where we said, “Look, we can do this, and we need to chase it everywhere it makes sense.”
And we have the emissions data. We have our seismic data. We know the geology. Let’s just work hard.” So, we started chasing projects and that leads us to where we are today. Ultimately, that led us to bringing in Robin, who’s got a different experience in the value chain as a midstream CEO. So, we’ve really built this out. So, long answer, but just catching you up to the beginning and the genesis to where we are today.
David Deckelbaum:
Absolutely, and appreciate that background, Tim. Robin, maybe you want to talk about what attracted you to the opportunity at Talos, someone that had extensive experience on the midstream side and why this all made sense for you.
Robin Fielder:
Sure. Great. And thanks for having me again. My most recent role was leading and running Noble Midstream Partners, which became part of Chevron in 2021. And after running integration there and taking a step back, deciding what I wanted to do next, it really was focused in and around energy transition. And as I began doing my own evaluation of the space and figuring out for myself, where can my existing skill sets and knowledge base really play in this space where we’ve got some advantages?
And where it made the most sense to me, I independently came up that I thought carbon capture sequestration was really what makes the most sense for a lot of both upstream and midstream players when you think about what we’re doing in the subsurface and then gathering in order to get to injection for permanent storage. Especially what we’re thinking about proposing here is in saline aquifers, which conventional exploration and production companies know quite well as we drill through a lot of those, but it’s just another reservoir that we can characterize and better understand.
So on that journey, I happened to run across the Talos team and just had been seeing some of those press releases and seeing the quick speed of the team, the agility. The ability to get out in front of this was very exciting for me. So, I was happy to join and come lead this team and help shape that. We’ve got, again, a team focused with calculated speed, but also really focused on the customer and working in and around on what that end emitter needs and seeing if we can contract and come up with solutions that work for everyone.
David Deckelbaum:
Thanks for that. Tim or Robin, maybe you can just describe a bit the business model that you’re trying to develop on the CCS side. We can get into all of the projects that you have out there, but maybe just starting at a high level, the business model that you’re attempting to build right now or that you are building right now and how you maybe see that differentiated from some of the other CCS competitors along the Gulf Coast.
Tim Duncan:
Again, Talos started 10 years ago. The company before that was called Phoenix Exploration Company. And we were actually one of the bigger operators in coastal waters of Louisiana. We had assets in coastal waters of Texas. And so, we just have a real depth of familiarity with the geology and the operations and what we need to do to execute operationally in shallow water and in those water depths. It’s just, if you will, a bit of our heritage. And so part of this is it’s really interesting.
We’re going from suddenly being an oil and gas operator, which is absolutely who we are and who we’ll continue to be to also building a vertical that Robin’s running that’s really a service provider, but we’re transferring the same skill sets. And that was what was so interesting for us. We’ve got to know-how. We understand the regulations. We understand the operations. We can drill Wells. We can move quickly. Business development’s something that we strive in, but we’re offering something different and we’ve got to converse with and work with a different type of partner. And that is an industrial emitter who suddenly becomes a customer.
And that’s really the big differentiator, but I think for us, there just wasn’t any reason we couldn’t do some of the building blocks that will ultimately lead to interacting with that customer, which is get the right pores great space, know how to describe it, partner with midstream and really understand the engineering. We’re also used to managing really big projects. When we’re in deep water, we’re managing complicated multi-billion dollar projects that have multi-years of planning. There’s a little bit of that in CCS, and we’re not afraid to offer and understand those engineering services and how we do it. And so I think that’s something that we’re comfortable in.
David Deckelbaum:
I guess aside from the process familiarity of working with … I think you point out the contract us of operating offshore versus onshore and how much advanced planning is required and detailed project orientation. Is there an inherent advantage to doing ECS offshore versus the … Obvious, the positioning of where you are along the Gulf Coast and the emissions profile there and the number industrial emitters there, but is there an inherent advantage that you think you would have over some of the pore spaces onshore?
Tim Duncan:
Look, I’ll grab that one. I can offer some … We’ve talked about this, which is interesting as an oil and gas operator, “Hey, the geology doesn’t know the coastline.” There’s certain formations in certain trends, in certain age geology. And when you go back however many millions of years in time, it really doesn’t understand in today’s time where five feet in of shallow water or 10 miles inland or 10 miles offshore. We’re looking for three characteristics.
We need really good geology, a good geological column with good porosity, good permeability that can accept the CO2 and it can get absorbed by the saline aquifers. So, we need good geology. We need it to cover a fairly large area, because we’re trying to put away emissions for 10, maybe hopefully 25, 30 years. So, you need it to cover a big bulk volume, a big area, and we’d want a lot of old wellbores. If that happens 20 miles inland, totally find us. We’ve been there and we can handle it. If it makes more sense for them to be five miles offshore, we absolutely get that as well.
