Catalyst with Shayle Kann - How geothermal gets built

Episode Date: May 29, 2025

Geothermal seems to be nearing an inflection point. With rising load growth, clean, firm power is more valuable than ever. Next-gen geothermal players like Fervo Energy and Sage Geosystems are signing PPAs with major tech firms. Even U.S. Secretary of Energy Chris Wright — a known critic of renewables — has praised the potential of geothermal.  The size of the U.S. geothermal resource accessible through next-gen geothermal technologies like enhanced-geothermal systems is enormous — potentially thousands of gigawatts. But tapping into it hinges on figuring out the economics. So what does it actually take to develop a geothermal project — and how are new tools reshaping the process? In this episode, Shayle talks to Carl Hoiland, co-founder and CEO of geothermal energy company Zanskar, which uses AI for enhanced geothermal exploration. Shayle and Carl cover topics like:  Why geothermal stalled — and what’s changing now The full step-by-step process of developing a project How to avoid exploration risk, also known as dry hole risk Methods for estimating resource size and managing depletion risk The geothermal supply chain  How permitting is speeding up Carl’s outlook for when and where development is likely to happen Resources: Latitude Media: Geothermal could meet 64% of hyperscale data center power demand Latitude Media: Why geothermal might benefit from Trump’s tariffs The Green Blueprint: How a text message launched a geothermal revolution in Utah Latitude Media: The geothermal industry has a potential ally in Chris Wright Latitude Media: Why California lawmakers are warming to geothermal  Credits: Hosted by Shayle Kann. Produced and edited by Daniel Woldorff. Original music and engineering by Sean Marquand. Stephen Lacey is executive editor. Catalyst is brought to you by Anza, a platform enabling solar and storage developers and buyers to save time, reduce risk, and increase profits in their equipment selection process. Anza gives clients access to pricing, technical, and risk data plus tools that they’ve never had access to before. Learn more at go.anzarenewables.com/latitude. Catalyst is brought to you by EnergyHub. EnergyHub helps utilities build next-generation virtual power plants that unlock reliable flexibility at every level of the grid. See how EnergyHub helps unlock the power of flexibility at scale, and deliver more value through cross-DER dispatch with their leading Edge DERMS platform, by visiting energyhub.com.

Mark your calendar for June 12, 2025. Latitude Media is holding its fourth Transition AI Conference in Boston. This year's theme, energy infrastructure in the era of AI-driven load growth. We're going to bring together investors, developers, researchers, and tech companies to talk about the creative ways to meet data center demand. And companies include Fervo energy, form energy, scale microgrids, spark fund, KKR, generate capital, or RENIA, flexgen, national grid partners, and more. Plus, we're going to have a live open circuit episode featuring Caroline Golland from Google and a live green blueprint episode featuring Rick Needham from Commonwealth Fusion Systems. Get your ticket at latitudemedia.com slash events. Podcast listeners get 10% off their ticket. Use the code latitude pods 10 at checkout.

Latitudemedia.com slash events. We will see you at Transition AI. Latitude Media covering the new frontiers of the energy transition. I'm Shayal Khan, and this is Katz. When you look at the full stack of kind of near-term EGS and conventional, we really are talking about hundreds of gigawatts to terawatts of resource potential, as much potential to give as, say, the entire Gulf of Mexico from an oil point of view. Coming up, the heat beneath our feet.

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Predictive, verifiable, and designed to perform when it counts. Learn more at energy hub.com. Trillions of dollars are flowing into clean and critical infrastructure, but those investments aren't driven by technology alone. They're shaped by markets, by policy, by capital, and by the institutions that connect them. I'm Alfred Johnson, CEO of Crux, and host of a brand new podcast, Critical Capital.

Each episode, I talk with people deploying capital, shaping policy and building the clean economy. Tune in as we unpack how progress is actually made. Listen to Critical Capital on Spotify, Apple, or wherever you get your podcasts. Catalyst is supported by Fish Tank PR, an award-winning PR firm focused on climate and energy tech, renewables, and sustainability.

