.svg){kind=avatar}
As pressure mounts to deliver 24/7 clean electricity amid growing demand, our first article examined why geothermal is emerging as a vital part of the decarbonization puzzle by exploring policy support, market drivers, and reliability advantages. Today we turn our attention to four core technology pathways driving geothermal forward: conventional hydrothermal and binary-cycle plants that harness steam and hot water; ground-source heat pumps paired with community thermal networks; engineered enhanced geothermal systems that create reservoirs in hot rock; and advanced closed-loop designs that seal high-temperature loops deep underground and unlock scalable, dispatchable energy across diverse geographies. At Energy Capital Ventures, we champion these Green Molecules™ because they deliver reliable, zero-carbon power and flexible thermal services, unlock deep decarbonization, and create long-lived infrastructure value—the exact ingredients utilities and industries need to build resilient, affordable clean-energy systems.
How They Work: Conventional geothermal plants tap naturally occurring underground steam or hot water (hydrothermal resources) to generate electricity. In dry steam plants (the first geothermal plants, like The Geysers in California), steam from deep reservoirs is piped directly to turbines. More common today are flash steam plants – high-pressure hot water is pumped up and flashed into steam as it enters a low-pressure tank, then routed through a turbine. After powering the turbine, fluids are reinjected to sustain the reservoir. In regions with lower-temperature resources, binary cycle plants are used: hot geothermal water heats a secondary working fluid (with a low boiling point) in a heat exchanger, vaporizing this fluid to spin a turbine. The geothermal water never contacts the turbine, which mitigates corrosion and allows using resources that aren’t hot enough to produce steam on their own. These binary systems have expanded geothermal power into places with moderate-temperature wells that were once considered unusable.
Performance and Cost Trends: A key strength of conventional geothermal plants is their reliability. They operate at very high capacity factors (often 85–90% or more) – far above coal or gas plants, and vastly outpacing wind or solar. This means a 50 MW geothermal plant often delivers as much annual energy as a 100+ MW solar farm, due to around-the-clock output. Geothermal is also prized for its capacity to provide ancillary grid services (voltage/frequency support) like a traditional power plant, making it a true “baseload” resource for utilities.
Despite running continuously, geothermal has a tiny environmental footprint. Emissions average ~45 g CO₂ per kWh – an order of magnitude lower than natural gas or coal. Water and land use are minimal (on the order of 1–8 acres per MW) since energy is drawn from a compact underground source. Modern flash and binary plants reinject fluids, maintaining reservoir pressure and preventing subsidence or depletion of the resource. Some even turn waste streams into value: for example, geothermal brines can contain minerals like lithium that developers are now looking to extract. In fact, the geothermal brine in California’s Salton Sea could yield up to ~170,000 tons of lithium per year – a potential $2+ billion annual market for battery material. Co-producing critical minerals could improve project economics while supplying new value streams.
Improvements and Innovations: Conventional geothermal’s main drawbacks have been its high upfront costs and geographical limits. Developers must spend tens of millions on exploration and drilling with no guarantee of hitting a productive reservoir. Moreover, the “easy” hydrothermal fields (typically in volcanic or tectonically active regions) are limited. However, recent advances are chipping away at these challenges:
From a utility business model perspective, conventional geothermal fits well into power portfolios as a long-term asset with stable output. The high upfront capital can be justified by low operating costs and 30+ year project lifetimes. New financing models, like energy offtake agreements with tech giants (e.g. Google’s 2023 deal to buy geothermal power) are helping de-risk investments. Utilities in regions with known geothermal potential (e.g. the U.S. West, East Africa’s Rift Valley, Indonesia’s volcanic zones) are increasingly seeking geothermal procurement to meet clean energy targets with firm power. Globally, conventional geothermal capacity stands around 16 GW, but untapped hydrothermal resources remain – and binary tech will continue to broaden the map of viable projects.
Not all geothermal energy involves deep wells and power plants. Shallow geothermal harnesses the moderate temperatures just below the Earth’s surface (typically 50–60°F or ~10–15°C at depths of a few hundred feet) to provide heating and cooling. The workhorse here is the ground-source heat pump (GSHP), which uses the ground as a giant thermal battery. In winter, fluid circulating through underground loops absorbs heat from the earth to warm buildings; in summer the process reverses, and heat is dumped into the cooler ground to provide air conditioning. Because the ground stays at a relatively stable temperature year-round, these systems operate very efficiently – often delivering 3 to 5 units of heat for every 1 unit of electricity used to run the pump and compressors. This translates to 300–500% efficiency, far above even the best gas furnace (~95%) or electric resistance heater (100%). In cooling mode, ground-source heat pumps outperform traditional air conditioners, since the ground offers a cooler heat sink than hot outdoor air on a summer day.