So, I don’t think we’re trying to be preferential to offshore than onshore. Just trying to be preferential for those three characteristics of geology, ultimately bulk volume in space, and then lacking old wellbores and potential P&A obligation to stay away from.
David Deckelbaum:
That makes a lot of sense. Maybe that can dovetail a little bit into just discussion around some of the projects that you have in front of you. I guess how should US and the community think about the differences between, I guess your four main projects? You have two hubs and two point sources. Can you give a brief description or overview of those and tell our audience the difference between the hub and point source?
Tim Duncan:
Go ahead, Robin.
Robin Fielder:
Yeah, I’ll jump in there. So, when we’re thinking about a hub, we’re talking about said oversee as an industrial cluster of emission. So, you’re going to have several emission sources that will require some midstream gathering solution to collect all of those and get them piped to the injection sites or in many cases, it will be multiple wells with multiple monitoring wells. This is great for scale, so you can collect quite a few emissions and build out a major hub. As Tim was talking about, we’d like to have a nice, big, contiguous leasehold. And so right off shore provides an opportunity, but we’ve also been successful onshore.
So, three of our four announced projects have onshore sites. Compare that to a point source where we’re really talking about a single emission source, we’re able to, in many cases, do that right on site or right adjacent too, so your stream solution there is very minimized, which allows for lower cost and really short cycle times. So, you’ve got some enhanced economics when you think about reducing that cycle time and upfront cost, but obviously a lot smaller scale. And so, our vision is to build out a portfolio of these de-carbonization as low carbon solutions continue to maintain that first mover advantage.
Again, really be that partner of choice, whether it’s with the end customer and meet them where they’re at and see what they need, which is our example with Freeport LNG doing that solution right there, in and around the fence line or to attract new customers and even partners as we build out these hubs. So, most recently we announced a partnership and the Port of Corpus Christi with both the port and Howard Energy, for instance. So, that’s great where we align stakeholders that can help us with these projects. We gauge the best places there we’re seeing and the viability of a long-term project in the region.
Tim Duncan:
When you think about these hubs, as you guys know … You’re running a podcast on this, a lot of people want to be in space. Not just folks that maybe had some upstream experience. Obviously there’s captured technology. There’s midstream players who want to know, can they use either their infrastructure or can they use right of ways? We recognize. So, to make these work, we’re going to have to pull in additional partners that can combine and put together really the best offering for wherever that addressable market is.
And as Robin talked about, what we’re doing in the River Bend area, which is along the Mississippi River, what we’re doing recently announced in the Coastal Bend area, which is in Corpus Christi, those are nice examples of utilizing part who are local with the right infrastructure, so they can have the best chance of actually making those things go.
David Deckelbaum:
Now, that might be a good segue into I know some of the questions that we have around some of your partners. Marc, maybe you want to ask them some around some of the partnership opportunities that they’re pursuing right now.
Marc Bianchi:
Yeah, certainly. And I think there’s the question of partnerships and alliances, but also just what your scope is within a project. So, maybe before we get into the partnerships and alliances, can you just talk about… You mentioned the capture piece, which I don’t think you’re going to be involved in, but maybe you could talk about stream piece, which maybe you have some more involvement in. But just from a high level, define your scope on these projects for us.
Robin Fielder:
Say a lot of our focus obviously as a ushering E&P is going to be on that storage and monitoring piece, again, having that expertise and skill set the subsurface, when you think about injection wells and understanding characterizers of more long term. But married to that obviously is the gathering equipment, getting everything up to pressure and ready for injection, again, in the wheelhouse of midstream in both onshore and on offshore platform here. As you move closer back to the emissions, it’ll really depend.
I don’t think you’ll see us designing our new capture tech inside Talos, but we certainly have a technology team that’s looking into all the different technologies, the different key players, and even the EPC contractors. So, as we’re coming to customers with a solution on the gathering and injection side, we can also talk about and be a liaison for some opportunities on the capture side. And in some cases, when it’s pretty straightforward and you’ve got a very pure CO2 stream, such as at Freeport LNG, when you think about separating off the CO2 from the LNG, that’s pretty straightforward.
And that’s an offering that we can help provide and contract that out and do that right on site. So, I think we’ll be a little bit bespoke on how we approach this, but it’s a great evolving space when you think about the capture technologies as well. So, as folks are deciding that they want to capture their emissions and have a permanent storage solution, we’re going to be there with them to walk through those opportunities. And in many cases, as we described, a complete bundled solution when you talk about the midstream and gathering piece and getting it into the storage site.