Fish Tank is known for generating prominent and effective media coverage for the brands they work with. If you want a PR partner that's thoughtful, shoots straight, and gets results, you'll like Fish Tank PR. To learn more about Fish Tank's approach, visit fish tankpr.com. That's F-I-S-C-H-Fish-Tankpr.com. I'm Shale Khan. I invest in early-stage climate technologies at energy impact partners. Welcome. So is geothermal having a moment? Here's the case four.

It's clean firm baseload power, which is a hot commodity right now. Hyperscalers of all expressed interest. Some of them have signed PPAs. Fervo Energy notably has PPAs, both with utilities and with Google for hundreds of megawatts of new development. And the Trump administration, particularly the Secretary of Energy, Chris Wright, came into office with very positive rhetoric about geothermal. In contrast to other forms of renewables. The case against is the big beautiful bill that just passed the house last week, which throws the geothermal baby out with the wind and solar bathwater, basically.

So all of that enthusiasm is not currently reflected in legislation, at least, though let's see what happens in the Senate. Anyway, I think regardless the case four is a lot stronger than the case against here, to be honest. And so I wanted to bring on Carl Hoyland to talk a little bit more about geothermal at a high level. Carl is the CEO and co-founder of Zanskar, which is a startup that's leveraging AI to enhance geothermal exploration and ultimately production. But beyond that, Carl is basically an encyclopedia of geothermal, as you will soon see. And I have taken great advantage of that myself. So it's your turn. Here's Carl.

Carl, welcome. I shall. It's great to be here. All right. I want to start with you giving me a history lesson, as you have given me before. But walk me through the history of geothermal power in the United States, in brief. Fantastic. So humans have been using geothermal energy

for many purposes for a long time, but really you see the origins of this power industry emerged in the United States in the 1960s with the initial development being in the Geysers field in Northern California. And this really ushers in this early mover, experimentation phase. You start ushering in this new phase

of early geothermal developments, and they're really exploring for the first time the ability to use this resource to generate electricity. And it's fairly basic at the time. Just take the steam that's coming out of the ground, it through a steam turbine to generate electricity. And usually they were evaporating it at that point. But we see it.

Most of the United States growth actually happens in those first one to two decades. And for a while, it looks like geothermal is just going to take off. It's scaling faster than any other renewable at the time. And through the 1980s, we had gigawatts of capacity in the United States. But then things kind of come to a halt. And you go through this period through the 90s and 2000s, where you really see almost no growth. And then another tip up in the late 2000s, early 2010s, and then it's been flat almost until just recently.

And even that tip up in the late 2000s and early 2010s, I mean, how much did we build during that period? We added hundreds of megawatts, but they were really, in some ways, offsetting some of the losses that we saw in some of the early steam fields. And so in terms of total installed capacity, it's meaningful, but it's relatively minor and not as much as we were hoping. I think a lot of people know this to be true of nuclear. Like, we built a lot of it decades ago, and then we stopped building new stuff in the U.S. I think a lot of people don't appreciate that the same thing is true of geothermal, and actually interestingly on like a roughly similar timeline, which I find kind of intriguing, not exactly the same, but similar kind of story.

So what happened? Like, why did it stall out? Well, I think there were a couple of things that happened in the early days is the early technologies could really only work with very high temperature steam. And so they were looking for exceptional locations in the Earth's crest where this was 200 Celsius and often higher. And it turns out those were relatively rare. And the further down in temperature you go, the more abundant they become.

But the other part of it was that we had so many failures in trying to drill into these resources where there was a hot spring or geyser at the surface. They thought this was a no-brainer. And when they come in and start drilling those deeper wells, they would not find the resource they were expecting. And so this is what we call exploration risk or dry hole risk in geothermal. And it led the industry to start having enough failures to scale. capital investors to say, whoa, should we really be throwing more money after this?

