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Krafla, a geothermal power station in Iceland
Countries with installed or developing geothermal power projects
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Sustainable energy
A car drives past 4 wind turbines in a field, with more on the horizon
Energy conservation
Renewable energy
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Geothermal power is electrical power generated from geothermal energy. Technologies in use include dry steam power stations, flash steam power stations and binary cycle power stations. Geothermal electricity generation is currently used in 26 countries,[1][2] while geothermal heating is in use in 70 countries.[3]

As of 2019, worldwide geothermal power capacity amounts to 15.4 gigawatts (GW), of which 23.9% (3.68 GW) are installed in the United States.[4] International markets grew at an average annual rate of 5 percent over the three years to 2015, and global geothermal power capacity is expected to reach 14.5–17.6 GW by 2020.[5] Based on current geologic knowledge and technology the Geothermal Energy Association (GEA) publicly discloses, the GEA estimates that only 6.9% of total global potential has been tapped so far, while the IPCC reported geothermal power potential to be in the range of 35 GW to 2 TW.[3] Countries generating more than 15 percent of their electricity from geothermal sources include El Salvador, Kenya, the Philippines, Iceland, New Zealand,[6] and Costa Rica. Indonesia has an estimated potential of 29 GW of geothermal energy resources, the largest in the world; in 2017, its installed capacity was 1.8 GW.

Geothermal power is considered to be a sustainable, renewable source of energy because the heat extraction is small compared with the Earth's heat content.[7] The greenhouse gas emissions of geothermal electric stations average 45 grams of carbon dioxide per kilowatt-hour of electricity, or less than 5% of those of conventional coal-fired plants.[8]

As a source of renewable energy for both power and heating, geothermal has the potential to meet 3 to 5% of global demand by 2050. With economic incentives, it is estimated that by 2100 it will be possible to meet 10% of global demand with geothermal power.[6]

History and development

[edit]

In the 20th century, demand for electricity led to the consideration of geothermal power as a generating source. Prince Piero Ginori Conti tested the first geothermal power generator on 4 July 1904 in Larderello, Italy. It successfully lit four light bulbs.[9] Later, in 1911, the world's first commercial geothermal power station was built there. Experimental generators were built in Beppu, Japan and the Geysers, California, in the 1920s, but Italy was the world's only industrial producer of geothermal electricity until 1958.

Trends in the top five geothermal electricity-generating countries, 1980–2012 (US EIA)
Global geothermal electric capacity. Upper red line is installed capacity;[10] lower green line is realized production.[3]

In 1958, New Zealand became the second major industrial producer of geothermal electricity when its Wairakei station was commissioned. Wairakei was the first station to use flash steam technology.[11] Over the past 60 years, net fluid production has been in excess of 2.5 km3. Subsidence at Wairakei-Tauhara has been an issue in a number of formal hearings related to environmental consents for expanded development of the system as a source of renewable energy.[6]

In 1960, Pacific Gas and Electric began operation of the first successful geothermal electric power station in the United States at The Geysers in California.[12] The original turbine lasted for more than 30 years and produced 11 MW net power.[13]

An organic fluid based binary cycle power station was first demonstrated in 1967 in the Soviet Union[12] and later introduced to the United States in 1981[citation needed], following the 1970s energy crisis and significant changes in regulatory policies. This technology allows the use of temperature resources as low as 81 °C (178 °F). In 2006, a binary cycle station in Chena Hot Springs, Alaska, came on-line, producing electricity from a record low fluid temperature of 57 °C (135 °F).[14]

Geothermal electric stations have until recently been built exclusively where high-temperature geothermal resources are available near the surface. The development of binary cycle power plants and improvements in drilling and extraction technology may enable enhanced geothermal systems over a much greater geographical range.[15] Demonstration projects are operational in Landau-Pfalz, Germany, and Soultz-sous-Forêts, France, while an earlier effort in Basel, Switzerland was shut down after it triggered earthquakes. Other demonstration projects are under construction in Australia, the United Kingdom, and the United States of America.[16]

The thermal efficiency of geothermal electric stations is low, around 7 to 10%,[17] because geothermal fluids are at a low temperature compared with steam from boilers. By the laws of thermodynamics this low temperature limits the efficiency of heat engines in extracting useful energy during the generation of electricity. Exhaust heat is wasted, unless it can be used directly and locally, for example in greenhouses, timber mills, and district heating. The efficiency of the system does not affect operational costs as it would for a coal or other fossil fuel plant, but it does factor into the viability of the station. In order to produce more energy than the pumps consume, electricity generation requires high-temperature geothermal fields and specialized heat cycles.[citation needed] Because geothermal power does not rely on variable sources of energy, unlike, for example, wind or solar, its capacity factor can be quite large – up to 96% has been demonstrated.[18] However the global average capacity factor was 74.5% in 2008, according to the IPCC.[19]

Resources

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Enhanced geothermal system 1:Reservoir 2:Pump house 3:Heat exchanger 4:Turbine hall 5:Production well 6:Injection well 7:Hot water to district heating 8:Porous sediments 9:Observation well 10:Crystalline bedrock

The Earth's heat content is about 1×1019 TJ (2.8×1015 TWh).[3] This heat naturally flows to the surface by conduction at a rate of 44.2 TW[20] and is replenished by radioactive decay at a rate of 30 TW.[7] These power rates are more than double humanity's current energy consumption from primary sources, but most of this power is too diffuse (approximately 0.1 W/m2 on average) to be recoverable. The Earth's crust effectively acts as a thick insulating blanket which must be pierced by fluid conduits (of magma, water or other) to release the heat underneath.

Electricity generation requires high-temperature resources that can only come from deep underground. The heat must be carried to the surface by fluid circulation, either through magma conduits, hot springs, hydrothermal circulation, oil wells, drilled water wells, or a combination of these. This circulation sometimes exists naturally where the crust is thin: magma conduits bring heat close to the surface, and hot springs bring the heat to the surface. If a hot spring is not available, a well must be drilled into a hot aquifer. Away from tectonic plate boundaries the geothermal gradient is 25 to 30 °C per kilometre (70 to 85 °F per mile) of depth in most of the world, so wells would have to be several kilometres deep to permit electricity generation.[3] The quantity and quality of recoverable resources improves with drilling depth and proximity to tectonic plate boundaries.

In ground that is hot but dry, or where water pressure is inadequate, injected fluid can stimulate production. Developers bore two holes into a candidate site, and fracture the rock between them with explosives or high-pressure water. Then they pump water or liquefied carbon dioxide down one borehole, and it comes up the other borehole as a gas.[15] This approach is called hot dry rock geothermal energy in Europe, or enhanced geothermal systems in North America. Much greater potential may be available from this approach than from conventional tapping of natural aquifers.[15]

Estimates of the electricity generating potential of geothermal energy vary from 35 to 2000 GW depending on the scale of investments.[3] This does not include non-electric heat recovered by co-generation, geothermal heat pumps and other direct use. A 2006 report by the Massachusetts Institute of Technology (MIT) that included the potential of enhanced geothermal systems estimated that investing US$1 billion in research and development over 15 years would allow the creation of 100 GW of electrical generating capacity by 2050 in the United States alone.[15] The MIT report estimated that over 200×109 TJ (200 ZJ; 5.6×107 TWh) would be extractable, with the potential to increase this to over 2,000 ZJ with technology improvements – sufficient to provide all the world's present energy needs for several millennia.[15]

At present, geothermal wells are rarely more than 3 km (2 mi) deep.[3] Upper estimates of geothermal resources assume wells as deep as 10 km (6 mi). Drilling near this depth is now possible in the petroleum industry, although it is an expensive process. The deepest research well in the world, the Kola Superdeep Borehole (KSDB-3), is 12.261 km (7.619 mi) deep.[21] Wells drilled to depths greater than 4 km (2.5 mi) generally incur drilling costs in the tens of millions of dollars.[22] The technological challenges are to drill wide bores at low cost and to break larger volumes of rock.

Geothermal power is considered to be sustainable because the heat extraction is small compared to the Earth's heat content, but extraction must still be monitored to avoid local depletion.[7] Although geothermal sites are capable of providing heat for many decades, individual wells may cool down or run out of water. The three oldest sites, at Larderello, Wairakei, and the Geysers have all reduced production from their peaks. It is not clear whether these stations extracted energy faster than it was replenished from greater depths, or whether the aquifers supplying them are being depleted. If production is reduced, and water is reinjected, these wells could theoretically recover their full potential. Such mitigation strategies have already been implemented at some sites. The long-term sustainability of geothermal energy has been demonstrated at the Larderello field in Italy since 1913, at the Wairakei field in New Zealand since 1958,[23] and at the Geysers field in California since 1960.[24]

Power station types

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Dry steam (left), flash steam (centre), and binary cycle (right) power stations.