Marc Bianchi:
So, one of the point source projects is Freeport, which you just discussed. There’s another one. And then you’ve got the two hubs. What type of industry is the other point source, if you’re willing to discuss? And then within the hubs, as you think about the opportunity set there, what types of capture applications are you really focused … If we think about dividing up the CO2 molecules that are coming into the hub, what proportion of industry are they coming from?
Robin Fielder:
So, our most recent announcement is for of the Coastal Bend project partnership with supportive Corpus Christi and Howard Energy. So Howard Energy’s got an extensive midstream network there and is already connected to some of the industrial emissions in and around the Coastal Bend area is the name of the region. And so what we’ll be doing is we’ve got an option on 13,000 acres to go out and find that best place and just test the pre-FEED and viability of the project.
So once we get that lease subscribed, we’ll be able to talk a little bit more about that. So for right now, we’re talking about it as point source, meaning we’ll probably already be tied into some of that. It is expandable to a micro hub or even larger hub over time. And none of our thought as we step into this, being able to lease some of the ports land onshore is a little bit more straightforward when you’re talking about bringing in onshore equipment to do this. So, it should be pretty easily to scale if we’ve got enough acreage that works and is contiguous and meets those three characteristics that Tim mentioned earlier.
Marc Bianchi:
And then on the hubs, is it largely hydrogen production that’s coming off of a refinery and someone’s capturing CO2 and feeding in your system or is it power gen? Just any thoughts on a high level industry exposures?
Robin Fielder:
That’s a great question. We really need to get those anchor emitters announced. We haven’t done that quite yet, but you bring up a great point. And that’s why we’re really supportive and are hopeful to see the enhancements on the 45Q tax code. Because today there are some sectors that are economic at the $50 for ton of CO2, where you’ve got ethanol ammonia. We’ve mentioned LNG some chemicals, some hydrogen, and even some gas processing, but for many of the other harder to abate sub-sectors, like your other refineries and coal, cement, steel, even some of the gas power and other petrochemicals.
They’re really waiting for that enhancement. And also hopefully, we’ll get direct pay with that too that’ll allow those tax credits to be more easily moved from owner to owner with less value leakage. So, as we’re waiting on that, we’re having a lot of these discussions. And some folks have already made the call that they want to go and do this. And as they’re looking through their captured technologies, the thing that we’re hearing is, “We need you to be out and ready in advance.” And so, we’re out putting together these stores, putting together our partnerships and again, trying to provide that bundled solution.
So that way, when they make that call, that they’re ready to put in that captured technology, however that may look, we’re ready to go and announce those.
Marc Bianchi:
Okay, great. I think we’re going to talk about lead times in a little bit, because that’s certainly an important part of the project. In terms of the partnerships you have … So I’m aware of the Carbonvert one and then TechnipFMC, which is a company that we follow. So, we’re very aware of that one, but could you just talk to those and then if there’s any others that we should be aware of? Just what’s the nature of those agreements or partnerships, and what does that other party bring to the agreement that’s really so beneficial?
Tim Duncan:
Let me jump on that, because I think Robin just hit a point that’s really actually critically important. First of all, an alliance might be something where one of these service providers has something that they can offer. It could be engineering services, it could be evaluation services where they want some exposure to really learning about how to apply that into CCS space. And frankly, we want a way to stretch our capital. And Robin mentioned earlier, we’ve talked to a lot of emitters. And we got to understand that this isn’t risk-free for us.
We’re going to go drill some stratigraphic tests and move along our EPA permits, and that is in anticipation that there’ll be a market there. And as Robin mentioned, on the 45Q tax credit, there’s still some work to do for some of that addressable market. So, having an alliance partner, figuring out how to stretch your capital program, bring them in, let them also take some risk alongside of you makes sense. Now, on the partnerships, that’s where you’re really talking about somebody who’s going to have an equity stake in the project.
And so as you get these things closer to FID, even if we were to go out and grab some pore space and what we think is a very good store, that’s not going to be the partnership when you get the FID. You’re going to have to bring someone else in the value chain who wants some to the project. And again … So, I’ll give you a couple examples. Carbonvert was a group that had some experts and had been in this space before. We were just getting started and working on that first bid off of Jefferson County.
And we leaned on that expertise for that particular project. And then I would anticipate as we get closer to FID, you’ll probably see another member of the value chain come in. When you look at River Bend, that was one where now at that point, here we are six months from the first startup. We have our legs underneath us. We really know what we’re doing. So, we put together all the geology and everything we needed to do there, and then we approached EnLink. And we had a great conversation with those guys, because they have such obvious infrastructure.
