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Steam rising from the Nesjavellir Geothermal Power Station in Iceland
The Imperial Valley Geothermal Project near the Salton Sea, California
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Renewable energy

Geothermal energy is thermal energy extracted from the Earth's crust. It combines energy from the formation of the planet and from radioactive decay. Geothermal energy has been exploited as a source of heat and/or electric power for millennia.

Geothermal heating, using water from hot springs, for example, has been used for bathing since Paleolithic times and for space heating since Roman times. Geothermal power (generation of electricity from geothermal energy), has been used since the 20th century. Geothermal power plants produce power at a constant rate, without regard to weather conditions. Geothermal resources are theoretically more than adequate to supply humanity's energy needs. Most extraction occurs in areas near tectonic plate boundaries.

The cost of generating geothermal power decreased by 25% during the 1980s and 1990s.[1] Technological advances continued to reduce costs and thereby expand the amount of viable resources. In 2021, the US Department of Energy estimated that power from a newly built plant costs about $0.05/kWh.[2]

In 2019, 13,900 megawatts (MW) of geothermal power was available worldwide.[3] An additional 28 gigawatts provided heat for district heating, space heating, spas, industrial processes, desalination, and agricultural applications as of 2010.[4] As of 2019 the industry employed about one hundred thousand people.[5]

The adjective geothermal originates from the Greek roots γῆ (gê), meaning the Earth, and θερμός (thermós), meaning hot.

History

[edit]
The oldest known pool fed by a hot spring, built in the Qin dynasty in the 3rd century BCE

Hot springs have been used for bathing since at least Paleolithic times.[6] The oldest known spa is at the site of the Huaqing Chi palace. In the first century CE, Romans conquered Aquae Sulis, now Bath, Somerset, England, and used the hot springs there to supply public baths and underfloor heating. The admission fees for these baths probably represent the first commercial use of geothermal energy. The world's oldest geothermal district heating system, in Chaudes-Aigues, France, has been operating since the 15th century.[7] The earliest industrial exploitation began in 1827 with the use of geyser steam to extract boric acid from volcanic mud in Larderello, Italy.

In 1892, the US's first district heating system in Boise, Idaho was powered by geothermal energy. It was copied in Klamath Falls, Oregon, in 1900. The world's first known building to utilize geothermal energy as its primary heat source was the Hot Lake Hotel in Union County, Oregon, beginning in 1907.[8] A geothermal well was used to heat greenhouses in Boise in 1926, and geysers were used to heat greenhouses in Iceland and Tuscany at about the same time.[9] Charles Lieb developed the first downhole heat exchanger in 1930 to heat his house. Geyser steam and water began heating homes in Iceland in 1943.

Global geothermal electric capacity. Upper red line is installed capacity;[10] lower green line is realized production.[4]

In the 20th century, geothermal energy came into use as a generating source. Prince Piero Ginori Conti tested the first geothermal power generator on 4 July 1904, at the Larderello steam field. It successfully lit four light bulbs.[11] In 1911, the world's first commercial geothermal power plant was built there. It was the only industrial producer of geothermal power until New Zealand built a plant in 1958. In 2012, it produced some 594 megawatts.[12]

In 1960, Pacific Gas and Electric began operation of the first US geothermal power plant at The Geysers in California.[13] The original turbine lasted for more than 30 years and produced 11 MW net power.[14]

An organic fluid based binary cycle power station was first demonstrated in 1967 in the USSR[13] and later introduced to the US in 1981[citation needed]. This technology allows the use of temperature resources as low as 81 °C. In 2006, a binary cycle plant in Chena Hot Springs, Alaska, came on-line, producing electricity from a record low temperature of 57 °C (135 °F).[15]

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 has an internal heat content of 1031 joules (3·1015 TWh), About 20% of this is residual heat from planetary accretion; the remainder is attributed to past and current radioactive decay of naturally occurring isotopes.[16] For example, a 5275 m deep borehole in United Downs Deep Geothermal Power Project in Cornwall, England, found granite with very high thorium content, whose radioactive decay is believed to power the high temperature of the rock.[17]

Earth's interior temperature and pressure are high enough to cause some rock to melt and the solid mantle to behave plastically. Parts of the mantle convect upward since it is lighter than the surrounding rock. Temperatures at the core–mantle boundary can reach over 4,000 °C (7,230 °F).[18]

The Earth's internal thermal energy flows to the surface by conduction at a rate of 44.2 terawatts (TW),[19] and is replenished by radioactive decay of minerals at a rate of 30 TW.[20] These power rates are more than double humanity's current energy consumption from all primary sources, but most of this energy flux is not recoverable. In addition to the internal heat flows, the top layer of the surface to a depth of 10 m (33 ft) is heated by solar energy during the summer, and cools during the winter.