Geothermal power stations are similar to other steam turbine thermal power stations in that heat from a fuel source (in geothermal's case, the Earth's core) is used to heat water or another working fluid. The working fluid is then used to turn a turbine of a generator, thereby producing electricity. The fluid is then cooled and returned to the heat source.

Dry steam power stations

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Dry steam stations are the simplest and oldest design. There are few power stations of this type, because they require a resource that produces dry steam, but they are the most efficient, with the simplest facilities.[25] At these sites, there may be liquid water present in the reservoir, but only steam, not water, is produced to the surface.[25] Dry steam power directly uses geothermal steam of 150 °C (300 °F) or greater to turn turbines.[3] As the turbine rotates it powers a generator that produces electricity and adds to the power field.[26] Then, the steam is emitted to a condenser, where it turns back into a liquid, which then cools the water.[27] After the water is cooled it flows down a pipe that conducts the condensate back into deep wells, where it can be reheated and produced again. At The Geysers in California, after the first 30 years of power production, the steam supply had depleted and generation was substantially reduced. To restore some of the former capacity, supplemental water injection was developed during the 1990s and 2000s, including utilization of effluent from nearby municipal sewage treatment facilities.[28]

Flash steam power stations

[edit]

Flash steam stations pull deep, high-pressure hot water into lower-pressure tanks and use the resulting flashed steam to drive turbines. They require fluid temperatures of at least 180 °C (360 °F), usually more. As of 2022, flash steam stations account for 36.7% of all geothermal power plants and 52.7% of the installed capacity in the world.[29] Flash steam plants use geothermal reservoirs of water with temperatures greater than 180 °C. The hot water flows up through wells in the ground under its own pressure. As it flows upward, the pressure decreases and some of the hot water is transformed into steam. The steam is then separated from the water and used to power a turbine/generator. Any leftover water and condensed steam may be injected back into the reservoir, making this a potentially sustainable resource.[30] [31]

Binary cycle power stations

[edit]
Main article: Binary cycle

Binary cycle power stations are the most recent development, and can accept fluid temperatures as low as 57 °C (135 °F).[14] The moderately hot geothermal water is passed by a secondary fluid with a much lower boiling point than water. This causes the secondary fluid to flash vaporize, which then drives the turbines. This is the most common type of geothermal electricity station being constructed today.[32] Both Organic Rankine and Kalina cycles are used. The thermal efficiency of this type of station is typically about 10–13%.[33] Binary cycle power plants have an average unit capacity of 6.3 MW, 30.4 MW at single-flash power plants, 37.4 MW at double-flash plants, and 45.4 MW at power plants working on superheated steam.[34]

Worldwide production

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Cracks at the historic Town Hall of Staufen im Breisgau presumed due to damage from geothermal drilling
A geothermal power station in Negros Oriental, Philippines
Geothermal power center in the Usulután Department, El Salvador

The International Renewable Energy Agency has reported that 14,438 MW of geothermal power was online worldwide at the end of 2020, generating 94,949 GWh of electricity.[35] In theory, the world's geothermal resources are sufficient to supply humans with energy. However, only a tiny fraction of the world's geothermal resources can at present be explored on a profitable basis.[36]

Al Gore said in The Climate Project Asia Pacific Summit that Indonesia could become a super power country in electricity production from geothermal energy.[37] In 2013 the publicly owned electricity sector in India announced a plan to develop the country's first geothermal power facility in the landlocked state of Chhattisgarh.[38]

Geothermal power in Canada has high potential due to its position on the Pacific Ring of Fire. The region of greatest potential is the Canadian Cordillera, stretching from British Columbia to the Yukon, where estimates of generating output have ranged from 1,550 MW to 5,000 MW.[39]

The geography of Japan is advantageous for geothermal power production. Japan has numerous hot springs that could provide fuel for geothermal power plants, but a massive investment in Japan's infrastructure would be necessary.[40]

Utility-grade stations

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See also: List of geothermal power stations
Yearly geothermal generation by continent[41]
Geothermal generation by country, 2021[41]

The largest group of geothermal power plants in the world is located at The Geysers, a geothermal field in California, United States.[42] As of 2021, five countries (Kenya, Iceland, El Salvador, New Zealand, and Nicaragua) generate more than 15% of their electricity from geothermal sources.[41]

The following table lists these data for each country:

  • total generation from geothermal in terawatt-hours,
  • percent of that country's generation that was geothermal,
  • total geothermal capacity in gigawatts,
  • percent growth in geothermal capacity, and
  • the geothermal capacity factor for that year.

Data are for the year 2021. Data are sourced from the EIA.[41] Only includes countries with more than 0.01 TWh of generation. Links for each location go to the relevant geothermal power page, when available.

Country Gen
(TWh) 		%
gen. 		Cap.
(GW) 		% cap.
growth 		Cap.
fac.
 World 91.80 0.3% 14.67 1.7 71%
 United States 16.24 0.4% 2.60 1.0 71%
 Indonesia 15.90 5.2% 2.28 6.9 80%
 Philippines 10.89 10.1% 1.93 0 64%
 Turkey 10.77 3.4% 1.68 3.9 73%
 New Zealand 7.82 18.0% 1.27 0 70%
 Iceland 5.68 29.4% 0.76 0 86%
 Italy 5.53 2.0% 0.77 0 82%
 Kenya 5.12 43.4% 0.86 0 68%
 Mexico 4.28 1.3% 1.03 0 47%
 Japan 3.02 0.3% 0.48 0 72%
 Costa Rica 1.60 12.6% 0.26 0 70%
 El Salvador 1.58 23.9% 0.20 0 88%
 Nicaragua 0.78 16.9% 0.15 0 58%
 Russia 0.45 0.04% 0.07 0 69%
 Papua New Guinea 0.40 8.2% 0.06 0 82%
 Chile 0.33 0.4% 0.04 0 94%
 Guatemala 0.32 2.2% 0.05 0 73%
 Honduras 0.31 2.6% 0.04 0 91%
 Germany 0.25 0.04% 0.05 15.0 62%
 Portugal 0.18 0.4% 0.03 0 70%
 France 0.13 0.03% 0.02 0 95%
 China 0.13 0.002% 0.03 0 55%
 Croatia 0.07 0.5% 0.01 0 85%

Environmental impact

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The 120-MWe Nesjavellir power station in southwest Iceland
Part of a series on
Renewable energy

Existing geothermal electric stations that fall within the 50th percentile of all total life cycle emissions studies reviewed by the IPCC produce on average 45 kg of CO
2 equivalent emissions per megawatt-hour of generated electricity (kg CO
2eq/MWh).[43] For comparison, a coal-fired power plant emits 1,001 kg of CO
2 equivalent per megawatt-hour when not coupled with carbon capture and storage (CCS).[8][43] As many geothermal projects are situated in volcanically active areas that naturally emit greenhouse gases, it is hypothesized that geothermal plants may actually decrease the rate of de-gassing by reducing the pressure on underground reservoirs.[44]

Stations that experience high levels of acids and volatile chemicals are usually equipped with emission-control systems to reduce the exhaust. Geothermal stations can also inject these gases back into the earth as a form of carbon capture and storage, such as in New Zealand[44] and in the CarbFix project in Iceland.

Other stations, like the Kızıldere geothermal power plant, exhibit the capability to use geothermal fluids to process carbon dioxide gas into dry ice at two nearby plants, resulting in very little environmental impact.[45]

In addition to dissolved gases, hot water from geothermal sources may hold in solution trace amounts of toxic chemicals, such as mercury, arsenic, boron, antimony, and salt.[46] These chemicals come out of solution as the water cools, and can cause environmental damage if released. The modern practice of injecting geothermal fluids back into the Earth to stimulate production has the side benefit of reducing this environmental risk.

Station construction can adversely affect land stability. Subsidence has occurred in the Wairakei field in New Zealand.[47] Enhanced geothermal systems can trigger earthquakes due to water injection. The project in Basel, Switzerland was suspended because more than 10,000 seismic events measuring up to 3.4 on the Richter Scale occurred over the first 6 days of water injection.[48] The risk of geothermal drilling leading to uplift has been experienced in Staufen im Breisgau.