We said, “Guys, we can put the pore space and the store and your infrastructure in one partnership and make sure that the customer base knows there’s a solution right here, they don’t have to take 15 meetings a day, they could give an obvious and answer.” And so pulling … And the same thing with Howard Energy. They are the obvious answer there. And so if you can find members of the value chain who want to partner in a project, divide up the economics to where it makes sense for everybody and have one offering to customer base, then I think you’ve got a better chance of these projects making it.
If we all have to cannibalize each other to figure out how to put emissions in the ground, this is going to take forever. And so, again, alliances helps stretch our capital, gives a chance for those service providers to be in this and learn as we learn. Great. And you’re going to hear more of those alliances, partnerships really bringing something to the value chain with really the hopes of just accelerating all this, because you’re going to have to have those pieces put together.
Marc Bianchi:
Can we talk a little bit about maybe the size of investment for a project like you’re considering? And this is coming from a bit of a selfish place as a service analyst, trying to figure out what the revenue opportunity is for the companies that I follow and just understanding too how much differentiation there might be among those companies that providing services. So, you have the alliance with Technip, but there’s several other companies that can provide sub-sea services and wellheads and trees and so forth.
So, maybe just talk to us about the invest dollars that could be involved and maybe how you would bucket how much goes into the actual sub-sea installation, how much is in the midstream piece, maybe how much is in further closer upstream to the point of capture?
Robin Fielder:
Sure. I’ll jump in on there. So recently, we just announced our 2022 capital budget, and you’ll notice the CCS portion of Talos’ capital investments for the year is roughly about 5%. So still relatively small. A lot of that is continuing our leasing works, the lease cost and then drilling some of these stratigraph test wells that we’ve mentioned, which we feel will be necessary for some of these Class VI permits. So again, trying to stay on the very quick line and staying out in front of what we know will be the critical path item, and that’s the approval of these Class VI permits.
But I was trying to characterize a different project type. So if you’ve got a point source, again, you’ve got minimal midstream infrastructure that’s needed for that, you’re really talking more about the injection wells themselves, drilling those injection wells, drilling the stratigraphic tests, and then hopefully you can reuse that strat test for monitoring purposes as well. So, we’ll have some permanent bottomhole gauges to monitor, as well as use some surface technology. So, those projects, pretty straightforward.
You can think of those probably in the tens of millions of dollars versus when you start talking about regional hubs, it’s really going to just depend on the expanse there. And the good news is that it’s scalable. So once you get that backbone pipe to the site, then it’s just the incremental emission you can bring on really helps those returns, just like any other large infrastructure project. So, that’s why getting that anchor emitter to underwrite the project with a significant amount of emissions is critical for us.
So we have yet to announce that, but as we talk to different potential customers, that’s how we’re thinking about that. Those kind of projects could lead into the hundreds of millions of dollars, just depending on how large and how many different store and then how many injection wells will be required.
Tim Duncan:
Right. A couple things to think about. Look, every injection well’s got to be monitoring well. And as Robin alluded to, we’re going to pull some deep water technology into this platform. And it’s really interesting not to be too nerdy about it, but this is a stratigraphic section at six to 8,000 feet below the ground that we just ignored, because we blew right through it. Why would I need to go really describe a bunch of wet aquifers that have nothing to do with my hydrocarbon extraction at 12, 13, 14,000 feet?
But now we’re going to go back and not only describe it, which really is historical and gas guys, you’re laughing at yourself for describing aquifers, because you’re avoiding those at all costs typically when you’re doing all the gas stuff. But we’re going to describe it and then we’re going to go drill another well, say a mile away, that’s going to have bottomhole pressure equations to really understand, are we injecting in zone? Are we seeing a pressure built?
So anybody involved in … And these are going to have to be probably bigger hole wells, different casing programs. So, all the casing, all the cementing, all the bottomhole technology, all the valuation, all those folks are going to be in this, amongst the service cycle, and just depends on where those alliances could fit. All the engineering design and how we want to do the injection. We do have, on the oil and gas side, a project in deep water, which is one of the few water flood projects where we’re injecting water and we’re not sourcing it outside the sub-sea environment.
So, to say we’re experts in sub-sea technology and subsurface technology, there’s no doubt about that. So, it’s just a different type of type of project and different type of work streams. And then obviously on the midstream side, there’s a lot to do there. But it really comes down to the emitter. Most of the capital’s going to be on the emission side, particularly when you get to multi-combustion plants, utility plants, things like that.
But it can be, for every million metric tons, we’re going to need an injection well and a monitoring well. So, if we have a hub that we think is good, can do eight to 10 million metric tons, you can think about eight to 10 injection wells and another 7, 8, 9 monitoring wells. So, you can start to grid that out visually and you can think about the capital and supply just for the storage and monitoring. If I got to go 10 miles, 15 miles, you can think about the cost per mile on that.