Outside of the seasonal variations, the geothermal gradient of temperatures through the crust is 25–30 °C (77–86 °F) per km of depth in most of the world. The conductive heat flux averages 0.1 MW/km2. These values are much higher near tectonic plate boundaries where the crust is thinner. They may be further augmented by combinations of fluid circulation, either through magma conduits, hot springs, hydrothermal circulation.

The thermal efficiency and profitability of electricity generation is particularly sensitive to temperature. Applications receive the greatest benefit from a high natural heat flux most easily from a hot spring. The next best option is to drill a well into a hot aquifer. An artificial hot water reservoir may be built by injecting water to hydraulically fracture bedrock. The systems in this last approach are called enhanced geothermal systems.[21]

2010 estimates of the potential for electricity generation from geothermal energy vary widely, from 0.035to2TW depending on the scale of investments.[4] Upper estimates of geothermal resources assume wells as deep as 10 kilometres (6 mi), although 20th century wells rarely reached more than 3 kilometres (2 mi) deep.[4] Wells of this depth are common in the petroleum industry.[22]

Geothermal power

[edit]
Main article: Geothermal power

Geothermal power is electrical power generated from geothermal energy. Dry steam, flash steam, and binary cycle power stations have been used for this purpose. As of 2010 geothermal electricity was generated in 26 countries.[23][24]

As of 2019, worldwide geothermal power capacity amounted to 15.4 gigawatts (GW), of which 23.86 percent or 3.68 GW were in the United States.[25]

Geothermal energy supplies a significant share of the electrical power in Iceland, El Salvador, Kenya, the Philippines and New Zealand.[26]

Geothermal power is considered to be a renewable energy because heat extraction rates are insignificant compared to the Earth's heat content.[20] The greenhouse gas emissions of geothermal electric stations are on average 45 grams of carbon dioxide per kilowatt-hour of electricity, or less than 5 percent of that of coal-fired plants.[27]

Geothermal electric plants were traditionally built on the edges of tectonic plates where high-temperature geothermal resources approach the surface. The development of binary cycle power plants and improvements in drilling and extraction technology enable enhanced geothermal systems over a greater geographical range.[21] 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 US.[28] In Myanmar over 39 locations are capable of geothermal power production, some of which are near Yangon.[29]

Direct use data 2015
Country Capacity (MW) 2015[30]
United States 17,415
Philippines 3
Indonesia 2
Mexico 155
Italy 1,014
New Zealand 487
Iceland 2,040
Japan 2,186
Iran 81
El Salvador 3
Kenya 22
Costa Rica 1
Russia 308
Turkey 2,886
Papua New Guinea 0.10
Guatemala 2
Portugal 35
China 17,870
France 2,346
Ethiopia 2
Germany 2,848
Austria 903
Australia 16
Thailand 128
Installed geothermal electric capacity
Country Capacity (MW)
(2024)[31] 		% of national
electricity
production

(2024)[32]

% of global
geothermal
production (2024)[32]
Australia 0 0.0% 0.0%
Austria 0 0.0% 0.0%
Canada 6 0.0% 0.0%
Chile 95 0.4% 0.6%
China 26 0.0% 0.2%
Taiwan 7 0.0% 0.0%
Costa Rica 263 8.3% 1.7%
Croatia 10 0.0% 0.0%
El Salvador 209 11.2% 1.4%
Ethiopia 7 0.1% 0.0%
France 16 0.0% 0.1%
Germany 44 0.0% 0.3%
Guadeloupe 15 6.6% 0.1%
Guatemala 49 1.8% 0.3%
Honduras 39 2.0% 0.3%
Hungary 3 0.0% 0.0%
Iceland 788 26.8% 5.1%
Indonesia 2,688 18.8% 17.4%
Italy 772 1.1% 5.0%
Japan 461 0.3% 3.0%
Kenya 940 33.7% 6.1%
Mexico 999 2.9% 6.5%
New Zealand 1,275 14.3% 8.3%
Nicaragua 165 21.5% 1.1%
Papua New Guinea 51 12.8% 0.3%
Philippines 1,952 21.0% 12.7%
Portugal 29 0.1% 0.2%
Romania 0 0.0% 0.0%
Russia 81 0.1% 0.5%
Thailand 0 0.0% 0.0%
Turkey 1,734 2.5% 11.2%
United States 2,703 0.6% 17.5%
Total 16,738