Geothermal has minimal land and freshwater requirements. Geothermal stations use 404 square meters per GWh versus 3,632 and 1,335 square meters for coal facilities and wind farms respectively.[47] They use 20 litres of freshwater per MWh versus over 1000 litres per MWh for nuclear, coal, or oil.[47]

Local climate cooling is possible as a result of the work of the geothermal circulation systems. However, according to an estimation given by Leningrad Mining Institute in 1980s, possible cool-down will be negligible compared to natural climate fluctuations.[49]

While volcanic activity produces geothermal energy, it is also risky. As of 2022 the Puna Geothermal Venture has still not returned to full capacity after the 2018 lower Puna eruption.[50]

Economics

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See also: Cost of electricity by source

Geothermal power requires no fuel; it is therefore immune to fuel cost fluctuations. However, capital costs tend to be high. Drilling accounts for over half the costs, and exploration of deep resources entails significant risks. A typical well doublet in Nevada can support 4.5 MW of electricity generation and costs about $10 million to drill, with a 20% failure rate.[22] In total, electrical station construction and well drilling costs about 2–5 million € per MW of electrical capacity, while the levelised energy cost is 0.04–0.10 € per kWh.[10] Enhanced geothermal systems tend to be on the high side of these ranges, with capital costs above $4 million per MW and levelized costs above $0.054 per kWh in 2007.[51]

Research suggests in-reservoir storage could increase the economic viability of enhanced geothermal systems in energy systems with a large share of variable renewable energy sources.[52][53]

Geothermal power is highly scalable: a small power station can supply a rural village, though initial capital costs can be high.[54]

The most developed geothermal field is the Geysers in California. In 2008, this field supported 15 stations, all owned by Calpine, with a total generating capacity of 725 MW.[55]

See also

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References

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Further reading

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[edit]
Revisions and contributorsEdit on WikipediaRead on Wikipedia

Geothermal power

View on Grokipedia
from Grokipedia
Geothermal power is the production of by extracting from the Earth's subsurface reservoirs of hot and , which is used to drive turbines coupled to generators. This source relies on continuous geothermal from and residual primordial , enabling baseload operation with capacity factors typically ranging from 70% to 90%. As of 2024, global geothermal power capacity totals approximately 16.2 gigawatts, primarily in tectonically active regions like the , with leading producers including the , , , and . These installations generate over 90 terawatt-hours annually, contributing less than 1% of world but offering dispatchable, low-emission power with lifetimes exceeding 30 years. Key advantages include near-zero operational emissions of and other pollutants, small land footprints compared to solar or farms, and independence from weather conditions, making it suitable for grid stability. However, challenges encompass high upfront and costs, geographic constraints to areas with sufficient hydrothermal resources, and potential environmental risks such as induced micro-seismicity from reinjection of fluids, which, while generally low-magnitude, requires site-specific monitoring and . Advances in enhanced geothermal systems aim to expand viability beyond conventional reservoirs by fracturing hot dry rock, though scalability remains limited by technical and economic hurdles.

Fundamentals

Principles of geothermal energy extraction

Geothermal energy extraction relies on accessing the Earth's internal , which originates primarily from the decay of radioactive isotopes such as , , and in the crust and mantle, supplemented by residual from the planet's formation approximately 4.5 billion years ago. This conducts outward, establishing a where subsurface temperatures typically increase by 25–30 °C per kilometer of depth in . Extraction targets regions with elevated flow, such as tectonic plate boundaries or hotspots, where natural in fluid-filled reservoirs concentrates at shallower depths, often exceeding 150 °C at 1–3 km. The core principle involves production wells into permeable subsurface formations containing hot s or capable of being fractured to permit circulation. In these reservoirs, water or , heated by surrounding rock, is pumped to the surface through wells, leveraging hydrostatic and pumps where necessary to overcome frictional losses and maintain flow rates. The extracted transfers heat via —far more efficient than conduction alone—allowing rapid delivery of to the surface for power generation. Sustainable extraction requires balancing production with reinjection of cooled s into injection wells to replenish reservoir , minimize , and sustain permeability by preventing scaling or contraction. Heat extraction efficiency depends on reservoir characteristics, including , permeability, and temperature distribution, governed by for fluid flow through porous media: Q=−kAμ∇PQ = -\frac{k A}{\mu} \nabla P, where QQ is flow rate, kk permeability, AA cross-sectional area, μ\mu fluid viscosity, and ∇P\nabla P . In low-permeability formations, enhanced geothermal systems (EGS) apply hydraulic stimulation to create artificial fractures, enabling water circulation through hot dry rock and mimicking natural hydrothermal convection. Overall, the process converts stored into usable form while managing thermodynamic losses, with net typically ranging from 10–20% due to the low Carnot efficiency of moderate-temperature sources compared to higher-temperature fossil fuels.

Types of geothermal heat sources

Geothermal heat sources for power generation primarily consist of subsurface reservoirs where Earth's internal heat is accessible through fluids or engineered means. These sources derive from primordial heat retained during planetary formation, combined with ongoing radiogenic decay in the crust and mantle, creating temperature gradients that enable extraction. Conventional sources rely on natural hydrothermal , while advanced types involve human enhancement of permeability. Hydrothermal reservoirs, the most exploited type, feature permeable rock formations saturated with hot water or heated by underlying magmatic intrusions or deep circulation. They are subdivided into vapor-dominated and liquid-dominated systems based on fluid phase. Vapor-dominated reservoirs contain with minimal liquid water, typically exceeding 200°C, and constitute less than 5% of identified resources due to their rarity, as seen in fields like in , operational since 1960 with initial capacities over 2 GW. These systems require minimal fluid separation but face depletion risks from steam extraction without recharge. Liquid-dominated hydrothermal reservoirs, comprising the majority of commercial sites, hold pressurized hot water at 150–370°C in porous aquifers capped by impermeable layers. Fluids here often "flash" to steam upon pressure reduction at the surface, enabling turbine operation; examples include the field in , where temperatures reach 300°C and salinities exceed . These systems support higher fluid volumes but necessitate reinjection to sustain pressure and minimize , with global installed capacity from such sources exceeding 15 GW as of 2023. Geopressured reservoirs occur in deep sedimentary basins, trapping hot under abnormal hydrostatic with dissolved , potentially yielding both thermal and . Located at depths of 3–6 km with temperatures around 150–200°C, they offer co-production potential but face challenges from high and gas separation; U.S. Gulf Coast estimates suggest recoverable equivalent to thousands of quads, though remains limited due to and scaling issues. Enhanced geothermal systems (EGS) target hot dry rock lacking natural permeability, fracturing impermeable formations at 3–10 km depths (300–500°C) and circulating injected water to extract heat conductively. Pioneered in projects like Fenton Hill, , in the 1970s, EGS expands resource potential to 80% of U.S. land area but requires hydraulic stimulation, raising concerns; pilot capacities have reached 5 MW, with DOE targeting 60 GW by 2050 through R&D.

Historical Development

Pre-20th century uses

Archaeological evidence indicates that in utilized geothermal hot springs for bathing, cooking, and heating as early as 10,000 years ago, with sites like Hot Springs in present-day serving as neutral gathering places for warring tribes. Ancient Roman civilization extensively harnessed geothermal resources, channeling hot mineral waters from volcanic regions such as those near modern-day and Bath, , to supply public bathhouses () and systems starting around the 1st century CE. These applications relied on natural hot springs and shallow heated by geothermal gradients, facilitating both hygienic and therapeutic uses across the empire. In ancient , geothermal hot springs were employed for similar purposes, including cooking food directly in heated pools and space heating in dwellings, with records dating back over 2,000 years in regions like province. Native American groups in the continued these practices into historic times, integrating hot springs into daily sustenance and ceremonial activities. The transition to industrial applications occurred in the early 19th century, when in 1827, near Larderello in , , natural steam vents and drilled wells were used to evaporate seawater for production, marking the first documented commercial exploitation of geothermal steam. This method capitalized on the region's fumaroles, yielding significant chemical output without reliance on fossil fuels.

