Geothermal Energy

Geothermal energy is heat from inside the Earth, kept up by the slow decay of radioactive isotopes in the crust and mantle and by heat left over from the planet’s formation. On average, temperature climbs about 25-30 °C per kilometre of depth (the geothermal gradient). Near plate boundaries, volcanic arcs and rift valleys the gradient can be several times steeper, which puts water above 200 °C within reach of a drill. Almost all of the world’s geothermal power plants sit in these hotspots.

Geothermal supplies a small but steady slice of world electricity. Ember and Our World in Data group it under “other renewables”: about 89 TWh, or 0.3% of global generation in 2025. Installed power capacity is roughly 15-17 GW, depending on the source and how it is counted. Its value lies in how it runs, not in its size. Unlike solar and wind, a geothermal plant produces almost constant output day and night, all year, which makes it one of the few renewable sources of firm, baseload power.

How geothermal power works

A conventional hydrothermal system needs three things: heat, permeable reservoir rock, and water to carry the heat. Production wells, usually 1-3 km deep and sometimes deeper, tap the reservoir. As the hot fluid rises, pressure drops and some of it may flash to steam. At the surface it drives a turbine, either directly or through a heat exchanger. The spent fluid goes back down separate wells, which gets rid of dissolved minerals and helps hold reservoir pressure.

Temperature sets the basic limit. Geothermal fluids are much cooler than the steam in a coal or nuclear plant, so theoretical efficiency is low:

Real plants manage roughly 10-20% net conversion efficiency for high-temperature flash plants and 5-15% for low-temperature binary plants. Since the heat is free, low efficiency doesn’t add fuel cost. It does mean more wells and bigger fluid flows per MW.

Main types of geothermal plant

Dry steam

This is the simplest design: dry steam from the reservoir goes straight to the turbine. Such resources are rare. The two largest are Larderello in Tuscany, where the world’s first geothermal power was produced in 1904 and commercial generation began in 1913, and The Geysers in northern California, the biggest geothermal complex in the world. The Geysers peaked above 1.5 GW of installed capacity in the late 1980s. Overproduction then drained reservoir pressure, and since the late 1990s treated wastewater piped from Lake County and Santa Rosa has been injected to recharge it, keeping net output at roughly 700-900 MW.

Flash steam

Flash plants are the most common choice for high-temperature resources (above about 180 °C). Pressurised hot water rises up the well, part of it flashes to steam in a separator, and the steam drives the turbine. Double-flash plants pass the leftover brine through a second, lower-pressure separator to get more energy out. Major flash fields include Wairakei in New Zealand, Olkaria in Kenya, Tiwi and Makban in the Philippines, Cerro Prieto in Mexico, and Hellisheiði in Iceland.

Binary cycle

In a binary cycle plant, geothermal fluid at roughly 100-180 °C passes through a heat exchanger and boils a second working fluid with a low boiling point (isobutane, isopentane or a refrigerant). That vapour drives the turbine in an organic Rankine cycle. The geofluid stays in a closed loop and is reinjected without touching the atmosphere, so direct emissions are close to zero. Binary units are modular, typically a few MW to tens of MW each, and make up most new plants by number, especially in the US, Türkiye and Germany.

Enhanced geothermal systems (EGS)

An enhanced geothermal system builds a reservoir where the rock is hot but not permeable enough. Water is injected at high pressure to open fractures, then fluid is circulated between injection and production wells. In principle, EGS could open up geothermal power almost anywhere at depths of 3-7 km. Recent gains come straight from shale oil and gas: horizontal drilling, multi-stage stimulation and polycrystalline diamond drill bits. Fervo Energy’s Project Red in Nevada demonstrated a commercial-scale horizontal doublet in 2023, and its Cape Station project in Utah aims for roughly 100 MW in the first phase, with more planned. The US DOE’s Utah FORGE site acts as a field laboratory. Closed-loop designs, which circulate fluid through sealed wellbores with no fracturing, are a related approach.

Direct use and ground-source heat pumps

Geothermal heat is also used as heat, with no conversion to electricity. Direct use covers district heating, greenhouses, aquaculture, bathing and industrial drying. Reykjavík’s geothermal district heating network heats nearly all of the capital region, and around 90% of Icelandic homes are heated geothermally. The 2020 World Geothermal Congress review (Lund and Toth) counted more than 100 GW of thermal direct-use capacity worldwide, but over two-thirds of it was ground-source heat pumps.

Ground-source heat pumps are a different technology. They don’t tap volcanic heat. Instead they use the shallow ground, which stays near the local annual mean temperature (about 8-14 °C in much of Europe and North America), as a steady heat source in winter and heat sink in summer, with a COP of typically 3-5. They work almost anywhere but need electricity. You can size one with the ground-source heat pump calculator.

Leading countries

Capacity figures are rounded ranges from IRENA, ThinkGeoEnergy and national statistics for 2023-2025. Country pages: Iceland, Kenya, United States.