Ground Loop Designs: Shallow geothermal installations come in a few flavors. Common for individual buildings is the vertical closed-loop system: contractors drill one or more boreholes (typically 100–500 feet deep) and insert U-shaped pipes that circulate water or antifreeze solution. A heat pump at the surface extracts heat from (or rejects heat to) this loop. Where land is available, horizontal loops can be buried just 4–6 feet deep over a broad area, performing the same function. For larger buildings or campuses, engineers might use an open-loop design, pumping groundwater from an aquifer through a heat exchanger and then returning it to the ground. Open-loop can be very efficient but requires a suitable aquifer and careful management to avoid depletion or contamination. In all cases, the technology is proven, and the primary barriers are often upfront cost and drilling logistics, not performance.
Performance and Decarbonization Impact: A well-designed geothermal heat pump system can supply all of a building’s heating and cooling needs with dramatically lower energy use and emissions. For utilities, this presents both a load challenge and an opportunity. As buildings electrify their heating (to move off natural gas or oil), winter peak electricity demand can soar – but geothermal heat pumps mitigate this by using 60–80% less electricity than resistance heaters. In essence, widespread GSHP adoption could shift a large chunk of heating load onto the electric grid without the massive peak spikes that pure electrification would cause. This makes them an attractive tool for building decarbonization that utilities can support while maintaining grid reliability.
Moreover, shallow geothermal can unlock an entirely new utility service model: thermal energy networks. Instead of each home or building installing its own ground loops, utility or third-party providers can build shared loop fields that serve whole neighborhoods or districts. These are sometimes called “geothermal micro-districts” or networked geothermal systems. The concept is analogous to district heating, but using underground loops as the distribution system. Such networks allow multiple buildings to exchange heat with the ground and with each other. For example, an office building with excess heat (cooling load) can send heat into the loop that a neighboring apartment building uses for hot water or heating – improving overall efficiency. Unlike the one-building-one-system approach, networked geothermal turns heating/cooling into an integrated resource for a community. This unlocks synergy: buildings with different load profiles can balance each other (one’s waste heat is another’s fuel).
Schematic of a ground-source heat pump system in cooling (left) vs heating (right) mode. In summer, heat is pulled from indoors and dispersed into the ground; in winter, stored ground heat is absorbed and delivered into the building. The process is highly efficient, leveraging the Earth as a stable thermal reservoir.
Utility Perspective and Thermal Networks: For gas utilities facing a future of declining fossil fuel use, geothermal networks offer a chance to repurpose expertise (like drilling and customer heating service) toward a zero-carbon heating business. States like New York and Massachusetts have picked up on this – New York’s 2022 Thermal Energy Networks Act now allows utilities to build and operate shared geoexchange systems as regulated assets. Several utilities are running pilot projects to test the model. For instance, utility National Grid is piloting networked geothermal loops in Massachusetts to heat dozens of homes that were formerly on gas, and Con Edison is testing a similar concept in New York City. Early signs show these networks can provide reliable comfort while cutting winter peak demand and eliminating on-site combustion. They also enhance resilience: an underground thermal grid is immune to polar vortexes or fuel supply disruptions, and it can keep operating through power outages using minimal backup power.
From a long-term value standpoint, shallow geothermal enables utilities to decarbonize buildings at scale. Heating is often 30–40% of a city’s CO₂ emissions; electrifying it with efficient heat pumps could drastically reduce those emissions. Utilities can play a central role by offering geothermal loop service – essentially replacing pipelines with plastic loops. Customers benefit from stable, lower heating bills (since heat pumps deliver 3-5x more energy than they consume), and utilities get a new regulated asset base. The main challenges remain educating customers (many are still unfamiliar with geothermal heat pumps) and figuring out business models to handle the high upfront costs. On that front, some creative approaches are emerging – from on-bill financing of heat pump installations to utility-owned loops with connection fees. If these models prove out, shallow geothermal could become a cornerstone of utilities’ strategy to hit net-zero targets, all while modernizing the concept of a heating utility for the 21st century.