Commercialization in the 20th century

The commercialization of geothermal power began in at the Larderello field in , where Prince Piero Ginori Conti demonstrated the first geothermal electricity generator on July 4, 1904, successfully powering four light bulbs using steam from natural fumaroles. This experimental setup marked the initial proof-of-concept for harnessing geothermal steam for electrical generation, leveraging the region's dry steam reservoirs for extraction since the . By , the world's first commercial geothermal power plant, Larderello 1, entered operation with a capacity of 250 kilowatts, supplying to local industries and expanding to power the Italian railway system. remained the sole producer of geothermal through the mid-, scaling Larderello's output to several megawatts by the 1920s and 1930s despite interruptions from . Commercialization accelerated post-World War II with developments outside Italy. In New Zealand, the Wairakei power station began generating electricity in November 1958, utilizing wet steam resources in the Taupo Volcanic Zone; its initial 12.5-megawatt turbine represented the first large-scale geothermal plant beyond , eventually reaching 157 megawatts by 1963 through phased construction. This facility demonstrated the feasibility of flash-steam technology for two-phase reservoirs, influencing global adoption. In the United States, field in initiated commercial production in 1960 with Pacific Gas & Electric's Unit 1, an 11-megawatt dry-steam plant that became the first geothermal facility in the and a model for utility-scale deployment. By the late 1960s, expanded rapidly, adding multiple units and reaching over 500 megawatts, supported by federal incentives and technological refinements in well drilling and steam separation. The 1970s and 1980s saw broader internationalization amid oil crises that highlighted geothermal's baseload reliability. commissioned its first commercial plant at Hatchobaru in 1973, while Iceland's Svartsengi station began operations in 1976, integrating power with . The entered with the Tiwi field in 1977, followed by Elazig in in 1984, and Kenya's Olkaria I in 1985, diversifying to binary-cycle adaptations for lower-temperature resources. By 2000, global installed capacity exceeded 8,000 megawatts across 21 countries, with , the , and accounting for over half, driven by resource assessments confirming economic viability in volcanic regions. These expansions relied on empirical modeling and advancements, though challenges like steam depletion prompted reinjection practices by the 1980s.

21st century advancements and EGS emergence

The marked a shift in geothermal power toward broader resource accessibility, with systems dominating new installations. Since 2000, nearly all geothermal power plants added have utilized s, which efficiently convert heat from fluids at 110–200°C into using organic working fluids, expanding viable sites beyond high-temperature hydrothermal reservoirs. Concurrently, Enhanced Geothermal Systems (EGS) emerged as a pivotal innovation to harness hot dry rock formations by engineering permeability through hydraulic stimulation, creating artificial reservoirs for sustained fluid circulation. This approach, evolving from "hot dry rock" experiments, gained strategic focus via the 2006 MIT-led report The Future of Geothermal Energy, which modeled EGS potential to supply 100 GWe of baseload power in the U.S. by 2050, contingent on overcoming stimulation and circulation challenges. U.S. Department of Energy initiatives accelerated EGS maturation, including the 2015 launch of the Frontier Observatory for Research in Geothermal Energy () in to validate reservoir creation and flow management. By 2023, Fervo Energy's Project Red in demonstrated commercial viability, achieving the first grid-connected EGS doublet with 3.5 MW of firm output and record flow rates, leveraging horizontal drilling and fiber-optic monitoring for precise fracture control. Subsequent developments included Fervo's 2023 Cape Station project in , aiming for 400 MW by 2028 through phased scaling, and 2024 tests confirming fracture connectivity in granitic rock at depths over 2 km. A 2025 review of 103 global EGS efforts documented drilling costs below 20% of prior benchmarks, production temperatures averaging 10°C higher per decade, and flow rates exceeding 80 L/s, signaling readiness for widespread adoption amid power purchase agreements surpassing prior capacities by over tenfold.

Resource Assessment

Geological reservoir types

Geothermal reservoirs exploited for power generation are chiefly hydrothermal convective systems, where circulates through permeable fractures or porous media, heated by underlying magmatic intrusions or conductive heat flow from , and trapped beneath impermeable . These natural s require three essential geological elements: a heat source, a (typically ), and sufficient permeability for migration. They form predominantly in tectonically active regions, such as zones or rift systems, where elevated geothermal gradients exceed 30–50°C/km. s are classified primarily by the dominant phase—vapor-dominated or liquid-dominated—reflecting thermodynamic conditions where and determine phase equilibrium, with vapor systems exhibiting specific volumes exceeding water's critical volume (approximately 0.056 m³/kg at 374°C). Vapor-dominated reservoirs contain as the primary mobile phase, with minimal immobile , typically at temperatures above 235°C (the at 30–35 bar reservoir pressure) and permeabilities sustained by fracture networks in volcanic or metamorphic rocks. These systems feature a near-static steam column overlying a two-phase zone, producing only discharges without surface hot water manifestations, and are geologically linked to high-enthalpy volcanic provinces where low-permeability caps prevent recharge dominance. Representing less than 10% of identified high-enthalpy fields due to their specific formation requirements, they enable direct extraction but risk rapid pressure decline from steam cap depletion. Key examples include Larderello in Italy's Tuscan volcanic province and in California's , both hosted in fractured and volcanic rocks with initial reservoir pressures around 35 bar. Liquid-dominated reservoirs, far more prevalent and comprising over 90% of operational geothermal fields, hold pressurized hot as the principal phase, with temperatures ranging from 150°C to over 350°C in permeable aquifers of sedimentary, volcanic, or fractured igneous rocks. Fluid exists as a single-phase liquid under hydrostatic or higher pressures, often with dissolved gases and minerals, and production involves flashing to at the surface or binary cycles; geologically, they arise in extensional basins or faulted terrains where recharge sustains liquid volumes, though excessive extraction can induce boiling and to vapor conditions. These systems exhibit higher storage capacities but require separation of to mitigate scaling from mineral precipitation. Prominent instances occur in the ' volcanic arcs (e.g., Tiwi field) and Indonesia's zones, with reservoir permeabilities of 10–100 mD and porosities up to 20% in volcanic tuffs or limestones. While both types share convective mechanisms, their geological distinctions influence extractability: vapor systems offer higher initial enthalpies (2,500–2,800 kJ/kg) but lower sustainability without recharge, whereas liquid systems support larger volumes (10^9–10^12 m³) yet demand reinjection to maintain and avoid , as evidenced by drawdowns exceeding 10 bar in mature fields. Emerging assessments also consider hybrid or transitional with evolving phase dominance due to exploitation-induced .

Global distribution and exploration methods

Geothermal resources suitable for power generation are concentrated in tectonically active regions where heat flow from Earth's mantle is elevated due to plate boundary processes, including subduction zones, mid-ocean ridges, and continental rifts. Principal areas include the Pacific Ring of Fire, encompassing Indonesia, the Philippines, Japan, and the western United States; the East African Rift system in Kenya, Ethiopia, and Djibouti; and hotspots like Iceland and parts of New Zealand. Additional significant zones occur along transform faults in Turkey and volcanic provinces in Italy and Mexico. These distributions align with global patterns of thinned crust and magmatic activity, enabling accessible reservoirs at depths typically under 5 km. As of the end of 2024, worldwide installed geothermal power capacity totaled 15.4 GW, with operations in over 30 countries but dominated by a handful of leaders exploiting hydrothermal systems. The maintains the largest capacity at approximately 3,937 MW, concentrated in California's field and Nevada's enhanced systems. ranks second with 2.6 GW, leveraging its position on the despite regulatory hurdles limiting fuller development of its estimated 29 GW resource base. Other top contributors include the (around 1.9 GW), (1.7 GW), (1 GW), (over 800 MW supplying 25% of national electricity), (861 MW as of recent expansions), Italy, and . These nations account for over 80% of global output, reflecting both resource endowment and investment in drilling infrastructure. Exploration for geothermal reservoirs employs a phased approach integrating surface and subsurface data to minimize drilling risks, which constitute 30-50% of project costs. Initial relies on geologic mapping of fault systems, volcanic features, and hot springs to identify prospects, supplemented by via for thermal anomalies. Geophysical methods dominate subsurface delineation: (MT) surveys detect low-resistivity zones from saline fluids, seismic reflection profiles image faults and permeability structures, and gravity or magnetic surveys highlight intrusive bodies. Geochemical sampling of fumaroles and fluids analyzes isotopes and gases (e.g., for mantle input) to infer reservoir temperatures exceeding 150°C. Confirmation requires slimhole (2-5 inch diameter) for temperature logs and fluid yields, progressing to full-size wells (8-12 inch) for production testing. Volume-based assessments by agencies like the USGS estimate recoverable heat using , permeability, and recharge rates derived from these data. Advanced techniques, informed by oil and gas analogs, include 3D seismic imaging for fracture networks and machine learning integration of multi-dataset models to predict reservoir viability. Success rates hover at 20-30% for exploratory wells, underscoring the empirical necessity of iterative testing amid heterogeneous subsurface conditions. Emerging enhanced geothermal systems (EGS) broaden to non-conventional areas by targeting hot dry rock via hydraulic stimulation, as demonstrated in USGS-supported pilots in the .
Leading Countries by Installed Capacity (2024, MW)Source
United States: 3,937ThinkGeoEnergy industry report, corroborated by DOE estimates
Indonesia: 2,600EIA
Philippines: ~1,900IRENA aggregates
Turkey: ~1,700IRENA aggregates
New Zealand: ~1,000IRENA aggregates