Efficiency and capacity factor

Few generators match geothermal capacity factors. IRENA’s global weighted average for recently commissioned plants is above 80%, and well-run fields top 90%. The fleet as a whole runs lower, often 70-75%, because some older fields are in decline and some plants in markets like New Zealand and the US now run flexibly instead of at constant output. Reservoir management decides a lot. Producing faster than natural recharge pulls pressure down, and make-up wells have to be drilled every few years to compensate. The capacity factor calculator compares annual output with solar or wind of the same nameplate size.

Costs

Upfront drilling dominates geothermal economics. Exploration and well drilling can make up 30-50% or more of total project cost, and each well costs several million dollars with no guarantee it will produce. This resource risk, carried at the exploration stage before any revenue comes in, is the main barrier to investment. That is why geological risk insurance and public exploration funds (as in Kenya, Indonesia and Türkiye) have made such a difference.

• IRENA (2024): the global weighted-average LCOE of new geothermal plants was about USD 0.071/kWh in 2023, with individual projects spread widely around that figure. Installed costs usually run from about USD 3,000 to over 6,000 per kW.
• Lazard LCOE+ (2024): unsubsidised US geothermal at roughly USD 64-106/MWh.
• NREL ATB separates hydrothermal flash and binary plants from deep EGS. EGS is much more expensive today but is projected to get far cheaper in advanced scenarios.

Once a plant is built, operating costs are low and there is no fuel price risk, so with refurbishment it can run for 30-50 years or more. Per MWh of firm, dispatchable output, geothermal holds up well against other low-carbon options. The LCOE calculator shows how a high capacity factor offsets high capital cost.

Land, water and materials

Land. Per unit of energy, geothermal has one of the smallest surface footprints of any source. A power plant and its well pads take up a few hectares per tens of MW, and directional drilling lets many wells share one pad. Pipelines across the field add a linear footprint.

Water. Flash and dry steam plants usually top up their cooling towers with condensed geothermal steam, so they need little outside freshwater, though evaporation can leave less fluid for reinjection. Air-cooled binary plants use very little water. EGS needs water for stimulation and to replace circulation losses, which can add up in arid areas.

Materials. Steel well casing and cement make up most of the material, along with corrosion-resistant alloys for wells and heat exchangers that handle acidic or salty brines. Some brines, such as those at California’s Salton Sea, contain recoverable lithium, a possible new co-product.

Lifecycle and direct CO2 emissions

Geothermal emissions vary more than for most sources, because some reservoirs hold dissolved gases that escape when the fluid reaches the surface. These are mainly CO2, plus hydrogen sulphide (H2S) and smaller amounts of methane.

• IPCC AR5 WGIII Annex III (2014): lifecycle median 38 gCO2e/kWh, range 6-79 g.
• Operational emissions: a 2016 World Bank ESMAP survey of plants worldwide found direct CO2 emissions ranging from a few grams to several hundred grams per kWh, with a weighted average on the order of 100 g. Binary plants that reinject all their fluid emit next to nothing. Flash plants in carbonate-rich reservoirs, for example in parts of western Türkiye and some Italian fields, can match or exceed gas-fired generation. (The UNECE 2021 assessment did not cover geothermal.)

Abatement is improving. Iceland’s CarbFix project at Hellisheiði dissolves CO2 and H2S in water and pumps them into basalt, where they turn into stable carbonate minerals within about two years. Italian plants use AMIS units to strip out H2S and mercury. New plants in Türkiye and New Zealand are increasingly reinjecting all non-condensable gases as standard practice.

Safety and environmental impacts

Induced seismicity is the best-known risk. Most events are micro-earthquakes, but some have caused damage. The Basel EGS project triggered a magnitude 3.4 earthquake in 2006 and was abandoned, and a Korean government investigation concluded that fluid injection at a nearby EGS site triggered the magnitude 5.4 Pohang earthquake of 2017. The Geysers has thousands of small, injection-linked earthquakes a year. Current best practice combines detailed fault mapping, real-time seismic monitoring and traffic-light protocols that cut or halt injection when thresholds are crossed.

Other impacts include H2S odour and toxicity near flash plants without abatement; land subsidence (more than 10 m locally at Wairakei after decades of production without reinjection); disposal of brines containing arsenic, boron or mercury; noise during drilling and well testing; and possible effects on hot springs and geysers valued for culture and tourism. Reinjection and abatement handle most of these, and deaths per unit of energy are low.

Outlook

For a century, geothermal power has been confined to places with generous geology. That may be changing. The IEA’s 2024 report The Future of Geothermal Energy argues that next-generation technologies, EGS and closed-loop systems built on oil and gas drilling know-how, could bring geothermal to most countries. With continued cost cuts, it says, geothermal could meet a substantial share of global electricity demand growth to 2050, and next-generation project costs could fall to around USD 50/MWh by 2035. The US DOE’s GeoVision study also found potential for tens of GW of US capacity by 2050 if drilling costs keep falling. Data-centre operators looking for firm, round-the-clock clean power have become early buyers.

Hydrothermal growth continues in Indonesia, Kenya, the Philippines, Türkiye and New Zealand, and geothermal district heating is spreading in Europe, including Germany, France and the Netherlands. Geothermal complements variable renewables: firm low-carbon output means less storage is needed. Plant locations are on the world power plants map, and the technology comparison page sets geothermal against hydropower and other sources.