What if geothermal energy weren’t limited to the rare spots where nature conveniently trapped hot water in permeable rock? Enhanced Geothermal Systems (EGS) aim to create geothermal reservoirs almost anywhere by engineering the subsurface. In an EGS project, engineers drill deep into hot, dry rock (typically 2–5+ miles down, where temperatures exceed ~150°C). They then inject water at high pressure to fracture the rock, opening up pathways (like a stimulated reservoir in oil/gas) that allow water to circulate and pick up heat. By drilling at least two wells – one for injection and one for production – you create a closed loop that mines heat from formerly impermeable rock. In essence, EGS turns “hot rocks” into productive geothermal wells by adding the one ingredient nature left out: permeability.
This concept has been pursued for decades, but only recently have demonstrations achieved the flow rates and power output needed for commercial viability. In 2023, Houston-based startup Fervo Energy announced a breakthrough result from its full-scale EGS pilot, Project Red in Nevada. Using advanced horizontal drilling and controlled fracking techniques, Fervo stimulated a section of hot rock and circulated water between two horizontal wells for 30 days. The test sustained a flow of 63 liters/second at high temperature, producing an estimated 3.5 MW of electric power – a record for an EGS and a clear proof of concept. The achievement showed that oilfield methods can be adapted to geothermal: Fervo drilled laterals over 3,000 feet long in hard rock and successfully “connected” the wells, something previously unproven at scale. The pilot’s output is expected to supply Google with about 4 MW of 24/7 clean power under a contract by end of 2023. Equally important, it confirmed that many sites once thought uneconomic for geothermal could be developed this way. As Fervo’s CEO Tim Latimer put it, hundreds of sites across the western U.S. now look viable for EGS where conventional geothermal wouldn’t have worked.
A drilling rig at Fervo Energy’s Project Red in Nevada – the United States’ first full-scale EGS pilot – which in 2023 achieved a 30-day sustained flow test yielding ~3.5 MW of power. By applying horizontal drilling and hydraulic stimulation (similar to shale fracking), this project created an artificial geothermal reservoir in hot rock, proving the potential to replicate geothermal anywhere hot rocks are found.
From Pilot to Market: With the technical feasibility demonstrated, the focus now is on driving down costs and scaling up EGS projects. Fervo and others are working to streamline drilling and stimulation methods, reduce water usage, and manage seismicity (small, induced tremors) which can be a concern during fracturing. The goal is to make EGS wells as routine as oil wells. Progress is encouraging – Fervo reports it has already improved drilling speed by 70% on subsequent wells after the pilot. Meanwhile, governments have poured funding into EGS R&D (the U.S. DOE has a dedicated field lab in Utah (FORGE) where new EGS techniques are being tested, and Europe and Australia have had EGS test sites as well). These efforts could unlock an enormous resource. The U.S. Department of Energy estimates that with widespread EGS deployment, U.S. geothermal power capacity could grow from ~3.7 GW today to over 60–90 GW by 2050 – enough to power tens of millions of homes. In other words, EGS could multiply geothermal’s contribution to the grid by an order of magnitude, rivaling other major energy sources.
Crucially, EGS is moving from experiment to commercial reality. Utilities are starting to sign contracts for EGS-based energy, confident it will materialize later this decade. A prime example: in mid-2024, Fervo Energy secured two 15-year power purchase agreements with Southern California Edison for 320 MW of geothermal capacity. This audacious deal – the largest ever for next-gen geothermal – hinges on Fervo’s planned EGS projects scaling up to full power by around 2028. It signals real utility buy-in, driven by the need for clean firm power. California’s grid, in particular, is hungry for geothermal to provide reliability as fossil plants retire, and EGS opens the door to developing geothermal in new areas (including near existing transmission). Other startups and partnerships (some involving oil & gas giants repurposing their drilling expertise) are chasing the EGS prize as well. Pilot projects are active or planned in places as far-flung as France, Japan, and Australia, each adapting techniques to local geology.
Utility and Grid Impact: For utilities, EGS could be transformative. It promises geothermal’s reliability and zero-carbon attributes without being constrained to volcanic regions. In theory, a utility in the middle of a broad geologic basin (with no hydrothermal activity) could still develop geothermal power by drilling deep and creating its own reservoir. This means the resource base for geothermal becomes geographically much larger. EGS plants would provide always-on capacity that complements intermittent renewables and reduces reliance on natural gas peakers or massive battery farms. And because EGS still uses water as the working fluid, plants can be built in a range of sizes – from tens of MW to potentially larger complexes – offering flexibility in planning generation additions.