Geothermal heating

[edit]
Main article: Geothermal heating

Geothermal heating is the use of geothermal energy to heat buildings and water for human use. Humans have done this since the Paleolithic era. Approximately seventy countries made direct use of a total of 270 PJ of geothermal heating in 2004. As of 2007, 28 GW of geothermal heating satisfied 0.07% of global primary energy consumption.[4] Thermal efficiency is high since no energy conversion is needed, but capacity factors tend to be low (around 20%) since the heat is mostly needed in the winter.

Even cold ground contains heat: below 6 metres (20 ft) the undisturbed ground temperature is consistently at the Mean Annual Air Temperature[33] that may be extracted with a ground source heat pump.

Types

[edit]

Hydrothermal systems

[edit]

Hydrothermal systems produce geothermal energy by accessing naturally occurring hydrothermal reservoirs. Hydrothermal systems come in either vapor-dominated or liquid-dominated forms.

Vapor-dominated plants

[edit]

Larderello and The Geysers are vapor-dominated. Vapor-dominated sites offer temperatures from 240 to 300 °C that produce superheated steam.

Liquid-dominated plants

[edit]

Liquid-dominated reservoirs (LDRs) are more common with temperatures greater than 200 °C (392 °F) and are found near volcanoes in/around the Pacific Ocean and in rift zones and hot spots. Flash plants are the common way to generate electricity from these sources. Steam from the well is sufficient to power the plant. Most wells generate 2–10 MW of electricity. Steam is separated from liquid via cyclone separators and drives electric generators. Condensed liquid returns down the well for reheating/reuse. As of 2013, the largest liquid system was Cerro Prieto in Mexico, which generates 750 MW of electricity from temperatures reaching 350 °C (662 °F).

Lower-temperature LDRs (120–200 °C) require pumping. They are common in extensional terrains, where heating takes place via deep circulation along faults, such as in the Western US and Turkey. Water passes through a heat exchanger in a Rankine cycle binary plant. The water vaporizes an organic working fluid that drives a turbine. These binary plants originated in the Soviet Union in the late 1960s and predominate in new plants. Binary plants have no emissions.[12][34]

Engineered geothermal systems

[edit]

An engineered geothermal system is a geothermal system that engineers have artificially created or improved. Engineered geothermal systems are used in a variety of geothermal reservoirs that have hot rocks but insufficient natural reservoir quality, for example, insufficient geofluid quantity or insufficient rock permeability or porosity, to operate as natural hydrothermal systems. Types of engineered geothermal systems include enhanced geothermal systems, closed-loop or advanced geothermal systems, and some superhot rock geothermal systems.[35]

Enhanced geothermal systems

[edit]
Main article: Enhanced geothermal system

Enhanced geothermal systems (EGS) actively inject water into wells to be heated and pumped back out. The water is injected under high pressure to expand existing rock fissures to enable the water to flow freely. The technique was adapted from oil and gas fracking techniques. The geologic formations are deeper and no toxic chemicals are used, reducing the possibility of environmental damage. Instead proppants such as sand or ceramic particles are used to keep the cracks open and producing optimal flow rates.[36] Drillers can employ directional drilling to expand the reservoir size.[12]

Small-scale EGS have been installed in the Rhine Graben at Soultz-sous-Forêts in France and at Landau and Insheim in Germany.[12]