It adds up. These regional are going to be very, very, expensive. And that’s why you’ve got to have the right incentive structure for these folks to capture the emission, so that we can move them in a tolling fee type infrastructure.
Marc Bianchi:
Maybe just one on that, and then I’ll turn it back over to David. But in terms of the infrastructure and moving CO2 around, my understanding is CO2 can be pretty corrosive to a natural gas pipeline and carbon steel. How much retrofit do you think we’ll see to pipeline infrastructure for some of the projects you guys are looking at versus a greenfield construction, just because of the different characteristics of the molecule?
Tim Duncan:
Again, we’re describing saline aquifers, which we’re avoiding when we’re doing the oil and gas stuff. Now we’re talking about moving CO2, which generally we were avoiding that are corrosive. So we do have to adapt and we have to adjust. And Robin can talk about how we do that in the business space.
Robin Fielder:
Right. It’s a great question, and it really just comes down to, if you think about design specs of pipe. And so if you’ve got some existing pipes that’s already high pressure and has had CO2 through it, obviously there’s an advantage there. So, you’re right. CO2 can be very corrosive, mixed with water. So one of the pipe specs be to get this very dehydrated and really dry out the water and trained in the CO2. So, that component of the dehydration. The pipe itself, we’ve got to look at the different metallurgy make a wall fixed.
And a lot of it has to do with trying to … In diameter, to get the CO2 up and underpriced supercritics. We like easier if moving more like a liquid state and it’ll be for us to inject into these saline aquifers, and then to dissolve the solution there where we can monitor that longer-term. So, those are the key things we look in all of the pipe and the [inaudible 00:28:56] around the 800, 900 PSI. And we’re talking of a thousand PSI for what we’re going to need for that supercritical state.
So in some, it’ll be repurposing, in some re-using cases, it’ll be some length and type and just existing right of ways where we have that.
Tim Duncan:
But look, as Robin mentioned, it’s new. We’ve been dealing with gas properties. We’ve been dealing with our whole careers. We thought about it in a different way. The level of which you need to create it really depend on the pipe. Typically, it was mixed with other things and now it’s really not, because we’re trying to inject that. So, we just have to think about the process differently. Again, a lot of that’s not technology from a transportation and injection vector.
David Deckelbaum:
Maybe on the regulatory side, you talked a lot about before, and we’ve heard a lot about from the industry on Class VI permits, we discussed 45Q earlier. Right now, is everything overseen by the federal government? How are states involved? And what’s under their purview, particularly in Louisiana? And what’s your outlook on how difficult it’s going to be to obtain some of these permits?
Tim Duncan:
Our background, mostly we operate on the west side, controlled by the federal government. So, we deal with Interior, with DPA, we deal with Department … We deal with these folks all the time, because again, we’re on federal land. We’re familiar with how the federal government can and move. And when they’re motivated, they can actually move pretty quick. If politically or policy-wise, they’re not as motivated, it can move a little slower. This is an area where I do think that the policy is aligned with everyone’s objectives.
And I do think this is one of the things that if we think about transition, we’re electrifying everything. Could be debatably nothing is certainly inappropriate. Here, carbon capture, I think a lot of bipartisan support. So, we’re hoping that makes its way into having urgency around permits, but there’s not a lot of history. There’s, you need to drill as well. Do you have enough information
[inaudible 00:30:56]
how it’s going to be injected? I think there’s going to be an iterative test early on.
And so I think to really … Not everybody else is going to have to be in front of the government, try to move these things as quickly as we can. The states want to be involved, but right now it’s a federal process. And so you’ve heard about the term primacy and well, just be involved and be able to manage that process at the state level. Will Louisiana do it? And Robin has some views. I think ultimately that might be the case, but I don’t think it’s going to be the case certainly right away.
Maybe Louisiana is a little closer than Texas, but really we don’t know or in various other permitting regimes and permitting goal for these states to do. But I think they’re doing it in Wyoming. Maybe we’ll get there by the end of the year, but I would tell you, for us, just saying, “Hey, look, that’s a big gating item. It’s going to take too long and we’re not interested.” Two is these are fairly complicated projects and we can get out and start working on it. And we’re just going to have to take a little bit of that policy and timing risk and just get this thing moving, or else, we’re not going to be there when the customer’s ready to make the investment on the capture side and be there.
But it’s going to be a lot of work on public policy makers and various government entities. But again, we’re familiar with it.