Generation Technologies

Conventional steam-based systems

Conventional steam-based geothermal power systems extract high-temperature fluids from hydrothermal reservoirs to produce that drives turbines for . These systems encompass dry steam plants, which utilize naturally occurring steam reservoirs, and flash steam plants, which convert pressurized hot into steam through rapid depressurization. Such technologies are suitable for reservoirs with temperatures exceeding 180°C and are among the earliest and most direct methods of geothermal production. Dry steam plants pipe directly from production wells to without intermediate separation, minimizing equipment complexity. Steam exits the as low-pressure exhaust, which is condensed using cooling towers or air coolers before reinjection into the to sustain pressure and reduce subsidence risks. The Larderello field in hosted the world's first dry steam plant in 1904, initially generating enough power for five light bulbs, and remains operational with expansions exceeding 800 MW capacity as of recent assessments. Other notable examples include in , the largest complex of its type, peaking at over 2,000 MW in the 1980s but now operating at about 725 MW due to management needs. These plants achieve thermal efficiencies around 20-25%, limited by the relatively low steam temperatures compared to cycles. Flash plants, the most prevalent conventional type comprising over 70% of global geothermal capacity, pump hot pressurized water from depths of 1-3 km into surface separators where pressure drops cause flashing—a phase change producing at 150-200°C. Single-flash configurations use one separator, while double- or triple-flash systems cascade multiple stages to capture additional from separated , boosting by 5-10%. The drives , and spent is reinjected after silica scaling mitigation, though non-condensable gases like CO2 and H2S require abatement to prevent and emissions exceeding 100 g/kWh in some fields. Pioneered in New Zealand's Wairakei plant in 1958, flash systems dominate in regions like and the due to abundant liquid-dominated reservoirs. Both subtypes offer high capacity factors over 90%, providing baseload power with minimal fuel costs, but site specificity confines deployment to volcanic or tectonically active areas covering less than 1% of land surface. Resource depletion from over-extraction has occurred, as at , necessitating advanced reinjection; environmental releases include trace minerals and gases, though lifecycle emissions remain below 50 g CO2eq/kWh—far lower than coal's 800+ g. Corrosion from geothermal fluids and from reinjection pose operational challenges, addressed via material alloys and monitoring.

Binary cycle systems

Binary cycle systems in geothermal power generation utilize a closed-loop process where geothermal , typically at temperatures between 100°C and 200°C, heats a secondary with a lower , such as , , or refrigerants like R134a, without direct contact between the geothermal fluid and the . This indirect heat exchange occurs in a , vaporizing the secondary fluid to drive a connected to a generator, after which the fluid is condensed and recycled. The geothermal , which remains in a liquid state, is reinjected into the to sustain and minimize surface emissions. These systems are particularly suited for moderate-temperature resources that are uneconomical for dry steam or flash steam plants, expanding the viable geothermal resource base by enabling utilization of fluids as low as 57°C in some advanced configurations, though most operate above 100°C for . Efficiencies typically range from 10% to 15%, lower than flash or dry steam systems due to the temperature differential, but they offer higher and reduced scaling or issues since the turbine does not contact corrosive geothermal fluids. A key advantage is near-zero air emissions, as non-condensable gases in the are reinjected, contrasting with open-cycle systems that may release CO2 or H2S. The first commercial binary cycle plant, the 11 MW Raft River facility in , , began operation in 1981 using as the , demonstrating feasibility for lower-temperature fields. By 2023, binary cycles accounted for about 15% of global geothermal capacity, with notable installations including the 34 MW McKay Canyon plant in (online 1985) and larger dual-flash/binary hybrids like the 117 MW Heber plant in (1985). In regions like the and , binary systems support baseload power from non-volcanic fields, such as the 49 MW plant. Ongoing focuses on supercritical CO2 as a to boost efficiency up to 20% in pilots, though remains limited as of 2025.

Enhanced and next-generation systems

Enhanced geothermal systems (EGS) expand geothermal power potential by engineering reservoirs in hot dry rock formations lacking natural permeability, through hydraulic fracturing and water injection to create artificial fluid pathways for heat extraction. Unlike conventional systems reliant on pre-existing hydrothermal reservoirs, EGS targets deeper, hotter crystalline rock, enabling deployment in diverse geological settings beyond volcanic regions. Advancements since the 1970s, including improved drilling techniques and reservoir stimulation, have boosted productivity and reduced costs, with U.S. Department of Energy estimates indicating EGS could supply over 65 million American homes. Key progress includes horizontal drilling borrowed from oil and gas, enhancing well connectivity and heat exchange efficiency, as demonstrated in projects like Fervo Energy's Cape Station in , which achieved flow rates exceeding 63 liters per second in 2023 tests. The U.S. FORGE site in has validated EGS viability through iterative field experiments, informing scalable designs with productivity indices up to 0.02 MW per well. Recent cost reductions, estimated at 50% from 2021-2023 via optimized stimulation and diagnostics, position EGS for commercial competitiveness, potentially delivering baseload power at levelized costs approaching $50-100/MWh by 2030. Next-generation variants push boundaries further, such as supercritical geothermal systems accessing fluids above 374°C and 220 bar, yielding up to tenfold compared to subcritical conditions through deeper into superhot rock. Initiatives like Japan's ICDP project and U.S. efforts under H.R. 8665 aim to develop these by advancing millimeter-wave for 10-20 km depths, though challenges persist in and management. Closed-loop systems, exemplified by Eavor's Eavor-Loop , circulate sealed working fluids in wells, minimizing water loss and environmental risks while targeting consistent output independent of permeability. As of 2025, these innovations, supported by investments exceeding $500 million in startups like Fervo and , signal EGS maturation toward contributing 100 GW in the U.S. by 2050, contingent on sustained R&D in fracture longevity and mitigation.

Production and Deployment

Current global capacity and output (as of 2025)

As of the end of 2024, global installed geothermal power capacity reached approximately 15.4 gigawatts (GW), reflecting a modest annual growth rate of less than 2% from prior years, according to data compiled by the International Renewable Energy Agency (IRENA). Independent trackers, such as Global Energy Monitor, report slightly higher operating capacity at 16.17 GW across 770 units in 49 countries, incorporating updates for smaller or off-grid installations potentially undercounted in aggregated statistics. This capacity has expanded slowly due to high upfront exploration and drilling costs, with cumulative additions since 2010 totaling under 5 GW globally. In 2024, geothermal worldwide approximated 98 terawatt-hours (TWh), accounting for about 0.3% of total global output, consistent with factors typically ranging from 70-90% in mature hydrothermal fields. This output remained stable year-over-year, as new capacity additions—primarily in , , and —offset minor declines in older fields due to depletion without significant reinjection enhancements. Projections for 2025 indicate continued incremental growth, potentially adding 0.4-0.5 GW, driven by policy incentives in regions with high resource potential, though enhanced geothermal systems (EGS) contributed negligibly to current totals.

Major operational projects and leading nations

The holds the largest installed geothermal power capacity worldwide, totaling 3,937 MW as of the end of 2024, primarily concentrated in , , and . ranks second with 2,653 MW, driven by volcanic resources in and , where projects like the Windu and fields contribute significantly to national output. The follows with 1,984 MW, relying on fields such as Tiwi and Mak-Ban, which have been operational since the and supply about 10% of the country's . has expanded rapidly to 1,734 MW, with key developments in western , including the Kızıldere and fields. New Zealand operates around 1,000 MW, with pioneering stations like Wairakei (operational since 1958) and modern expansions at Tauhara, supporting over 18% of its electricity needs from geothermal sources. Iceland generates nearly 30% of its electricity from 755 MW of geothermal capacity, exemplified by the Hellisheiði plant (303 MW, commissioned 2006) and Nesjavellir (120 MW), leveraging high-enthalpy resources for baseload power and district heating. Other notable leaders include Kenya (with Olkaria complex exceeding 900 MW across multiple units since 1981 expansions), Mexico (Cerro Prieto at 720 MW), and Italy (Larderello, the world's first grid-connected plant from 1904, now at ~800 MW).
CountryInstalled Capacity (MW, end-2024)
3,937
2,653
1,984
1,734
~1,000
755
Major operational projects underscore these nations' dominance. In the US, The Geysers complex in California, the largest geothermal field globally, operates at approximately 725 MW net capacity across 22 units, though output has declined from peak levels due to reservoir depletion without recharge. Kenya's Olkaria fields, managed by KenGen, include Olkaria I (45 MW, 1981), II (105 MW, 1991), and recent additions like Olkaria V (140 MW, 2019), totaling over 900 MW and forming Africa's largest geothermal resource. Indonesia's Sarulla complex (330 MW, fully operational by 2017) represents one of the world's largest single-site developments, utilizing technology in . In the , the project (various units totaling ~700 MW) and Bacon-Manito field highlight sustained operations amid seismic challenges. Mexico's Cerro Prieto, operational since 1973, sustains 720 MW through flash steam systems, contributing about 3% of national electricity. These projects demonstrate geothermal's reliability for baseload power, with capacities verified through operator reports and international trackers, though long-term sustainability requires ongoing reservoir management to mitigate drawdown effects.

