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 our 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.
Transcript
Stephen Lacey: Mark your calendar for June 12th, 2025. Latitude Media is holding its fourth transition AI conference in Boston. This year’s theme is 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, SparkFund, KKR, Generate Capital, Orennia, Flexgen, National Grid Partners, and more. Plus, we’re going to have a live open circuit episode featuring Caroline Golan from Google and a Live Green Blueprint episode featuring Rick Needham from Commonwealth Fusion Systems. Get your ticket at latitudemedia.com/events. Podcast listeners get 10% off their ticket. Use the code LATITUDEPODS10 at checkout. Latitudemedia.com/events. We will see you at Transition AI.
Tag: Latitude Media: covering the new frontiers of the energy transition.
Shayle Kann: I’m Shayle Kann and this is Catalyst.
Carl Hoiland: When you look at the full stack 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
Shayle Kann: Up next: the heat beneath our feet.
I’m Shayle Kann. I invest in early stage climate technologies at energy impact partners. Welcome. So is geothermal having a moment? Here’s the case for. It’s clean firm baseload Power, which is a hot commodity right now. Hyperscalers have all expressed interest. Some of them have signed PPAs for Fervo energy, notably has PPAs both with utilities and with Google for hundreds of megawatts of new development. And the Trump administration and 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 for is a lot stronger than the case against here to be honest. And so I wanted to bring on Carl Hoylan 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’ll soon see, and I have taken great advantage of that myself. So it’s your turn. Here’s Carl.
Shayle Kann: Carl, welcome.
Carl Hoiland: Hi. It’s great to be here.
Shayle Kann: Alright, 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.
Carl Hoiland: 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 emerge in the United States in the 1960s with the initial development being in the geysers field in northern California. And it 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, drive 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 nineties and two thousands where you really see almost no growth. And then another tip up in the late two thousands, early 2010s, and then it’s been flat almost until just recently.
Shayle Kann: And even that tip up in the late two thousands and early 2010s, I mean, how much did we build during that period? We added hundreds of megawatts, but they were
Carl Hoiland: 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.
Shayle Kann: I think a lot of people know this to be true of nuclear. 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 a roughly similar timeline, which I find kind of intriguing, not exactly the same, but similar kind of story. So what happened? Why did it stall out?
Carl Hoiland: Well, I think there were a couple of things that happened in the early days. he early technologies could really only work with very high temperature steam. And so they were looking for exceptional locations in the earth’s crust 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 came 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 scare 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 in 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.
Shayle Kann: 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, what’s actually going on in the subsurface?
Carl Hoiland: Yeah, so at the geology or geothermal 1 0 1 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 magmatic 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 vulcanism or magmatism, 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. 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.
Shayle Kann: And so with the geysers projects, for example, which by the way are still producing power, some of ’em, right? It’s amazing. It’s a great resource. We just kind of got lucky in that case or is that just such a good resource that you know what I mean? 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 first time around in the geysers it just happened to be the overlap?
Carl Hoiland: 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 Unical, Phillips Hunt, and others that entered into the space in the late seventies and early eighties, 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 depth.
Shayle Kann: Can you just give a little bit more detail on the difference between a conventional or a hydrothermal field and an EGS field? What are you looking for in each?
Carl Hoiland: Yeah. In a conventional geothermal field, you need to find the temperature. So 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 fluid can circulate through extract heat, you’ll bring it out at the surface, then you’ll reinject 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 the 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 just drill a well and have what you need versus needing to modify the subsurface in some way.
Shayle Kann: Okay, so the failing, the reason that the markets 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 these 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 walk me through 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? Right?
Carl Hoiland: 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 a hundred 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.
Shayle Kann: One question I’ve always had about this, ultimately if you’re finding a resource, you’re going to be drilling deeper than a hundred feet or a thousand feet. So it 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 a hundred foot depth, well what the temperature gradient, what the temperature expected would be at a kilometer or something like that. Is that right?
Carl Hoiland: 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.