Robin Fielder:
I’m just going to jump in and reiterate what Tim said today that regulatory body is the EPA for both our projects in Texas and Louisiana. But as Louisiana’s filed for that primacy, we’re hopeful we can accelerate that along and that Texas will be right behind it. Where you’ve got these state regulatory bodies, like the Department of Natural Resources and the Railroad Commission that are much more familiar and better staffed to issue these permits. We do injection wells. Salt water injection wells go through the state today.
We’re hopeful that that’ll take place. And meanwhile, that we’ve got a lot of support from both the Biden administration, really bipartisan support and then support of these clean climate tech technologies, energy transition. So, hopefully to put the pressure that we’ve got enough staffing, even at the EPA, to help push these permits forward.
David Deckelbaum:
Thanks, Robin. Tim, you alluded to this before, just perhaps the rest of the industry, maybe it’s just an area of ignorance or just the unknown, but the perception that Class VI permits are just such a hassle that, “I don’t want to deal with it. I’m not going to get involved in this.” Maybe you can con contrast … Permitting for a deep water well and offshore Gulf of Mexico is not easy. So, can you contrast the experience in permitting for an oil and gas well that Talos has experience in versus permitting for a Class VI injection well, and some of the different preparations involved with that?
And if you would balance one as being significantly more challenging than the other, other than the obvious, which is there’s not a ton of precedence for Class VI wells.
Tim Duncan:
But look, it’s a good question, because what we do at deep water is extremely complicated. Before we go drill a well, the level of design work we do to show the government that what we think we’re doing is safe … And particularly some of this coming out of the 2010 Macondo incident, we do a lot of detailed calculations on what could be a worst case discharge. We do just really a ton of work, and sometimes that’s iterative. We might present something and they’ve heard something somewhere else. And they could ask a question, and we can say, “Look, we can look at that iteration and come back with them with more data.”
And so you get used to that. And that now, if you find something, congratulations. You got to put a full working plan together on the development side and think of a two-well sub-sea tieback that goes 15, 20 miles and 4,000 feet of water. What are all the characteristics of that? What does the government need to understand if you’re putting in a new facility, the amount of testing and understanding on those facility designs. Again, we’re used to that, but as Robin said, we’re dealing with an interior.
The Bse is a very mature organization. They’re used to managing these permits. They’re used to plowing through them. And so you do have the right staffing and the right folks on the other side. So, we’re totally prepared to get them involved in the Class VI process. We’re prepared to do whatever we need to make it work. If it’s drill a start well, if we have other data … And we understand the iterative process, but what you also need is enough staffing on the other side to say, “We’re also familiar with it from a regulatory agency perspective. And here are the questions we have. And if you can answer these questions, we’re prepared to give you the permit.”
So, it’s just going to be a little bit of a learning exercise and whether that stays with the federal government or moves to the states. But I think for us, we’re comfortable in that space. We understand the level of organization we need to turn things around very, very fast. And it’s one of the reasons we got into this. We’re just used to working with that agility. And we’ll manage that here as well.
Robin Fielder:
One of the things that you need for a Class VI, it’s called an MRV plan. So, it’s a monitoring reporting and verification. So, it’s similar in the fact that it’s really your development, how you’re going to handle this long term. And it’s all the technologies in our wheelhouse today, as far as some of the advanced metering, even the bottomhole gauges I mentioned earlier. So, that’ll be a big advantage for us, but also a piece that’s going to have to go into these permit applications.
David Deckelbaum:
Maybe we can touch a little bit, on the regulatory side, on 45Q. And Robin, you mentioned the 45Q earlier. How critical is a 45Q upgrade to your projects that you have in Q2 right now and how do you view the current 45Q standards as either being supportive or an impediment to progressing?
Robin Fielder:
As I mentioned earlier, there are some sub-sectors within the different industrial bases that the $50 works today, but for many, they really need to see that enhancement in order to make them make that decision that it’s time to start capturing. So, meanwhile, while we are able to subscribe and start to talk to some customers such as Freeport LNG, where it works today, the rest, they’re getting prepared. They’re hearing the pressures from both their own shareholders and board of directors.
They’re hearing that, “Yes, we need to de-carbonize,” and they want to look for solutions, but it’s really about making that move, including the direct pay piece that’ll really allow them to make that call. So, meanwhile, while we’ve been waiting for that, and we’re still encouraged that since it has bipartisan support that at some point it’ll get through, it’s given us a little time to get together, get these key partnerships and technical alliances in place, and really build out our portfolio of stores and offerings back to the customers.
And we’re hopeful we’ll get something passed that enhances those tax credits hopefully sometime this year, but it’s hard to say exactly when.
Tim Duncan:
When you think about the projects, if you’re going to announce a point source, a couple things probably have to happen. That industrial partner probably has a bigger footprint of land, and they really need. So, maybe their industrial process takes up … I’m going to make up a number, three, 400 acres, but they have 2,000 acres of fence line. They don’t want to butt up to a school or a neighborhood or anything of that nature. And then they’re sitting on good geology and the current credits work.
