How it works, how it complements other energy, and how fast the market is maturing
CCEBA sat down with Blair Kendall, a long-time solar developer based in Durham, North Carolina, who has made a transition to geothermal. In this second of two installments we discuss geothermal’s supply chain advantages, its financing challenges, and market trajectory compared with developing technologies.
Q: If this next-gen technology is still at such an early stage, why is it relevant right now?
Good question. The next-gen geothermal scene totally reminds me of solar in the Southeast in the early 2000s—it’s exciting and fun, but at the same time, the costs are high with limited projects—the market hasn’t been built yet. But there are a few reasons why I believe geothermal deployment will accelerate much faster than wind or solar did at the outset.
There is also massive policy, industry, utility, and offtaker support for next-gen geothermal—the tailwinds pushing it forward are tremendous. O&G, especially oil field services companies, see next-gen as a major market opportunity and are plowing capital and know-how into the nascent market. Major renewable energy buyers Microsoft, Google, and Meta are partnering with companies like Fervo, Sage, and Greenfire to provide First-of-a-Kind (FOAK) financing—mainly through flexible PPAs—that get them through the technology startup “valley of death.” Finally, in the federal government, Department of Energy (DOE) funding and Inflation Reduction Act (IRA) tax credits are driving technology development and deployment. The U.S. military is also aggressively pushing next-gen as they see it as the solution to their power resiliency mandate.
Another reason it should move more quickly is that we don’t need to build or create the foundational market infrastructure for geothermal as we did with wind and solar. Next-gen geothermal already has an existing supply chain with vendors from the O&G and geothermal markets quickly adapting to the new opportunities. On the labor side, the O&G industry has a ready, trained labor force, one of the largest labor forces in the country, which can transition into next-gen geothermal. Many see geothermal as potentially smoothing out the cyclical O&G labor markets and stabilizing the labor force.
Most importantly, with load growth rising exponentially and clean energy demand surging, we require gigawatts of clean, firm power. And when you look around the energy landscape, there just aren’t a lot of available options in the near-to-medium term. I believe that next-gen geothermal will move much faster than other up-and-coming technologies like green hydrogen, small modular nuclear reactors (SMRs), and carbon capture and storage (CCS), all of which have delayed deployment timelines. I don’t foresee that these other options will have moved down the cost curve, have solved the technology issues or have the infrastructure in place to deliver energy at scale, in the best cases, for another decade.
Q: What are the challenges to scale the next-gen market?
On one hand, much of this technology is mature—both in geothermal power generation as well as O&G exploration and production —and we are now just applying these technologies to next-gen geothermal. At the same time, there is still significant work to be done in terms of higher heat-resistant equipment, new drilling techniques and reservoir management. We are already more than halfway there. With all the resources focused on solving these technical problems, I feel that this innovation will happen quickly.
Then there is the issue of seismic risk. We have all heard about examples of seismic activity caused by fracking, and there are also a few well-known cases from early geothermal development. These seismic events occur when the drilling and/or operations cause existing tension built up between subsurface faults or fractures to be released. While there are examples of seismic induced earthquakes in the US, of the 1.7 million unconventional (fracked) O&G wells, the number of events is small, and the risk is limited. This risk profile also varies with EGS having a higher risk potential than Closed Loop or Hot Sedimentary Aquifer geothermal. While the risk is low, this doesn’t mean it doesn’t exist and shouldn’t be addressed, as we know from solar and storage, the perception of risk can be as much of an obstacle as the actual risk.
On the front end, the O&G and geothermal industries have learned how to identify subsurface conditions with high seismic risk and to avoid drilling in these areas. At an operational level, the industry has coalesced around a common monitoring protocol to identify any seismic activity and, when identified, to slow or cease operations until the seismic disturbance has worked itself through the fault system. The geothermal industry is acutely aware that its social license to operate depends on ensuring there are no major induced seismic events.
I think a major near-term challenge for geothermal energy development is the front loading of risk capital and the barriers to project financing. Because of the early market stage, we really haven’t seen this play out yet. In solar, wind and storage, we stage gate the deployment of risk capital, mitigating the next level of risk before investing the next tranche of capital—the deployment of risk capital is an upward sloping curve. With geothermal, the risk capital required comes much earlier in the development process, it starts higher, and then declines. While you can derisk the resource validation, at the end of the day, you still need to drill a seven million to twelve million exploratory well to prove the resource. And this drilling occurs earlier in the development process than with other technologies.
Traditional project financing, because of the front loading of risk capital investment, will not work in the same way we apply it to solar, wind or storage development. The first next-gen projects have been utilizing FOAK, catalytic, and venture capital, which just doesn’t scale. There needs to be major innovation in financing structures to take this market to the next level. Geothermal also has a higher cost of capital given the greater perceived risk, which increases its cost. Like with other renewables, this risk profile should improve as we have more deployment and get more project level data.
Q: What is the process for developing a geothermal project?
Like any clean energy project development – it’s complicated. And furthermore, I don’t think that I’m qualified to answer that question. I do think it helpful for us solar and storage developers to understand how all the pieces of a project fit together as a system.