And this kicks off really a race, a lot of it funded by the Department of Energy, to solve the problem in one of two ways. We were either going to get better at finding these systems, so better exploration methods and data types, or we were going to avoid the exploration problem altogether by just engineering and place the things that we needed to make that system work. And so you see the beginnings of both the unconventional enhanced geothermal industry starting at that time, as well as the beginnings of some of the modern exploration methods. Before we talk about the process of exploration and development and so on, from a technical standpoint, what is happening there? What is going on when you have steam at the surface, what looks like it should be a perfect resource, and then you drill down and it's a dry hole? Like what's actually going on under in the subsurface?

Yeah, so at kind of the geology or geothermal 101 level, everywhere on the planet, as you go deeper, it gets hotter usually, or at least in general. And in most places, that's at, say, 25 Celsius per kilometer. So you'd have to go four or five kilometers or so to get to where you'd have steam temperatures. But in certain locations, that temperature is actually elevated, either because of magnetic or volcanic processes that may have brought heat closer to the surface, or in many places in the western United States, even in the absence of volcanism or magnetism, you can have fractures or permeable zones within the earth that will allow it to start convecting hot water from greater depth

to closer to the surface. And hot springs are usually that kind of manifestation where there's hot water circulating, often in a convective nature, to bring that water to where you see it. What we've since learned in the decades since is that where you see hot springs at the surface, those are kind of the outliers.

is that that's the tip of the iceberg. Most of these convective cells of hot water underground are not coming to the surface. And we now know that the majority of them are actually what we call blind. There's no hot spring, no volcano. And you wouldn't have even known they existed had you not, in most cases, drilled into them accidentally.

And so with the Geysers projects, for example, which, by the way, are still producing power, some of them, right? Like, it's amazing. It's a great resource. We just kind of got lucky in that case. Is that just such a good resource that, you know what I mean? Like, I guess what you're saying is that most of the good resources do not show at the surface, and many of the things that show at the surface are not actually good resources. Is it just that that first time around in Geysers, it just happened to be the overlap?

I think that's exactly right. And so the first pass, and this is true for almost all natural resource industries, the first pass is the low-hanging fruit, the really obvious stuff at the surface. There's copper, there's gold, there's steam, there's oil seeping out, let's drill there, and the geysers was just one of those world-class resources. And there may be more of those around the globe yet to be developed, but at least here in the United States, it's unlikely that there's another gigawatt-scale conventional geothermal resource

to be discovered of that type. But there, you're right, there were geysers at the surface, fumaroles. In fact, the early explorers, a lot of them came from oil and gas. You had Chevron, Unicall, Phillips, Hunt, and others that entered into the space in the late 70s and early 80s, and they actually spent hundreds of millions of dollars going out and drilling test holes. looking for more geysers-like fields. And the geysers was such a unique field

in terms of its size and scale. They thought, oh, we just have to drill every few miles, and we'll see something like that if it's out there. And it turns out they didn't find anything like that in all of their searching. But in the process, they did find some of these other geothermal systems, some of which are now being turned into EGS fields and some of which are being developed for conventional.

I think they just underappreciated how narrow and small they could look at the surface and yet still have meaningful power potential. a depth. Can you just give a little bit more detail on the difference between a conventional or hydrothermal field and an EGS field? What are you looking for in each? Yeah, in a conventional geothermal field, you need to find the temperature. It needs to be hot enough to boil water or working fluid. You need to have porosity or permeability in the rock so that that that fluid can circulate through extract heat. You'll bring it out at the surface, then you'll re-inject it so it can

circulate again. And you need water, so that working fluid that's going to sweep that heat through the system. And in a conventional field, all of those exist. naturally. That's what we call a hydrothermal system. EGS was based on that early recognition that we drilled a lot of holes or wells that were hot, but didn't necessarily have the water or the porosity and permeability to be able to circulate the water. And EGS was this hope that we could stimulate or engineer the rocks to have that permeability and maybe even add the water in some cases. And so this in many ways I think is analogous to what you see in oil and gas. The division between conventional oil and gas and unconventional is the ability to

