Geothermal energy is on the verge of a major expansion. For decades, geothermal power was limited to places where hot water naturally reaches the surface, like Iceland or parts of the western United States. New drilling and engineering techniques are changing that, making it possible to tap Earth’s heat almost anywhere on the planet. With a global average cost of $0.060 per kilowatt-hour in 2024, geothermal is already competitive with hydropower and closing the gap on solar and wind, while offering something neither of those can: round-the-clock, weather-independent electricity.
Why Traditional Geothermal Hit a Ceiling
Conventional geothermal plants need a rare combination of underground conditions: extremely hot rock, water already present in the rock, and enough natural permeability for that water to flow through and carry heat to the surface. These conditions exist in only a small fraction of Earth’s land area. That’s why geothermal has supplied roughly the same tiny sliver of global electricity for years, even as solar and wind capacity exploded.
The next generation of geothermal technology removes one or more of those requirements, dramatically expanding where plants can be built.
Enhanced Geothermal Systems
Enhanced geothermal systems, or EGS, are the most commercially advanced of the new approaches. Instead of relying on naturally permeable rock, EGS projects create their own underground reservoir. Water is pumped into deep, hot rock at high pressure, opening up fractures that allow the water to circulate, absorb heat, and return to the surface as steam or superheated fluid.
Recent advances in directional drilling (steering a drill bit horizontally through rock, borrowed from the oil and gas industry), slim-hole drilling (using narrower boreholes to cut costs), and targeted stimulation techniques have made EGS far more practical than early experiments suggested. Chemical and thermal stimulation methods can now enhance rock permeability without relying solely on hydraulic fracturing, giving operators more control over how the underground reservoir develops.
The most tangible proof of progress is Fervo Energy’s Cape Station project in Utah. Fervo reported a 70% year-over-year reduction in drilling times between its pilot project and Cape Station. During a standard 30-day production test, a single well achieved a maximum flow rate that could generate over 10 megawatts of electricity, triple the output of Fervo’s earlier pilot. Cape Station is expected to begin delivering 24/7 carbon-free electricity to the grid in 2026, with 400 megawatts fully contracted and scheduled to be online by 2028. That’s enough to power roughly 300,000 homes.
Closed-Loop Systems Avoid Key Risks
One of the persistent concerns with EGS is induced seismicity. Fracturing rock underground can trigger small earthquakes, and in rare cases, ones large enough to be felt at the surface. The geothermal industry has developed risk management frameworks that include traffic light protocols (green, amber, red thresholds that dictate whether operations continue, slow down, or stop), real-time seismic monitoring networks, and structured communication plans for nearby communities. These systems have improved significantly, but the concern hasn’t disappeared.
Closed-loop geothermal systems sidestep the issue entirely. In a closed-loop design, the working fluid stays sealed inside a pipe the entire time it’s underground. It never contacts the surrounding rock or exchanges fluid with the reservoir. Heat transfers into the pipe through conduction, the same way a metal spoon gets hot in a pot of soup. Because there’s no fracturing and no fluid injection into rock, the seismic risk drops to essentially zero.
Closed-loop systems also offer flexibility in choosing a working fluid (it doesn’t have to be water) and can operate in impermeable rock formations that would be useless for conventional or even enhanced geothermal. The tradeoff is efficiency: conduction transfers heat more slowly than convection, so closed-loop wells produce less power per well than an EGS system tapping the same temperature rock. Whether that penalty can be overcome through deeper drilling or better heat-exchange designs is one of the key questions the industry is working on.
Super-Hot Rock: The High-Energy Frontier
The deeper you drill, the hotter it gets. At depths greater than 5 kilometers (about 3.1 miles), rock temperatures in many locations exceed 374°C, the point where water reaches a “supercritical” state. Supercritical water carries dramatically more energy per unit of fluid than the lower-temperature water used in conventional geothermal. A single super-hot rock well could potentially produce five to ten times more power than a standard geothermal well.