Shayle Kann: So you drill this temperature gradient hole, 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
Carl Hoiland: In terms of the drilling to really confirm a resource. Before that you will have deployed even lower costs, 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.
Shayle Kann: Okay, so you drill your first well, which is your temperature gradient hole. How easy is it? Is it binary? I assume it’s not binary, but 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?
Carl Hoiland: In the early days, there was a lot of uncertainty. There 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 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 and what kind of resource you’re working with.
Shayle Kann: Okay, so let’s say you drill your temperature gradient hole, you confirm, you see what you’re looking to see, and at least your interpretation is positive there. What’s the next step?
Carl Hoiland: 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. IIs 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 as mini production wells that are going to be able to allow you to pull water out of the system
Shayle Kann: 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?
Carl Hoiland: 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
Shayle Kann: And rough order of magnitude. What is the cost of one of these wells in depth?
Carl Hoiland: Yeah, in this case, you’re going to be going to a few thousand feet, maybe as much as five or 6,000 feet, and your cost is going to be in the million plus range. So call it one to 2 million, maybe three or four depending on the more complex wells to prove that out.
Shayle Kann: So this is where you, I presume historically when it became more difficult to finance, the cost of capital got higher and higher. This is the step where real money starts to show up. I would assume
Carl Hoiland: 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 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.
Shayle Kann: 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’ve gotten your temperature gradient, but then you drill down and you can’t flow anything.
Carl Hoiland: 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 five, 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.
Shayle Kann: 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 de-risked at this point? Do you know what you’ve got?
Carl Hoiland: You’re much further along the route of de-risking, 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.
Shayle Kann: Can you describe what, I know I brought up decline rate, but I realize 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?
Carl Hoiland: 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 reinject it, the water’s 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 maintaining pressure in your system.
Shayle Kann: 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?
Carl Hoiland: Let’s see. So we recently actually drilled a new production well down at an 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.
Shayle Kann: That’s sizable. 50 megawatts is sizable, but ideally, probably you want projects that are multiples of that size or an order of magnitude bigger. That’s right. 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?
Carl Hoiland: And this is an area of research and really just a 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 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 had two or three or four wells here, how much will that impact my decline versus just doing one or two in the same location?
Shayle Kann: 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 top-side? 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, but–
Carl Hoiland: Yeah, 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 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.
Shayle Kann: 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?
Carl Hoiland: 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-inject your fluid back into the ground and that working fluid just cycles through the system.
Shayle Kann: So I think we’ve reached the end of the development process. Curious about the timeline, both historically and maybe today, 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. 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 gas turbines are backorder for five years and nuclear takes nuclear timeframes. What is the timeframe of exploration and development for geothermal historically, and how much opportunity is there to compress it?
Carl Hoiland: 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 major part of that is the slow decision making. As I mentioned, the sort of incremental de-risking 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 designs and constructed a new production well to a zone that was four times deeper than 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.
Shayle Kann: 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 geysers 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?
Carl Hoiland: 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 economics. As drilling costs come down or as demand for clean firm power continues to increase, we see the economics 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.
Shayle Kann: Can you give me an order of magnitude of how much power we might, well, let’s say we stay in the western third of the United States. What’s the total resource size that we expect? When you look
Carl Hoiland: At the full stack 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, a hundred 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.
Shayle Kann: Alright, Carl, always appreciate you schooling me on geothermal. Thank you so much for joining.
Carl Hoiland: Thank you, Shayle. Great to be here.
Carl Hoiland is the co-founder and CEO of Zanskar. This show is a production of Latitude Media. You can head over to latitude media.com for links to today’s topics. Latitude is supported by Prelude Ventures. Prelude backs, visionaries, accelerating climate innovation that will reshape the global economy for the betterment of people and planet. Learn more at preludeventures.com. This episode was produced by Daniel Woldorff. Mixing and theme song by Sean Marquand. Stephen Lacey is our executive editor. I’m Shayle Kann, and this is Catalyst.