to just drill a well and have what you need versus needing to modify the subsurface in some way. Okay, so the failing, the reason that the market stalled out was we weren't great at exploration at the time. It turns out we sort of lucked into some great resources in geysers and then couldn't replicate that success. And in the process of failing over and over again to replicate that success, it became harder and harder to finance new exploration. And then everybody kind of just fell out of love with geothermal. Now, obviously, we have this resurgence, and as you said, it's coming in sort of two different categories. One is the, can we do better at finding the existing hydrothermal resources, and then the other is, can we engineer them via EGS? Let's talk about

conventional hydrothermal development. Can you kind of walk me through what that, like the actual steps in the exploration and then development process? When you said they drilled a bunch of test wells. What does a test well? What does it cost? Like what is, you know? Right. Yeah. So the first thing you're usually looking to confirm is temperature. You want to see that there's a resource here with enough heat in place to make a meaningful resource. And the standard tool of the industry is what's called the temperature gradient hole. And so you're literally going out and drilling a hole into the ground. Sometimes it's 100 feet, might be hundreds of feet or a thousand feet. And you're going to come back and measure the temperature gradient in there. And based on those gradients, estimate how much heat is

in place and what might be at greater depth. One question I've always had about this. Ultimately, if you're finding a resource, you're going to be drilling deeper than 100 feet or 1,000 feet. So it must be true that the temperature gradient that you find even pretty near the surface is highly correlated. It's like the temperature gradient is a spectrum that is consistent, and so you can infer from 100-foot depth well

what the temperature gradient, what the temperature expected would be at a kilometer or something like that. Is that right? I think directionally it's right in that heat has a harder time hiding than other types of resources, say like oil that might be underground. And so it is diffusing through the rock. But there are geologic processes that can obscure that or make it difficult to see. You might have a lot of cold water sweeping through from the climate or rainfall in an area that obscures the surface of it. And so there's large parts of Idaho, for example, where there are deep geothermal resources that you don't see at all in the first few hundred or even thousands of feet because of that obscuring.

But in drier areas, yes, you're right. You'll often see pretty distinct anomalous caps above these systems. Okay, so you drill this temperature gradient whole, and that's presumably pretty cheap to do. You're not drilling that deep, and depth is the main cost of drilling. And you're not drilling, you're not putting casing or anything like that, right? You're basically just drilling a hole with a sensor, measuring temperature gradient. So I assume that that is a lowest cost part of exploration, at least the physical lowest cost. In terms of the drilling to really confirm a resource, before that you will have deployed even lower cost, shallow and geophysical methods to help you identify the areas that are worth drilling.

But at this point, if you're drilling temperature gradient holes, you're deploying tens of thousands, maybe hundreds of thousands of dollars to test a certain target area. Virtual power plants are becoming a reliable way for utilities to manage capacity. But enrolling devices is just the start. What really matters is confidence, knowing those resources will perform when dispatched and being able to be able to be able to be able to be able to be able to be able to be able to do. Knowing those resources will perform when dispatched and being able to prove it from the control room to the living room. Energy Hub's platform handles the full picture, from near real-time forecasting, locational dispatch, and the kind of rigorous verification that holds up when regulators, grid operators, or leadership, ask, did it deliver?

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So you drill your first well, which is your temperature gradient hole. You, how easy is it? Is it binary? I assume it's not binary. But like what is the, so how much art versus science is there in the interpretation of that data? Is it easy to determine go-no-go or do you have to do something sophisticated? In the early days, there was a lot of uncertainty. They really just weren't enough success cases or even failure cases to help them understand what some of these data types meant.