That said, challenges remain. The economics of the first few EGS projects will be closely watched – can they deliver on cost targets and operate reliably over years? Drilling deep wells and fracturing rock is expensive today, and each project carries resource risk (rock may not fracture as well as expected, or thermal drawdown could occur if the reservoir isn’t large enough). Regulatory frameworks may need updating too; many regions’ geothermal rules assumed conventional projects, not water stimulation in new places. Managing public perception is key – induced seismicity has caused community concerns in a few EGS experiments (for example, a project in Switzerland a decade ago was halted after it caused minor quakes). EGS developers now employ sophisticated seismic monitoring and stop protocols to mitigate this, often keeping quakes too small to be felt. With careful execution, EGS can likely avoid significant seismic issues, but proving that at commercial scale will be important for public acceptance.
Overall, EGS technology is at a similar stage as shale gas was in the early 2000s – a recent breakthrough has changed the outlook, but scaling it will require intense innovation and investment. From a utility perspective, the long-term value is clear: a successful EGS industry means geothermal power plants could be deployed in many states or countries that previously had no geothermal resources, providing a firm clean energy option basically anywhere below ground is hot (which is everywhere, if you drill deep enough!). That could be a game-changer in the 2030s and 2040s as grids strive for round-the-clock carbon-free power.
The fourth category is Advanced Geothermal Systems (AGS), often used synonymously with closed-loop geothermal. These systems take a completely different approach: rather than relying on pumping water through rocks (either natural or fractured), a closed-loop system keeps working fluids sealed within a closed network of pipes underground. In effect, the well itself becomes a giant heat exchanger with the Earth. A simple way to picture it is as a buried radiator: two (or more) boreholes are drilled deep into hot rock, and at the bottom they are connected, forming a continuous loop. A fluid (could be water, brine, or even supercritical CO₂) circulates through this loop, absorbing heat from the surrounding rocks by conduction and carrying it back to the surface. Because the fluid stays in the pipes, there is no need for an aquifer or permeable rock, and nothing is withdrawn or injected into the formation besides heat.
There are multiple configurations being tested. One is a co-axial loop, where a single deep well has an inner pipe and an outer casing – fluid goes down one and up the other, picking up heat at the bottom. Another is the multilateral “radiator” style used by companies like Eavor: two vertical wells connected by a series of horizontal lateral wells several kilometers long, creating a large heat exchange area underground. In all cases, the system is a closed circuit. This has big advantages: no risk of GHG emissions or noxious gases coming up, no need for water except the initial fill, no induced seismicity from fracturing, and no reservoir uncertainty (since you don’t depend on finding or creating cracks – you’re extracting heat directly through the well surfaces). Essentially, if you drill deep enough to hit hot rock, closed-loop tech can turn that heat into useful energy almost anywhere on the planet.
Technology Status and Innovations: Advanced closed-loop systems are still in early stages, but several compelling demonstrations have been made. Eavor (Canada) built a pilot “Eavor-Lite” loop in Alberta in 2019, drilling two wells ~2.4 km deep with lateral connections, and proved it could thermosiphon (circulate fluid by itself once heated) and produce heat continuously. That system has run since, validating the concept. Building on this, Eavor is now developing a larger commercial project in Germany (the Geretsried project) expected to come online in the mid-2020s, which will use multiple loops to deliver both electricity (via an Organic Rankine Cycle turbine) and direct heat for a local district heating network. If successful, it’s projected to supply ~60 MW_th of heat and several megawatts of power – making it one of the first true commercial AGS deployments.
Closed-loop designs are also flexible in how they deliver energy. The heat can be used directly for industrial processes or heating buildings, or run through a binary power plant to generate electricity. Impressively, the closed nature means they can even be operated in a dispatchable mode: by restricting flow, the rock around the well can be allowed to heat up, effectively storing thermal energy that can be drawn out later at a higher rate. Eavor notes their system can act as a sort of giant subterranean battery, providing on-demand bursts of power or heat without any fuel input. This could be hugely valuable for grids – imagine a geothermal plant that normally produces 5 MW, but can ramp to 10 MW during evening peak by having built up extra heat in the loop during the day. Such flexibility, combined with closed-loop’s inherent baseload capability (the ~100% “thermal capacity factor” mentioned by Eavor, positions AGS as a unique hybrid of generation and storage.
Another frontier for AGS is working fluid innovation. Using water is simplest, but some startups are experimenting with supercritical CO₂ as the loop fluid, which can circulate without pumps (driven by density differences) and potentially extract heat more efficiently. Others are looking at nano-fluids or special additives to increase thermal conductivity. The materials science aspect is non-trivial: the pipes must withstand high temperatures (200–300°C or more) and perhaps corrosive fluids, all while minimizing heat losses on the way up. Advances in metallurgy and insulation, often coming from the petrochemical industry, are being applied to solve these challenges. The goal is to maximize heat extraction per foot of well, since drilling is expensive – thus, techniques like adding thermal enhancement materials around the well (e.g. filling the gap with a high-conductivity grout) are being tried to improve heat conduction into the loop.