Research out of Stanford University’s geothermal engineering program describes super-hot rock geothermal as a steadily advancing frontier. The core challenge is building wells that survive extreme temperatures and pressures (above 374°C and 22 megapascals) in hard crystalline basement rock. Drill bits wear out faster, conventional cements and steel casings degrade, and electronics used for downhole measurements fail in those conditions. However, researchers have concluded that these challenges are surmountable using combinations of existing technologies, not breakthroughs that haven’t been invented yet.
If super-hot rock systems become commercially viable, geothermal could provide long-term, scalable, renewable baseload power in locations far from any volcanic activity. That’s the prize: a clean energy source that works everywhere, around the clock, with a tiny surface footprint.
How Geothermal Costs Compare
According to the International Renewable Energy Agency, geothermal power achieved a global weighted average cost of $0.060 per kilowatt-hour in 2024. For comparison, onshore wind came in at $0.034/kWh, solar at $0.043/kWh, hydropower at $0.057/kWh, and offshore wind at $0.079/kWh. On raw cost per kilowatt-hour, geothermal looks more expensive than wind and solar.
But that comparison misses something important. Wind and solar produce power only when the wind blows or the sun shines. To deliver reliable electricity around the clock, they need battery storage or natural gas backup plants, both of which add significant cost. Geothermal runs 24 hours a day, 365 days a year, with capacity factors (the percentage of time a plant actually produces power) typically above 90%. Solar panels operate at roughly 15 to 30% capacity factor depending on location, and wind turbines at 25 to 45%. When you account for the full cost of delivering dispatchable, always-on power, geothermal becomes much more competitive.
The rapid drilling improvements seen at projects like Cape Station suggest costs will continue falling. Fervo’s 70% reduction in drilling time translates directly into lower well costs, since drilling is the single largest expense in any geothermal project. As the industry scales and standardizes equipment, the same learning-curve dynamics that drove solar panel prices down over the past two decades could apply to geothermal drilling.
Lithium From Geothermal Brines
Geothermal plants in certain regions pump up not just heat but mineral-rich brine. In California’s Salton Sea region, that brine contains significant concentrations of lithium, the critical mineral used in electric vehicle batteries and grid-scale energy storage. The U.S. Department of Energy estimates that the existing 400 megawatts of geothermal capacity in the Salton Sea area is already producing brine containing about 21,500 tons of lithium per year. That lithium isn’t currently being recovered, but extraction technologies are in active development.
The longer-term resource estimate for the region is enormous: roughly 3,400 kilotons of lithium classified as “probable,” meaning accessible with expected technology improvements. Producing lithium as a byproduct of geothermal electricity generation could simultaneously lower the cost of geothermal power (lithium sales offset operating costs) and reduce U.S. dependence on lithium imports. Several companies are building pilot extraction facilities in the area now.
What Stands in the Way
The biggest barrier is upfront cost and risk. Drilling a geothermal well costs millions of dollars, and unlike solar or wind, you don’t know exactly what you’ll find until you finish drilling. A well might hit lower temperatures than expected, or the rock might not fracture the way models predicted. This exploration risk makes financing difficult, especially for newer EGS and super-hot rock approaches where the track record is short.
Permitting is another bottleneck. Geothermal projects on federal land in the United States can take years to navigate environmental reviews, even though the surface footprint of a geothermal plant is a fraction of what a solar or wind farm requires for the same output. Several policy proposals aim to streamline this process, but progress has been slow.
Workforce availability matters too. The oil and gas industry has the drilling expertise and equipment that geothermal needs, and companies like Fervo have actively recruited from that sector. But scaling from a handful of demonstration projects to hundreds of commercial installations will require a much larger pool of trained workers, specialized rigs, and supply chain capacity that doesn’t yet exist.
Despite these obstacles, the trajectory is clear. The technology works, costs are falling, and the value of always-on clean electricity is rising as grids absorb more intermittent solar and wind. Geothermal is shifting from a niche resource tied to geology to a broadly deployable energy source, and the next decade will determine how fast that shift happens.