That’s checking a lot of boxes, but if you can check those boxes, then there’s no reason to wait, “Why aren’t we working on capturing these emissions? And let’s just hurry up and get the permitting started,” which is how the Freeport project works. Once you start getting around ports and you start getting around bigger cluster of emitters, the chances that they have all those characteristics, all that excess land right around their property, it’s probably less certain. And so that’s where the hub model is really going to be the model that we need to make work if we’re going to do the most good of putting the most emissions in the ground and storing it and monitoring it.
So, the hub model, I think, is the biggest benefit model when we think about broad emissions, but it also is the one that needs probably the most help on 45Q, because you’re addressing as big of an emitter market as possible. So, to make the hub model work, which I think is the model that has to work, you’re just going to need some policy help. I think you can do a lot of small things from a point source perspective, and that’s great. We should do those things, but it’s really not going to put a dent in the issue.
David Deckelbaum:
Absolutely. Maybe you can characterize the customer landscape right now. And we talked about, there is a lot of available space at different industrial sites for build-out and things like that. But this seems like, if you’re able to obtain that permits, if you’re able to provide a bespoke solution, that this is like a very simple, “Check the box. Great. You guys, go ahead and do of this.” Is there resistance from customers? Robin, you talked earlier about, announcing some anchor emitters and things like that.
Maybe if you can encapsulate the entire customer ecosystem right now and maybe points of resistance or concern that’s out there, and really how quickly you see this opportunity developing.
Robin Fielder:
Sure. As we’re going out, having these conversations with our potential customer base, we’re hearing various trends, but a lot of it’s really angled toward, they know they need to do this. There’s a desire to de-carbonize their business. So it’s just, when is that trigger point? And we know we’re not the only shop in town. There’s other folks trying to go out and do this. We’ve been very successful in getting some projects pulled together, making some announcements.
And I think that’s key. Again, it’s about this first mover advantage, this calculated speed and having these bundled solutions. So, the more we can come back to the customer with not just an injection store site, but also some midstream solution to get it there, the better off we’re going to be. And if we can even bring in and suggest some other partners on the capture side too, I think that’s helpful as well if you’ve got some that are still considering what capture technologies they want to place on their kit.
So, we’re really looking at trying to find that complete solution. Meanwhile, with the customers, it’s looking at who it is. So, it’s great that we’ve got a balance sheet as well, that we’re one of the recognized leaders in the offshore space. So, if you’re talking about going to the GLO and being able to operate and successfully manage that, I think there’s a lot of credibility history there. A big piece of this is operational assurance. So, making sure that as we take those CO2 and we go and inject, that it’s going to be there permanently. We’re going to be monitoring it for decades.
So, there’s got to be that good space and the understanding that we’re going to be committed to that. And so as we go out and contract this, that’s why we’ve talked about a tolling model, a long-term off-take, if you will, from the customer, since we are taking on that risk and making sure we can store it permanently. So, it’s just a little bit of the back and forth as everyone gets prepared and hopefully for some enhanced 45Q. Meanwhile, definitely progressing some conversations with some folks.
Tim Duncan:
Look, I think there’s certainly some industrial partners and emitters that are wondering, “Hey, can we do this ourselves and do it around our facilities?” And I think what we’re trying to do is just represent, “Look, you’re going to want better operational assurance than trying to do that yourself. Rely on folks who are in this space on this part of the value chain.” But these guys are getting inundated with calls and with ideas. And that’s why I think for us to make this work, we’ve got to pull together the right partnership as fast as we can, so that the industrial emitter can say, “Hey, look, I can see it. I can see where that makes sense. I can see where maybe that’s a better lower risk solution.”
And that’s a good counterparty, because you want to pull these guys into one counterparty bundle, and then let’s go in that direction. But we totally understand the overwhelmness, if you will, that the industrial guys are having with the phone calls they’re getting and what’s going through their minds as they think about it.
David Deckelbaum:
Absolutely. Maybe that can get into the next portion of just maybe some of the milestones that you see ahead for Talos’ progress this year and things that the investment community can look forward to help maybe better understand story and some of the projects you’re working on.
Robin Fielder:
Sure. So, as I mentioned earlier, so the Coastal Bend announcement, that one is a lease option. So, as we go out and explore, we’ve got nine months to look at the reservoir and work with Howard Energy on potential plans there. So, it would be pursuing and actually getting that to lease form. Same thing with the Jefferson County GLO. Get that lease fully executed. So, that’s obviously first to have that buttoned up. Next is the anchor emitters. So again, trying to get those guys subscribed, where we can announce that would be great.