Closed-loop geothermal systems

[edit]
Main article: Closed-loop geothermal

Closed-loop geothermal systems, sometimes colloquially referred to as Advanced Geothermal Systems (AGS), are engineered geothermal systems containing subsurface working fluid that is heated in the hot rock reservoir without direct contact with rock pores and fractures. Instead, the subsurface working fluid stays inside a closed loop of deeply buried pipes that conduct Earth's heat. The advantages of a deep, closed-loop geothermal circuit include: (1) no need for a geofluid, (2) no need for the hot rock to be permeable or porous, and (3) all the introduced working fluid can be recirculated with zero loss.[35] Eavortm, a Canadian-based geothermal startup, piloted their closed-loop system in shallow soft rock formations in Alberta, Canada. Situated within a sedimentary basin, the geothermal gradient proved to be insufficient for electrical power generation. However, the system successfully produced approximately 11,000 MWh of thermal energy during its initial two years of operation."[37][38]

Economics

[edit]

As with wind and solar energy, geothermal power has minimal operating costs; capital costs dominate. Drilling accounts for over half the costs, and not all wells produce exploitable resources. For example, as of 2009 a typical well pair (one for extraction and one for injection) in Nevada can produce 4.5 megawatts (MW) and costs about $10 million to drill, with a 20% failure rate, making the average cost of a successful well $50 million.[39]

A power plant at The Geysers

Drilling geothermal wells is more expensive than drilling oil and gas wells of comparable depth for several reasons:

  • Geothermal reservoirs are usually in igneous or metamorphic rock, which is harder to penetrate than the sedimentary rock of typical hydrocarbon reservoirs.
  • The rock is often fractured, which causes vibrations that damage bits and other drilling tools.
  • The rock is often abrasive, with high quartz content, and sometimes contains highly corrosive fluids.
  • The rock is hot, which limits use of downhole electronics.
  • Well casing must be cemented from top to bottom, to resist the casing's tendency to expand and contract with temperature changes. Oil and gas wells are usually cemented only at the bottom.
  • Well diameters are considerably larger than typical oil and gas wells.[40]

As of 2007 plant construction and well drilling cost about €2–5 million per MW of electrical capacity, while the break-even price was 0.04–0.10 € per kW·h.[10] Enhanced geothermal systems tend to be on the high side of these ranges, with capital costs above $4 million per MW and break-even above $0.054 per kW·h.[41]

Between 2013 and 2020, private investments were the main source of funding for renewable energy, comprising approximately 75% of total financing. The mix between private and public funding varies among different renewable energy technologies, influenced by their market appeal and readiness. In 2020, geothermal energy received just 32% of its investment from private sources.[42][43]

Socioeconomic benefits

[edit]

In January 2024, the Energy Sector Management Assistance Program (ESMAP) report "Socioeconomic Impacts of Geothermal Energy Development" was published, highlighting the substantial socioeconomic benefits of geothermal energy development, which notably exceeds those of wind and solar by generating an estimated 34 jobs per megawatt across various sectors. The report details how geothermal projects contribute to skill development through practical on-the-job training and formal education, thereby strengthening the local workforce and expanding employment opportunities. It also underscores the collaborative nature of geothermal development with local communities, which leads to improved infrastructure, skill-building programs, and revenue-sharing models, thereby enhancing access to reliable electricity and heat. These improvements have the potential to boost agricultural productivity and food security. The report further addresses the commitment to advancing gender equality and social inclusion by offering job opportunities, education, and training to underrepresented groups, ensuring fair access to the benefits of geothermal development. Collectively, these efforts are instrumental in driving domestic economic growth, increasing fiscal revenues, and contributing to more stable and diverse national economies, while also offering significant social benefits such as better health, education, and community cohesion.[44]

Development

[edit]

Geothermal projects have several stages of development. Each phase has associated risks. Many projects are canceled during the stages of reconnaissance and geophysical surveys, which are unsuitable for traditional lending. At later stages can often be equity-financed.[45]

Precipitate scaling

[edit]

A common issue encountered in geothermal systems arises when the system is situated in carbonate-rich formations. In such cases, the fluids extracting heat from the subsurface often dissolve fragments of the rock during their ascent towards the surface, where they subsequently cool. As the fluids cool, dissolved cations precipitate out of solution, leading to the formation of calcium scale, a phenomenon known as calcite scaling. This calcite scaling has the potential to decrease flow rates and necessitate system downtime for maintenance purposes.[46]

Sustainability

[edit]

Geothermal energy is considered to be sustainable because the heat extracted is so small compared to the Earth's heat content, which is approximately 100 billion times 2010 worldwide annual energy consumption.[4] Earth's heat flows are not in equilibrium; the planet is cooling on geologic timescales. Anthropic heat extraction typically does not accelerate the cooling process.