Geographic Flexibility and Utility Implications: The biggest promise of AGS is its geographic freedom. Since it doesn’t rely on natural reservoirs, an advanced closed-loop system could, in theory, be deployed under a power plant in Florida or a factory in Ohio or a city in Malaysia – places with no conventional geothermal activity. The only requirement is depth: you might need to drill very deep to find sufficiently hot rock in some regions. This is where ultra-deep drilling tech comes into play. One headline-grabbing effort is by Quaise Energy, which is developing a millimeter-wave drilling system (essentially drilling with high-power microwaves) to vaporize rock and reach depths of 10–20 km. At such depths, “superhot” geothermal resources become available – temperatures of 500°C or more. Tapping those could enable a single well to produce hundreds of megawatts (because the energy content of supercritical water/steam is huge). Quaise aims to use this tech to repurpose old fossil-fuel power plants: instead of a coal boiler, a deep geothermal well would supply the steam for the existing turbine. In 2024, Quaise announced a partnership with Nevada Gold Mines to build a pilot deep geothermal system at an industrial site, in what would be the first attempt to retrofit a fossil plant to geothermal for heavy. They have successfully vaporized hard rock in the lab and plan field trials of the drilling by 2025. If it works, it could be revolutionary – virtually any power plant could become a geothermal plant by drilling an ultra-deep well on site.
For utilities, AGS and deep drilling together mean geothermal anywhere, at any scale. A closed-loop project can be tailored: a few small loops for a hospital’s heating, or dozens of loops to feed a 100 MW power plant. Because nothing is extracted but heat, the environmental permitting may be simpler, and community concerns could be lower (no earthquakes, no plumes or emissions, minimal land use – mostly just wellheads and heat exchangers at the surface). This could ease the pathway for geothermal in regions where public acceptance of EGS (with its fracking connotation) might be tougher.
However, significant challenges persist before AGS is widespread. Drilling costs rise dramatically with depth, so hitting, say, 5+ miles deep for meaningful power output is not yet economical in most cases. The energy output per well is currently modest – the Alberta pilot loop only produced a few hundred kilowatts of heat. To make a dent in utility-scale supply, lots of wells or much bigger heat exchange designs are needed. That’s why companies like Eavor are clustering multiple loops together for their first commercial projects. Learning-by-doing and economies of scale should drive costs down. It’s worth noting that oil & gas industry know-how is a major enabler here: techniques for drilling multilateral wells, managing circulation, and designing well materials all borrow from that field, and many ex-oil experts are now spearheading geothermal startups. This cross-pollination is accelerating progress in AGS.
From a long-term strategic view, utilities eyeing deep geothermal see it as a potentially dispatchable, high-capacity clean resource that could be built in their own service territories, creating jobs and utilizing local workforces. Firms like Eavor have pitched their closed-loop tech as complementary to intermittent renewables – a way to fill the gaps without emissions. And because closed-loop systems can also deliver heat for district heating or industrial use, they present a multi-value proposition: one project could provide both electricity and useful heat (or even cooling via absorption chillers), something few energy sources can do.
In summary, advanced closed-loop geothermal is pushing the envelope of where geothermal can go – potentially everywhere. It embodies innovation in both drilling and thermodynamics, and while still nascent, it has attracted serious interest (and investment dollars – together, Eavor and Quaise have raised on the order of $400+ million). For utilities, it’s the part of geothermal to watch for the late 2020s and 2030s. A successful AGS industry would mean that even utilities far from traditional geothermal regions could tap into the Earth’s heat under their feet and deliver clean, continuous energy to customers, all while repurposing the skill sets of today’s energy workforce for tomorrow’s needs.
At Energy Capital Ventures, our Green Molecules™ strategy centers on geothermal’s diverse portfolio—conventional hydrothermal and binary-cycle plants, ground-source heating networks, engineered EGS reservoirs, and advanced closed-loop systems—as the backbone of reliable, zero-carbon power and thermal services. These innovations enable utilities to balance wind and solar with always-on generation, create new regulated heating businesses, and invest in long-lived assets with stable costs and no fuel risk. In Part 3, we’ll dive into the market mechanisms, policy incentives, and financing models needed to scale these pathways into gigawatt-scale deployments. Geothermal is no longer a niche experiment but a foundational element of resilient, affordable, clean-energy systems.