Economic Analysis

Investment and operational costs

The capital costs for constructing geothermal power plants, encompassing , , surface facilities, and power generation equipment, typically range from $4,000 to $6,000 per kilowatt of installed capacity for conventional hydrothermal systems as of 2023. For a representative 50-megawatt binary-cycle plant, the overnight averages $3,963 per kilowatt, excluding financing and escalation, though actual totals can reach approximately $198 million due to site-specific factors like resource assessment and , which often constitute up to 50% of the total. Flash steam plants may incur slightly lower costs at $4,350 to $5,922 per kilowatt, while binary-cycle variants, which operate at lower temperatures, trend higher at around $4,759 per kilowatt in base-year estimates. geothermal systems (EGS), reliant on hydraulic stimulation of hot dry rock, demand substantially more investment, with capital expenditures projected at $6,500 to $7,600 per kilowatt owing to deeper and challenges. These upfront investments exceed those of variable renewables like solar photovoltaic ($700–$1,000 per kilowatt) primarily because geothermal development involves high-risk geophysical exploration, including seismic surveys and test wells, which can fail to yield viable reservoirs in 20–30% of cases, necessitating dry-hole contingencies. Regional variations further influence costs; for instance, U.S. West Coast sites adjusted for labor and permitting may add 10–25% to base figures, yielding $4,500–$4,900 per kilowatt in areas like California's Central Valley or . Projections from the National Renewable Energy Laboratory indicate moderate cost reductions of 10–20% by 2035 through improved drilling rates of penetration and larger scales (e.g., 100-megawatt units), though EGS remains contingent on achieving these efficiencies to approach conventional viability. Operational and maintenance (O&M) costs for geothermal are comparatively low, reflecting their baseload reliability and absence of expenses, with fixed O&M averaging $125–$150 per kilowatt-year across recent projects. Variable O&M is negligible at approximately $0 per megawatt-hour, as operations involve minimal incremental inputs beyond routine monitoring and well-field management to sustain production. However, these costs can escalate with complexity, such as scaling or mitigation in binary systems, or induced permeability maintenance in EGS, potentially adding 10–20% to fixed expenditures if production declines require reinjection or redrilling. Over a typical 30–50-year plant lifespan, these low O&M profiles contribute to favorable long-term economics, though initial risks amplify perceived hurdles relative to dispatchable fossil alternatives.

Levelized cost comparisons and profitability

The levelized cost of energy (LCOE) for geothermal power, which represents the average net present cost of over a plant's lifetime including capital, operations, maintenance, and fuel costs, typically ranges from USD 60 to 82 per MWh for conventional hydrothermal systems in recent assessments. According to the (IRENA), the global weighted-average LCOE for newly commissioned geothermal s decreased by 16% in 2024 to approximately USD 60/kWh, reflecting efficiencies in and execution, though values vary by location with lows of USD 33/kWh in due to favorable and policy support. Enhanced geothermal systems (EGS) remain higher, often exceeding USD 100/MWh due to exploratory risks and advanced stimulation costs, limiting their current scalability.
TechnologyUnsubsidized LCOE (USD/MWh, 2024 estimates)Capacity Factor (%)Key Notes
Geothermal (hydrothermal)60–8275–90Baseload, low O&M; high upfront CAPEX offset by longevity >30 years.
Utility-scale solar PV24–9620–30Intermittent; requires storage for dispatchability, raising effective costs.
Onshore wind24–7535–50Variable output; grid balancing adds externalities not captured in basic LCOE.
Combined-cycle gas45–7450–60Fuel-dependent; lower than geothermal in some low-gas-price regions but volatile.
Coal (new supercritical)70–11760–80Includes emissions costs; declining viability due to regulatory pressures.
Nuclear (new build)140–22090+High CAPEX overruns common; longer lead times than geothermal.
Geothermal's LCOE competitiveness stems from its high capacity factors, averaging 75–88% globally in 2024, far exceeding intermittent renewables and enabling near-baseload operation without fuel price exposure. This reliability provides system value beyond LCOE, as it reduces the need for backup generation or storage required for solar and wind, though standard LCOE metrics undervalue such dispatchability in grid-integrated analyses. Profitability for operational plants is enhanced by minimal variable costs—often under 1 cent/kWh for O&M—and plant lifespans of 30–50 years, yielding internal rates of return (IRR) of 10–16% in favorable sites, comparable to or exceeding fossil projects when adjusted for risk. However, upfront exploration risks, with success rates below 50% for drilling, can erode returns for greenfield developments, necessitating site-specific assessments. In regions with established fields, such as Iceland or New Zealand, geothermal projects achieve positive cash flows within 5–10 years post-commissioning due to stable output and avoided fuel expenditures.

Role of subsidies and market incentives

Geothermal power projects often require substantial upfront capital for and , with success rates for wells as low as 20-30% in some regions, necessitating subsidies to mitigate financial risks and attract private investment. instruments, including grants, loan guarantees, and equity support, cover 76-90% of investments in many developing projects, with governments absorbing approximately 58.5% of total costs to enable deployment. In the United States, the of 2022 provided enhanced investment tax credits (ITC) and production tax credits (PTC) for geothermal, which persisted in modified form under the 2025 One Big Beautiful Bill Act, allowing baseload sources like geothermal to qualify for up to 48E ITC or 45Y PTC rates. These incentives have facilitated over $1.7 billion in North American geothermal funding in the first quarter of 2025 alone, primarily for next-generation enhanced geothermal systems (EGS). Market incentives such as feed-in tariffs () guarantee renewable producers fixed, above-market prices for electricity fed into the grid, promoting geothermal by ensuring revenue stability over long project lifespans of 30-50 years. Countries like and have used FITs alongside subsidies to accelerate private-sector involvement, contributing to Turkey's geothermal capacity growth from minimal levels in the early to over 1.7 GW by 2023. In , renewable portfolio standards and similar mandates, combined with EGS-focused grants totaling hundreds of millions in 2024 from nations like and the , have supported pilot deployments despite higher initial costs compared to variable renewables. Comparative analyses of FIT schemes indicate they enhance geothermal investment returns by 10-20% in risk-adjusted terms, though efficacy varies by degression rates and contract durations, with longer-term fixed tariffs proving more effective for capital-intensive technologies. Critics argue that ongoing subsidies distort market signals and delay cost reductions through innovation, as geothermal's levelized costs—currently $100-240/MWh for EGS—remain higher than unsubsidized fossil alternatives without incentives. However, proponents, including the , contend that targeted support for exploration risk-sharing and drilling advancements could reduce costs by up to 80% by 2035, enabling unsubsidized competitiveness in baseload power markets. Empirical evidence from U.S. Department of Energy programs shows that federal risk mitigation has increased successful well completions and lowered effective by 15-25% in subsidized projects, underscoring subsidies' role in bridging the gap until technological maturation.