Wells can further be considered renewable because they return the extracted water to the borehole for reheating and re-extraction, albeit at a lower temperature.

Replacing material use with energy has reduced the human environmental footprint in many applications. Geothermal has the potential to allow further reductions. For example, Iceland has sufficient geothermal energy to eliminate fossil fuels for electricity production and to heat Reykjavik sidewalks and eliminate the need for gritting.[47]

Electricity generation at Poihipi, New Zealand
Electricity generation at Ohaaki, New Zealand
Electricity generation at Wairakei, New Zealand

However, local effects of heat extraction must be considered.[20] Over the course of decades, individual wells draw down local temperatures and water levels. The three oldest sites, at Larderello, Wairakei, and the Geysers experienced reduced output because of local depletion. Heat and water, in uncertain proportions, were extracted faster than they were replenished. Reducing production and injecting additional water could allow these wells to recover their original capacity. Such strategies have been implemented at some sites. These sites continue to provide significant energy.[48][49]

The Wairakei power station was commissioned in November 1958, and it attained its peak generation of 173 MW in 1965, but already the supply of high-pressure steam was faltering. In 1982 it was down-rated to intermediate pressure and the output to 157 MW. In 2005 two 8 MW isopentane systems were added, boosting output by about 14 MW. Detailed data were lost due to re-organisations.

Environmental effects

[edit]
Geothermal power station in the Philippines
Krafla Geothermal Station in northeast Iceland

Fluids drawn from underground carry a mixture of gasses, notably carbon dioxide (CO
2), hydrogen sulfide (H
2S), methane (CH
4) and ammonia (NH
3). These pollutants contribute to global warming, acid rain and noxious smells if released. Existing geothermal electric plants emit an average of 122 kilograms (269 lb) of CO
2 per megawatt-hour (MW·h) of electricity, a small fraction of the emission intensity of fossil fuel plants.[50][needs update] A few plants emit more pollutants than gas-fired power, at least in the first few years, such as some geothermal power in Turkey.[51] Plants that experience high levels of acids and volatile chemicals are typically equipped with emission-control systems to reduce the exhaust. New emerging closed looped technologies developed by Eavor have the potential to reduce these emissions to zero.[37]

Water from geothermal sources may hold in solution trace amounts of toxic elements such as mercury, arsenic, boron, and antimony.[52] These chemicals precipitate as the water cools, and can damage surroundings if released. The modern practice of returning geothermal fluids into the Earth to stimulate production has the side benefit of reducing this environmental impact.

Construction can adversely affect land stability. Subsidence occurred in the Wairakei field.[7] In Staufen im Breisgau, Germany, tectonic uplift occurred instead. A previously isolated anhydrite layer came in contact with water and turned it into gypsum, doubling its volume.[53][54][55] Enhanced geothermal systems can trigger earthquakes as part of hydraulic fracturing. A 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.[56]

Geothermal power production has minimal land and freshwater requirements. Geothermal plants use 3.5 square kilometres (1.4 sq mi) per gigawatt of electrical production (not capacity) versus 32 square kilometres (12 sq mi) and 12 square kilometres (4.6 sq mi) for coal facilities and wind farms respectively.[7] They use 20 litres (5.3 US gal) of freshwater per MW·h versus over 1,000 litres (260 US gal) per MW·h for nuclear, coal, or oil.[7]

Production

[edit]

Philippines

[edit]

The Philippines began geothermal research in 1962 when the Philippine Institute of Volcanology and Seismology inspected the geothermal region in Tiwi, Albay.[57] The first geothermal power plant in the Philippines was built in 1977, located in Tongonan, Leyte.[57] The New Zealand government contracted with the Philippines to build the plant in 1972.[58] The Tongonan Geothermal Field (TGF) added the Upper Mahiao, Matlibog, and South Sambaloran plants, which resulted in a 508 MV capacity.[59]

The first geothermal power plant in the Tiwi region opened in 1979, while two other plants followed in 1980 and 1982.[57] The Tiwi geothermal field is located about 450 km from Manila.[60] The three geothermal power plants in the Tiwi region produce 330 MWe, putting the Philippines behind the United States and Mexico in geothermal growth.[61] The Philippines has 7 geothermal fields and continues to exploit geothermal energy by creating the Philippine Energy Plan 2012–2030 that aims to produce 70% of the country's energy by 2030.[62][63]