And so they often use very high thresholds. If it's not boiling, I'm not interested. But increasingly over time, our experience has taught us, like you said before, that even kind of a semi-anomalous or readings at a shallow level might indicate that it's worth drilling deeper. And so it's often an estimation of, given what I know now, is it worth investing additional capital to drill into that resource at greater depth to gain? greater confirmation. And so you can start with some probability distribution of possible outcomes, and the deeper you go and the more capital you invest in the project, the tighter that distribution of outcomes becomes and the higher your confidence is in what kind of resource you're working with. Okay, so let's say you drill your temperature gradient whole, you confirm you see what you're

looking to see, and at least your interpretation is positive there. What's the next step? At that point, you're going to need to put together, if you haven't already, a pretty detailed conceptual model or understanding of what might be driving this system. Is it a volcanic system? Is it a sedimentary system? Is it a fault-hosted system? And that's going to give you a better predictive ability to go deeper into the resource, at least with classical methods here. And you're ultimately going to then want to say, okay, if I've proven temperature, now I need to prove permeability or the ability to flow water through the wells that I would drill here. And so you're going to step up in size and complexity of your drilling program and drill slim wells or small, you think of this mini-production

wells that are going to be able to allow you to pull water out of the system. At which point you're flowing, you leave that well open for a while and flow it, presumably. Is this when you're also able to start to determine what a decline curve would look like, or is this too early for that? It depends on how well you engineer or how large that well is, but the initial step is just showing that you can flow it at commercial scale. And then what you really want to do is be able to flow it long enough to run a flow test and indicate that over time it's not declining too fast. and that you'll be able to manage this resource sustainably. And like Raffordor of magnitude,

what is the cost of one of these wells and depth? Yeah, in this case, you're going to be going to a few thousand feet, maybe as much as five or six thousand feet, and your cost is going to be in the million-plus range. So call it $1 to $2 million, maybe $3 or $4, depending on the more complex wells to prove that out. So this is where you, I presume, historically, when it became more difficult to finance,

the cost of capital got higher and higher. kind of, this is a step where like real money starts to show up, I would assume. That's right. At this point, though, you also have a little more confidence because of your earlier drilling and exploration. So your conversion rate is also a little bit higher. And so, yes, you're putting more capital to work, but you're a little more confident and it's going to be worth it. Those earlier stages, it is less capital, but you have to pursue more projects in parallel, which all sum up to also meaningful amounts of capital.

But when we talk about dry hole risk and what happened historically and so on, is this the stage where the dry hole shows up. Basically, I mean, you might have gotten your temperature gradient, but then you drill down and you can't flow anything. Yeah, you would start seeing it here. And actually, in the early days, they would often skip that intermediate, what I was calling a slim well or more miniature well, and they would go straight to production well. Oh, we've got great temperatures. Let's drill into this. And they might drill the $5, $10, $15 million well, only to realize that there was no permeability or porosity in the rock. And we'd call that a dry well. So hot but dry, no water coming through it. Okay, so next step.

So you drill this well. You're able to flow. You confirm permeability and porosity. You've confirmed temperature. Are you derisked at this point? Do you know what you've got? You're much further along the route of derisking. But until you can also drill the injection well,

which is going to be the way that you reinsert that water back into the system and let it circulate through the rock or through the ground network, you're not actually going to know that full decline rate to be able to build a robust reservoir model or estimate of the long-term potential of that resource. Can you describe what? I know I brought up decline rate, but I realized we didn't describe what causes it. What causes the decline?

You could imagine a scenario where, look, it's hot underground. You just keep recirculating water, and it should work infinitely. Why doesn't it? Yeah, so you are pulling heat out of the system, right? You're taking that to the surface. You're extracting it either through your turbines or through heat exchangers. And when you re-inject it, the water is going to be a little bit colder or quite a bit colder.

And because of that, it needs to extract more heat from the rock before it returns to the production well. And you can think of these two wells. If your injection well is too far away, it actually might not ever return, and you can start to draw down the pressure in the reservoir. If it's too close, where it maintains good pressure in that reservoir, it might return too quickly.