Environmental and Sustainability Impacts

Emission profiles and climate benefits

Geothermal power plants exhibit some of the lowest lifecycle (GHG) emissions among technologies, typically ranging from 10 to 50 grams of CO2 equivalent per (g CO2eq/kWh). A of life cycle assessments by the National Renewable Energy Laboratory (NREL) found median values of 11.3 g CO2eq/kWh for high-temperature systems, 47 g CO2eq/kWh for high-temperature flash systems, and 32 g CO2eq/kWh for geothermal systems (EGS) using binary cycles. These figures encompass emissions from , , plant , operation, and decommissioning, with the majority stemming from upfront material use and reservoir-derived gases rather than fuel . Operational emissions arise primarily from naturally dissolved non-condensable gases in geothermal fluids, including CO2 (accounting for about 10% of air emissions in open-loop systems) and (in smaller quantities), released during steam separation or reinjection processes. Non-GHG emissions such as (H2S), (NH3), and trace metals (e.g., , mercury) can occur but are site-specific and often mitigated through abatement technologies like scrubbing or reinjection, reducing H2S releases to low levels in modern plants. Unlike fossil fuels, geothermal avoids combustion-related pollutants like and , emitting 97% less sulfur compounds and 99% less CO2 on a lifecycle basis compared to or plants.
TechnologyLifecycle GHG Emissions (g CO2eq/kWh, median or range)
Geothermal (various)10–50
820–1,000
400–500
Solar PV40–50
Onshore Wind10–12
Nuclear10–15
Note: Comparative values drawn from harmonized NREL and IPCC assessments; geothermal's baseload operation yields consistent low emissions without intermittency-driven backups. The climate benefits of geothermal power derive from its capacity to displace fossil fuel-based generation with reliable, low-emission baseload electricity and heat, contributing to GHG without the variability of solar or . The (IPCC) highlights geothermal's role in providing continuous power from abundant subsurface heat, enabling deeper decarbonization in energy systems where storage or grid upgrades for intermittents are costly. The (IEA) estimates that scaling geothermal could avoid billions of tons of CO2 annually by 2050, particularly in regions with high geothermal potential, due to its high capacity factors (often >80%) and minimal land footprint relative to equivalents. However, benefits are contingent on site-specific reservoir chemistry; high-CO2 fields may require enhanced reinjection to minimize releases, and lifecycle emissions could rise with expansive EGS deployment if drilling intensives increase.

Resource depletion and water usage

Geothermal reservoirs, while drawing from vast subsurface heat sources, face depletion risks when extraction rates exceed the slow natural recharge of heat and fluids, leading to declines and drops over decades. In liquid-dominated systems, models indicate that unreplenished production can reduce reservoir productivity by depleting stored fluids and cooling the rock matrix, with decline rates potentially reaching 1-5% annually without management. For instance, at field in , vapor-dominated extraction caused significant pore liquid depletion and seismic velocity reductions by the early 2000s, necessitating wastewater reinjection to stabilize output. Similarly, early operations at Wairakei, , induced up to 0.45 meters per year due to initial reservoir depletion before reinjection practices were implemented. Sustainable management, such as limiting flow rates to match recharge (typically 10-50 years for partial recovery), and reinjection of cooled fluids can mitigate depletion, though full recovery to pre-exploitation states may require centuries-long shutdowns. Water usage in geothermal power varies by plant type and cooling method, with lifecycle consumptive demands generally lower than or nuclear alternatives but involving operational makeup for and reinjection losses. Flash steam plants exhibit minimal freshwater needs at approximately 0.01 gallons per (gal/kWh) over their lifecycle, primarily due to utilizing produced geofluids for cooling, though they incur geofluid losses of about 2.7 gal/kWh from separation processes. Binary cycle plants consume around 0.27 gal/kWh, mainly for air-cooled systems or makeup, while geothermal systems (EGS) require 0.51 gal/kWh, reflecting higher and demands. These figures compare favorably to (0.32-0.71 gal/kWh) and nuclear (0.4-0.85 gal/kWh), with geothermal's total often under 1 gal/kWh when using non-fresh sources like saline aquifers for operational needs. Consumptive losses arise from evaporative cooling (in wet-cooled variants) and incomplete reinjection efficiency (5-20% losses), potentially stressing local aquifers if freshwater is sourced without mitigation like or recycling. Reinjection sustains pressure and reduces depletion but demands precise water balancing to avoid scaling or corrosion-induced inefficiencies.

Induced seismicity and ecological risks

Geothermal power generation, especially in enhanced geothermal systems (EGS), involves injecting fluids into hot rock formations to create or enhance permeability, which can elevate pore pressures and destabilize faults, thereby inducing seismic events. This process reduces on preexisting fractures, potentially triggering earthquakes if critically stressed faults are present. In conventional hydrothermal fields, often arises from wastewater reinjection, as observed in field, , where thousands of microearthquakes occur annually due to fluid pressures exceeding fault strengths. Notable incidents underscore the risks: In Pohang, South Korea, hydraulic stimulation for an EGS project in 2017 culminated in a magnitude 5.5 earthquake on November 15, injuring 90 people and causing widespread damage in a densely populated area, with epicentral analysis linking it directly to injection-induced pressure buildup and delayed fault slip. Similarly, the Basel EGS project in Switzerland experienced a magnitude 3.4 event in 2006 following stimulation, resulting in approximately $9 million in damages and leading to project suspension due to public safety concerns. In the Salton Sea Geothermal Field, production and injection from 1972 to 2022 correlated with clustered seismicity, particularly where subsidence overlapped with fluid extraction zones. Mitigation strategies include real-time seismic monitoring, "traffic light" protocols that halt injections upon exceeding predefined magnitude thresholds (e.g., magnitude 1-2), and site-specific geomechanical modeling to predict fault responses, though post-injection seismicity remains challenging to fully suppress. Ecological risks extend beyond seismicity to include subsurface fluid migration potentially contaminating aquifers with geothermal brines containing , , , and , which can leach into surface waters if well integrity fails. Thermal discharges from cooling systems or blowouts elevate local water temperatures, disrupting aquatic ecosystems by altering species distributions and metabolic rates, as documented in Kenyan geothermal fields like Olkaria where effluent releases affect riparian habitats. Surface from reservoir depletion, reaching up to several meters in exploited fields, can fracture soils, alter hydrology, and degrade vegetation cover, indirectly harming terrestrial through . While reinjection minimizes net water loss, incomplete recapture risks mobilizing into , posing long-term bioaccumulation threats to and , with quantitative assessments indicating higher ecological damage potential in high-enthalpy systems compared to low-temperature ones. These impacts necessitate baseline ecological surveys and , though data gaps persist in peer-reviewed evaluations of cumulative effects across global sites.

Challenges and Limitations

Technical and scalability barriers

Conventional geothermal power systems depend on naturally occurring hydrothermal reservoirs featuring permeable rock formations saturated with hot fluids at depths typically under 3 km and temperatures above 150°C, conditions that are geologically rare and confined to tectonically active regions such as zones and areas. This inherent site-specificity restricts scalability, as suitable reservoirs exist in only a fraction of global landmasses—estimated at less than 10% for economic viability—despite Earth's vast internal heat resources exceeding 10^31 joules. Exploratory drilling to confirm productivity carries substantial technical , with global success rates averaging 60% in initial phases and dropping to 25% for wells in unproven areas, often requiring 3-5 attempts per productive site due to heterogeneous subsurface conditions. Drilling operations contend with extreme thermal gradients, corrosive brines containing and silica, and pressures exceeding 100 MPa, which degrade drill bits and casings at rates up to 10 times faster than in oil and gas wells, limiting depths to around 4-5 km with current materials. Post-development, reservoir sustainability poses ongoing challenges, including permeability decline from mineral scaling and during fluid reinjection, which is essential for pressure maintenance but can reduce injectivity by 50% or more over 5-10 years without chemical mitigation. Low natural and fracture connectivity further hinder fluid circulation, yielding heat recovery factors below 5% in many fields and necessitating dense well spacing—up to 1 well per MW—that amplifies land and demands. Efforts to overcome these limits through (EGS), which low-permeability hot dry rock to create artificial reservoirs, encounter additional technical obstacles: induces complex, unpredictable networks prone to short-circuiting, with flow rates often insufficient for commercial output (e.g., <50 L/s per well) and thermal drawdown occurring within 20-30 years due to limited heat exchange surface area. EGS prototypes have demonstrated permeabilities 10-100 times lower than targeted post-, compounded by challenges in sealing wells against supercritical fluids above 374°C and modeling coupled thermo-hydro-mechanical processes for scalable arrays.