Meanwhile, we’re going to continue to advance these and from pre-FEED into FEED. So, as we’re thinking about that critical path item of the Class VI permit, we’ll be out collecting all that information and data that we need to appropriately characterize that reservoir and propose that MRV plan on how we’re going to monitor these injection wells in our stores long-term.
Tim Duncan:
I think Robin talked about our budget earlier. We have a potential store. We’re going to go think about drill strat test this year definitely on the Freeport acreage. Really likely, potentially all of them. And so, we want to get that ball moving. And then, if you can see a Gantt chart, we’ve got a little bit of this and I would encourage anybody listening to go grab our investor deck, because we talk about it in the appendix or some timelines. It just really depends on, what are the gating items?
We know permitting’s always going to be a gating item, but what else in parallel do we need to get the first revenue? And the point source is not a lot. It’s really the permit, and then let’s get going. So that could be the first commercial injection on any project along the Gulf Coast certainly coming up. And that could be as early as 2024. But then as you get into some of these other hubs, it’s just, how quickly can we get that anchor emitter? Robin talked about that as well. And how can we spec out the pipeline to what we can use and reuse, what we may have to rebuild?
And boy, there’s so many moving pieces there. But I think we all want them to happen fairly quickly. Could it take four to five years for a hub to really start to show itself? That might, and then the point sources can happen quickly, but for you, again, deep water projects don’t happen overnight, stand timelines, understand how to get to those timelines and how to work parallel streams. And we just got to understand there’s just a lot of gating items and milestones that have to happen before you can get a revenue generated here. But when you do, it’s a long-term revenue source and it’s a bit of a yielding type of investment.
Robin Fielder:
Last piece is real critical, about project financing for these various projects. So, we want to get everything to a project FID-ready status. So it’s all the contracts. It’s all the pre-FEED and FEED. It’s getting that Class VI permit then approved for, and then securing the financing and then really getting after it with the construction and building this out, leading towards a first injection.
David Deckelbaum:
Maybe sake of asking an existential question, to wrap this up. And you started with the genesis of how Talos got involved with CCS. And now it’s a couple years into this process. You’re balancing a legacy oil and gas company that still had a number of prospects in the Gulf of Mexico and some different targets. That industry is very much calling for a return on capital model, like a maturity model. And you have on the other side, this emerging growing business opportunity with carbon capture and storage.
I guess, existentially, are you finding yourself … Do you think Talos has created the identity that once, is it finding the right investment community? Is it being looked at the way that you think Talos should be looked at right now? And do you think that you’re being welcomed properly into this energy transition ecosystem?
Tim Duncan:
Yeah. Look, that’s a great question. I would say the quick answer is yes, because I’m at an equities conference. Robin and I both go be attending several equity conferences in the next week. If you look at the meeting schedule, there’s going to be HSBCs, interested investors coming into the space. Look, we had somebody on the stock, in the 2021 of our biggest shareholders who’d been in the stock over 10 years moved out of … And that puts a little bit of a technical cover on the stock.
But I think now we’re backed on the fundamentals. Totally understand where the paradigm shift has been on the oil and gas side from growth, the value. We’re a small cap trying to push cap. So, I think as we drive down our cost of capital, as we get our leverage stat, close times … And it was about 1.3 times before the pandemic. So, it’s always been very competitive. We’re going to focus on that model, but we’re still company … Again, three years public, and dare we say the word growth, but we’re still growing this business.
We think we’re growing on the oil and gas side responsibly. We think we’re a natural consolidator. And I would tell you, for a lot of the majors who are thinking about de-carbonizing their portfolio, part of that is selling oil and gas assets to what they think are responsible stewards. And one thing we’re trying to show in the CCS business is we are responsible stewards of assets and we can be the second owner of the mid-life asset for the majors as well.
So, there’s a lot of duality here. I’m trying to build a responsible business and be a steward on the oil and gas side. And we’re trying to take those skills and build a vertical platform on the de-carbonized side. And then we think both of those grow and come to a stable place. And then we’re talking about returning some of that capital to shareholders. So, we’re probably in a little more of a transition than maybe a company that’s a large cap, certainly some of these bigger companies that went through a restructuring and they come out with a super clean balance sheet, but we’ll get there. It’s obviously where every company should aspire to be.
David Deckelbaum:
Absolutely. Tim and Robin, I want to thank you for your time today. This has been a wonderful conversation for us, and we’re certainly looking forward to following all of Talos’ successes in the year ahead here.
Tim Duncan:
That’s great. It’s great to have us.
Speaker 1:
Thanks for joining us. Stay tuned for the next episode of Cowen Insights.
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