And you can think of that as then not having enough time to recharge in temperature. And part of the challenge was finding that optimal distance where it has enough time to fully recharge, while also maintain pressure in your system. Right. And then kind of moving ahead in the development process, I imagine that the other challenge related to that is, okay, so let's say you're successful,

you drill your production well and your injection well, and it's working. Actually, give me context here. How much power might you generate out of a single pair? Let's see. So we recently actually drilled a new production well down at operating power plant in New Mexico. And that single well,

it's a larger diameter well going to about 8,000 feet depth, and it can produce about 15 megawatts net. So enough to power about 15,000 homes day and night. That's sizable. I mean, 50 megawatts is sizable. But ideally probably you want projects that are multiples of that size or an order of magnitude bigger in an ideal world. So in order to do that, now you're drilling another pair.

And I presume if you're drilling another pair into that same reservoir, you're obviously extracting even more of the heat. And so I assume there is a fair amount of magic in the question of how close together can you put well pairs, first of all. And second of all, basically how much can you extract from a given resource without accelerating the decline? Yeah, and this is an area of research and really just resource understanding that matured a lot over the past few decades as the industry was dealing with their existing resources and looking to expand or preserve them. And this is really where reservoir modeling becomes key. So there's certain data types like your flow and pressure information, but also we can put chemical tracers into the wells that will help identify how long it takes for them in the water to return from injection to production. And based on these, we can build pretty robust models that are bankable in terms of the feasibility that they provide.

And this is where you can start to estimate if I add two or three or four wells here, how much will that impact my decline versus just doing one or two in the same location? Okay, so this is the end. I mean, you drill the well pair. It works. You drill your however many additional well pairs you're going to drill. Now you've got a resource. What are you putting topside? We haven't talked about that yet.

You get the heat out, but obviously heat is not the end of the story. Could be the end of the story, I suppose. Has anybody done just geothermal, like ground geothermal for, I guess ground source heat pumps are this. And the most shallow ground source heat pumps. But in terms of direct use geothermal, there are a number of locations. around the world that do use it is in a direct way. In Europe, they're looking to repower many district heating systems by just bringing in hot water from underground. And even in the United States, the city of Boise, the city of Klamath Falls, they've been running district

heating systems with geothermal where they're just directly taking that heat. At Zanskar, at our company, we're actually working with large mining companies now to also provide heat for industrial applications. And so I think there's a lot of exciting applications there, even before you convert to electricity. Okay, but let's assume you do. want to produce power, which is what most of the projects end up doing. What is the top-side infrastructure that you require? The top-side, in many ways, looks like many other thermal plants. You're taking heat, you're generating steam, and that steam is going to drive a turbine, which then drives a generator and puts electricity onto the grid. In geothermal, especially in the

western United States, oftentimes we're working with such a low-temperature starting fluid that it's more efficient to put that heat into a working fluid, something that boils at a lower temperature. So think of isobutane or isopentane. And for that, we actually use heat exchangers. So most modern systems are going through a heat exchanger. We call this binary. And then that working fluid on the other side goes through the turbine system. And you re-injects your fluid back into the ground, and that working fluid just cycles through the system. Okay. So I think we've reached the end of the development process. Curious about the timeline, both historically and maybe today, you know, we're in an interesting moment now where there's plenty of demand for new power, period,

new sources of generation period, and then in some circles, particular demand for clean firm, which is what geothermal is. But everything is slow right now. Like, it's hard to get anything fast. The fastest thing you can get maybe is renewables, but even that is gummed up by supply chain challenges and all sorts of tax credit issues and so on. But, like, you know, gas turbines are back ordered for five years and nuclear. Nuclear takes nuclear timeframes.