With EGS, there is a vertical production and a vertical injection well, both wells are encased with concrete often all the way down to the bottom of the vertical shaft. In EGS, both these vertical wells have horizontal wellbores that can extend laterally several thousand feet. The injection lateral is drilled parallel and above the production lateral and these laterals are connected by the engineered fracture system. This unit (production well, injection well and reservoir system) is called a well pair and each well pair produces a specific amount of power – think of each well pair as an PV array. From the same well pad, a developer can drill multiple new well pairs extending in different directions and then aggregate the capacity of the well pairs to power one power plant. At some point, the immediate area around the well pad gets saturated and the developer will set up another well pad some distance from the original well site and repeat the process. In large utility-scale geothermal, you will often have multiple power plants operating around a site.
This is important to understand because a 100 MW plant may require around 50 acres on the surface, but then need four or five times that amount for the subsurface system. The developer needs to secure site control for the surface area and subsurface rights, most often the mineral rights, extending far beyond the surface site. In some states, the mineral rights rule, while in others the subsurface heat rights are split from the mineral rights. In a few other states, the mineral rights are tied to the surface ownership. This is a quickly evolving policy area and, as in most renewable development, you need to figure it all out for each jurisdiction.
Q: What are the economics of next-gen and what are future cost projections?
As next-gen is a nascent technology there are few data points to refer to. Cost projections therefore involve a lot of assumptions. And, like other renewables, there are many project variables impacting cost such as the depth of the wells, flow rate of the brine, type of rock, and local labor costs. Most recent data from the field and recent work by NREL has been focused on EGS since it has the greatest potential in the near-to-medium term.
The U.S. DOE’s EarthShots Initiative has announced that it wants to cut the cost of next-generation geothermal power by 90 percent to $45/MWh by 2035. Working backwards, this gives us a starting point of $450/MWh, based on NREL’s work from 2021. Since 2021, we have seen significant advances with several successful pilots and small commercial projects coming online or under development. NREL’s 2024 levelized cost of energy (LCOE) update for EGS with Flash Power Plants (higher temperatures) estimates the current LCOE to range from $84/MWh to $105/MWh, decreasing to $44 to $100/MWh in 2035 and $42 to $94 in 2050. The high-low deltas represent the more aggressive/conservative modeling scenarios as well as resource differentials between regions.
Mike Watson, a researcher at Princeton’s Zero Lab, published recent research on the learning rate—the speed at which they can bring down costs—and its influence on the cost of energy development. His paper shows that with a mid-range learning rate of 15 percent, EGS can become competitive with other technologies in the 2030s. Solar, for example, has had a 30 percent learning rate over the past decade.
Based on the most recent drilling data, Fervo achieved a 70 percent reduction in drilling time from their first well 18 months ago. This already exceeds NREL’s 2035 most likely scenario for drilling. It also shows a learning rate ahead of DOE’s most aggressive estimates.
All of this indicates that next-gen geothermal may come down the cost curve much more quickly than expected…just as we saw with wind, solar and storage costs.
Q: How do we do next-gen in the Carolinas? When do we start?
The best heat resources exist in the Western U.S., so that’s where almost all of the next-gen geothermal development will occur in the near-to-medium term. The East has a significantly lower heat gradient versus the West, meaning you need to drill deeper to access the adequate heat resource. This significantly increases the cost. If you look at the published, high-level EGS resource maps, the most promising heat gradients in the Eastern region are in the deep South or Gulf region (MISO) and up in the Pennsylvania and West Virginia area (PJM). In central South Carolina, southeastern North Carolina, and southeastern Virginia there exist some lower temperature heat resources. We will need some major advances in technology and cost to be able to develop this for power generation.
You can exploit the subsurface heat for direct use in commercial thermal applications right now. Some commercial developers, like SFL&A in Raleigh, use direct geothermal in all of their commercial buildings.
Q: What’s the projected size of this next-gen market?
If you remember, the potential market size of the solar and storage markets were consistently under-projected by the industry groups. I believe that we are seeing the same thing here with next-gen geothermal.
NREL base projections are that the market will reach 90 GW by 2050, which really doesn’t move the needle. NREL states up front that this is a conservative estimate and that this modeling excludes two base assumptions. First, these do not include a scenario where future land availability for solar/wind will be more limited with increased, competing land use and permitting challenges. The second missing factor is the potential flexibility of geothermal dispatch, being able to store the energy in the reservoir and dispatch it when the price of power is higher. I think these assumptions should be included into the modeling as: land-use issues and permitting are not going away and are possibly going to get worse in the future, and the ability of next-gen geothermal to flex power dispatch is technically feasible and has been demonstrated on a pilot level.
We know that the next-gen can flex its power production. The question is how much and for how long. When we reincorporate these assumptions back into the modeling, NREL’s projections jump to around 300 GW by 2050—three times the capacity of the current US nuclear fleet. To add perspective, note the capacity factor for new geothermal is around 90 to 95 percent compared to solar’s 25 to 30 percent; so 300 GW of geothermal energy is equivalent to 900 to 1,200 GW of solar power production. And while the peak production of geothermal and solar may be the same, geothermal is 24/7 firm and dispatchable—a very valuable grid resource.
It’s an exciting time for next-gen geothermal energy. I am a “solar optimist” about the prospects for next-gen geothermal. We will likely have to wait a few years to see how everything plays out, but the market is on the cusp of something big. Stay tuned!
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