Economic and regulatory obstacles

High initial capital expenditures for geothermal projects, often exceeding those of other renewables due to extensive exploration and requirements, pose a primary economic barrier. a single exploratory well can between $5 million and $10 million, with total upfront s for a power plant ranging from $2,000 to $5,000 per kilowatt installed, heavily skewed toward early-phase activities rather than ongoing operations. These s are exacerbated by resource uncertainty, where exploratory carries a of failure—historically contributing 20-30% to the overall in early-stage developments due to potential dry wells or suboptimal conditions. Such financial s deter private , as payback periods can extend 10-15 years even in favorable sites, contrasting with shorter timelines for or solar projects. Financing challenges further compound these issues, with elevated interest rates amplifying levelized costs; for instance, raising financing costs from 7% to 15% can increase the levelized cost of energy by $50 to $90 per megawatt-hour. Geothermal developers often struggle to secure contracts in competitive power markets dominated by lower-risk intermittent sources, as purchasers prioritize declining wind and solar prices over geothermal's baseload reliability. In the United States, these economic hurdles have limited deployment, with geothermal comprising only 0.4% of national electricity generation despite untapped potential, partly because high exploration risks create gaps in funding for reconnaissance phases. Regulatory obstacles, particularly protracted permitting processes, significantly delay project timelines and inflate costs. In the United States, compliance with the (NEPA) routinely extends environmental reviews to 2-5 years or more, with full project development spanning 5-10 years from inception to operation. For example, analyses of recent geothermal initiatives reveal that NEPA-related approvals, including environmental assessments and public comment periods, contribute to substantial nonproductive time, during which holding costs accrue without revenue generation. State-level requirements, such as California's CEQA, add further layers, mirroring NEPA delays and impacting economic viability by increasing total project costs through prolonged land leasing and exploration uncertainties. In , fragmented regulatory frameworks and legal uncertainties hinder scaling, with barriers including complex water management rules, environmental impact assessments, and inconsistent low-enthalpy project standards that prioritize safety and efficiency over expedition. These processes often require interagency coordination, which lacks streamlined memoranda of understanding, leading to redundant reviews and litigation risks. Globally, such regulatory rigidity manifests in lower geothermal contributions to mixes, as developers face competition from less-regulated alternatives, underscoring the need for reforms to mitigate both economic risks and administrative bottlenecks without compromising environmental oversight.

Criticisms of overhyped potential

Geothermal power's global potential has been described as vast in theoretical terms, with estimates suggesting the Earth's heat could theoretically supply humanity's needs for millions of years, yet the economically viable and technically feasible remains severely constrained by geological realities. Conventional hydrothermal systems, which dominate current deployment, are limited to regions with shallow, permeable reservoirs of hot water or , primarily near tectonic plate boundaries, accounting for less than 1% of global despite decades of development. This geographic specificity means that, unlike solar or resources available nearly everywhere, geothermal power plants can only be sited in a handful of countries, such as , , and , restricting its role as a scalable baseload alternative. Enhanced geothermal systems (EGS), promoted as a means to access deeper, hotter rock formations ubiquitously, have fueled optimism for broader deployment, with projections like the U.S. Department of Energy's forecast of 90 gigawatts by 2050 under favorable assumptions. However, EGS faces substantial hurdles, including high drilling costs—often exceeding those of oil and gas wells due to extreme temperatures and pressures—and success rates below 50% in pilot projects, leading critics to argue that such technologies overhype scalability without addressing causal barriers like reservoir permeability and . The notes that even with innovations, project development risks and long lead times limit rapid expansion, as evidenced by global installed capacity stagnating around 15 gigawatts as of 2023, far below the terawatt-scale potentials touted in some advocacy literature. Economic analyses further temper enthusiasm, revealing that geothermal's levelized costs, while competitive in ideal sites, escalate dramatically outside proven basins, rendering it unviable compared to unsubsidized solar-plus-storage or nuclear options in many contexts. The estimates geothermal could supply only about 3% of global by 2050 under optimistic technical potential scenarios, a figure dwarfed by the contributions projected for other renewables, underscoring how institutional —often driven by incentives rather than empirical deployment —overstates its capacity to transform systems. Such discrepancies highlight the need for first-principles evaluation of subsurface physics over unsubstantiated extrapolations from theoretical heat flows.

Future Prospects

Innovations in drilling and EGS scaling

Advancements in technologies have addressed longstanding barriers to accessing deeper geothermal reservoirs, enabling the exploitation of hotter rocks for higher energy yields. Fervo Energy demonstrated rapid progress in June 2025 by a 15,765-foot well reaching projected temperatures of 520°F in just 16 days, achieving a 79% reduction in time compared to conventional U.S. Department of Energy benchmarks through optimized and bit performance. Similarly, Quaise Energy achieved a milestone in July 2025 by to 100 meters using millimeter-wave , which vaporizes rock without mechanical downhole tools, potentially allowing access to superhot rock depths exceeding 20 kilometers for continuous baseload power. These innovations draw from oil and gas adaptations, including polycrystalline diamond compact bits and managed pressure , which enhance penetration rates in hard crystalline formations typical of geothermal targets. Enhanced Geothermal Systems (EGS) scaling relies on creating artificial fractures in hot dry rock to form heat exchangers, with recent demonstrations validating commercial viability. In 2025, Fervo Energy's collaboration with the FORGE project confirmed well connectivity and efficient in EGS reservoirs, achieving recovery factors of 50-60%, triple the rates of prior estimates. Fervo secured $206 million in financing in June 2025 to advance Cape Station, the world's largest EGS development in , targeting phased deployment of up to 400 MW with subsurface innovations enabling 18-month project timelines from drilling to power generation. A Clean Air Task Force report from September 2025 highlights 50 years of EGS progress, positioning the technology at the cusp of large-scale deployment through improved stimulation techniques that minimize while maximizing permeability. Projections indicate EGS could supply up to 100 GW in the U.S. by 2050, with levelized costs potentially falling to $50 per MWh by 2035 via drilling efficiencies and modular power plants. However, scaling requires site-specific geological assessments to ensure fracture propagation and long-term reservoir integrity, as evidenced by ongoing pilots integrating fiber-optic monitoring for real-time performance data.

Projected growth and integration challenges

Global geothermal power capacity stood at approximately 16.9 GW at the end of , reflecting a historical annual growth rate of around 3% since 2000. Projections indicate potential for significant expansion, particularly through enhanced geothermal systems (EGS) and advanced drilling technologies, with the (IEA) outlining an ambitious scenario where capacity could reach up to 800 GW by 2050, supplying nearly 6,000 TWh annually and meeting 15% of global demand growth. This would require cumulative investments of $2.5 by mid-century, driven by cost reductions targeting an 80% drop in levelized costs to $50/MWh by 2035. Regional targets, such as the U.S. Department of Energy's aim for 90 GW domestically by 2050, underscore EGS scalability, though realization depends on policy support and technological breakthroughs. Achieving these projections faces substantial economic hurdles, including high upfront capital expenditures—often exceeding those of solar or per MW—and exploration risks that result in dry wells up to 30% of the time, inflating project uncertainties. Financing remains constrained by these risks and long development timelines, typically 5-10 years from to operation, deterring private investment without de-risking mechanisms like government guarantees. Regulatory and permitting challenges exacerbate delays, with processes in many jurisdictions taking up to a decade due to environmental assessments and land-use conflicts, affecting fewer than 30 countries with dedicated geothermal policies compared to over 100 for solar and . Integration into power grids, while facilitated by geothermal's high capacity factors exceeding 75%, is complicated by the remote locations of viable resources, necessitating costly transmission expansions and potential upgrades for voltage stability and frequency regulation. A shortage of specialized geologists, engineers, and drillers—potentially needing to scale to 1 million jobs by 2030—further impedes deployment, as does competition from cheaper, faster-to-deploy renewables in policy-driven markets. Despite these barriers, geothermal's baseload reliability positions it as a complementary firm power source, provided innovations in co-production with oil/gas wells and risk-mitigation strategies accelerate adoption.

Comparative role versus other baseload sources

Geothermal power serves as a renewable baseload source with capacity factors typically ranging from 70% to over 90% at optimal sites, comparable to nuclear power's average of around 92% and superior to coal's 50% and combined-cycle ' 60%. This high utilization enables it to provide continuous, dispatchable without the of solar or , positioning it as a potential offset for baseload in geologically favorable regions, though its output remains steady and less flexible for rapid ramping compared to gas . Globally, geothermal's installed capacity reached approximately 15.4–16.9 GW by late 2024, contributing less than 1% of total and dwarfed by nuclear's ~400 GW, coal's thousands of GW, and natural gas's comparable scale. In the U.S., it accounted for 0.4% of generation in 2024, versus nuclear's 18% and fuels' majority share. This limited scale stems from resource confinement to tectonic hotspots, contrasting with the site flexibility of nuclear and plants, which can be deployed more broadly but incur ongoing fuel costs and emissions for the latter. On economics, the levelized cost of energy (LCOE) for geothermal fell 16% in 2024 to around $0.07–0.09/kWh globally, competitive with unsubsidized or gas but higher than mature renewables like onshore ; it undercuts new nuclear's capital-intensive builds while avoiding volatility. Environmentally, geothermal emits 99% less CO₂ than equivalent plants and produces no long-lived like nuclear, though it requires upfront drilling risks absent in gas. Overall, while geothermal offers low-carbon baseload reliability akin to nuclear without dependence, its geographic constraints hinder it from rivaling fuels' historical dominance or nuclear's potential for widespread deployment in mixes.

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