What is the time frame of exploration and development for geothermal historically and how much opportunity is there to compress it? Historically, it was also a fairly long lead time type development. Historical projects took usually over five years and oftentimes as much as 10 years from start to COD. And a major part of that is the slow decision making. As I mentioned, the sort of incremental derisking of a resource. We collect data, go back to the drawing board, decide if we're going to move forward. But another part of it was the permitting timelines is that a geothermal development project

would have to go through five NEPA reviews if on federal lands. And the ability to accelerate a lot of that permitting is another area where we're seeing a lot of progress in the industry. Geothermal was recently given a categorical exclusion for the exploration activities of confirming and verifying a resource, and there's potentially still permitting reform ahead for the construction stage of the project. If you just take it down to the bare bones of you need about one to two years to explore and confirm the resource and about one and a half to two years to construct that power facility and tie it into the grid. So the ideal scenario would be three to four years is realistic. And we're now seeing that as a possibility in certain locations in certain states where the regulatory frameworks are clear enough. And an example, not necessarily of a greenfield build, but of at least being able to come in and do meaningful work in a short.

period of time, is work that we did recently in New Mexico. So we acquired in May of last year, the Lightning Dock Geothermal Field, which is a field that had in many ways, I think, been seen to have underperformed and was no longer believed that it had much upside left in it. We, based on data sets that we had, and the models that we had, really came to a conviction that there was a lot more there to give. And so shortly after acquisition, we permitted, engineered, designed, and constructed a new production well to a zone that was four times deeper than that. the prior production zone. We built new pipelines, the electrical, installed the new line shaft pumps, and we were able to tie that into the grid in less than 12 months from acquisition. So in certain

locations, we can actually move pretty quickly. And in our greenfield projects, we have several veteran areas where we believe four years is a realistic timeline to bring those projects online. So you mentioned locations. I mean, that's the last thing that I want to talk about, I guess, with you, which is talk to me a little bit about the history. I mean, we talked about Geysers and guys is in California, but actually most of the geothermal that has been developed historically is not in California so much as Nevada and places like that. What's your view on how much geographic expansion should we be expecting for this next wave of geothermal development? How wide is the geographic aperture that people are looking at? Yeah, I think in terms of right now,

the technologies that work today and that are on the precipice of commercial scale up in just the next few years, which is really conventional hydrothermal and EGS, we really think you're still going to be limited to tectonically active areas or areas with higher heat flow. And that's about a third of most continental land masses. So think the western third of the United States and many other tectonically active areas around the globe. And the main reason for that is because even with EGS or with conventional, you're still drilling as a primary cost driver. And if you can find that heat closer to the surface, it's going to have meaningful impact on economic. As drilling costs come down or as demand for clean firm power continues to increase,

we see the economic shifting to where you could start to justify new-build geothermal using some of these new methods and even more unconventional locations. We think that timeline could be on the order of decades, though. Can you give me an order of magnitude of how much power we might? Let's say we stay in the Western 30 of the United States. What's the total resource size that we expect? When you look at the full stack of kind of near-term EGS, and conventional. We really are talking about hundreds of gigawatts to terawatts of resource potential.

That to me is super exciting in terms of the United States unique resource potential, because you can think of this as a resource that has as much potential to give as, say, the entire Gulf of Mexico from an oil point of view. This is a real national treasure. And even just focusing on the conventional geothermal resources that I mentioned before, which is where a lot of our near-term work has gone, there are tens of gigawatts, and by some estimates, 100 gigawatts or more of that, which can have a meaningful dent right away without any first-of-a-kind technology risk. And so in terms of adding low-cost, firm, renewable energy in the next five to 10 years, we really think there's a chance to add more with geothermal than any other competitive form. All right, Carl, always appreciate you schooling me on geothermal. Thank you so much for joining.

Thank you, Shale. Great to be here. Carl Hoyland is the co-founder and CEO of Zanskar. This show is a production of latitude media. You can head over Latitude Media.com for links to today's topics. Latitude is supported by Prelude Ventures. Pralood Backs Visionaries, Accelerating Climate Innovation that will reshape the global economy for the betterment of people and planet. Learn more at Praludadventures.com. This episode was produced by Daniel Waldorf,

mixing and theme song by Sean Marquand. Stephen Lacey is our executive editor. I'm Shell Khan, and this is Catalyst.