United States

[edit]

According to the Geothermal Energy Association (GEA) installed geothermal capacity in the United States grew by 5%, or 147.05 MW, in 2013. This increase came from seven geothermal projects that began production in 2012. GEA revised its 2011 estimate of installed capacity upward by 128 MW, bringing installed US geothermal capacity to 3,386 MW.[64]

Hungary

[edit]

The municipal government of Szeged is trying to cut down its gas consumption by 50 percent by utilizing geothermal energy for its district heating system. The Szeged geothermal power station has 27 wells, 16 heating plants, and 250 kilometres of distribution pipes.[65]

See also

[edit]

References

[edit]
[edit]
Revisions and contributorsEdit on WikipediaRead on Wikipedia

Geothermal energy

View on Grokipedia
from Grokipedia
Geothermal energy is the heat derived from the Earth's interior, originating from of isotopes in and crust as well as primordial heat from planetary accretion, which continuously flows toward the surface through conduction and in underground fluids. This thermal resource is harnessed via wells that access hot or reservoirs, typically in tectonically active regions, to drive turbines for production or provide direct heating, offering a baseload source with capacity factors often between 60% and 90%. utilization dates back thousands of years for bathing and therapeutic purposes in hot springs, evolving to industrial applications like extraction in 19th-century and the world's first geothermal power plant in Larderello, , in 1904, which remains operational. As of late , global installed geothermal capacity reached 15.4 gigawatts, concentrated in countries such as the , , Türkiye, , and , where it supplies significant fractions of national energy needs, exemplified by deriving over 25% of its from geothermal sources. While advantages include near-zero operational , minimal land use, and reliability independent of weather, challenges encompass site-specific geological requirements, high initial drilling costs, and risks of from fluid extraction or injection. Emerging enhanced geothermal systems (EGS) aim to broaden accessibility by creating artificial reservoirs in hot dry rock, though commercialization faces technical hurdles in permeability enhancement and long-term .

Fundamentals

Basic Principles

Geothermal energy derives from the stored within the and mantle, originating from residual heat retained during planetary accretion about 4.54 billion years ago and ongoing radiogenic heat production via the decay of isotopes such as , , and potassium-40. This heat flux averages approximately 0.087 watts per square meter at the surface globally, with variations tied to local and tectonic activity. Frictional dissipation from viscous flow in the mantle contributes a smaller portion, sustaining convective currents that transport heat toward the surface. The , defined as the rate of temperature increase with depth, typically measures 25–30 °C per kilometer in , though it can exceed 40 °C/km in rift zones or subduction areas due to thinned crust and magmatic intrusions. This gradient arises from conductive in the rigid overlying the convecting , modulated by rock thermal conductivity (around 2–3 W/m·K for typical crustal rocks) and advective transport via or . In equilibrium, subsurface temperatures reflect this gradient superimposed on surface conditions, enabling shallow resources (e.g., 50–150 °C at 1–3 km depths) in high-heat-flow regions while deeper drilling accesses hotter reservoirs. Exploitation relies on hydrological systems where meteoric water percolates into permeable, hot formations, convecting to accessible depths and forming reservoirs of pressurized hot water or . Heat extraction disrupts this equilibrium minimally due to the Earth's vast internal —estimated at 10^31 joules, dwarfing annual global —rendering geothermal resources effectively renewable on human timescales as radiogenic production replenishes losses. hinges on to avoid excessive drawdown, with reinjection of cooled fluids preserving pressure and minimizing risks observed in overexploited fields.

Heat Sources

The primary heat sources for geothermal energy are the residual primordial heat retained from Earth's formation approximately 4.5 billion years ago—arising from gravitational accretion, core formation, and initial differentiation—and ongoing radiogenic heat production from the decay of isotopes such as , , and within the planet's crust, mantle, and core. Primordial heat, though diminishing through secular cooling, contributes to and overall geothermal gradients, while radiogenic decay provides a continuous replenishment, for roughly half of Earth's current surface heat loss of about 44 terawatts. In the continental crust, where most exploitable geothermal resources are located, radiogenic heat production dominates the accessible thermal budget, with average values around 0.5–1.0 microwatts per cubic meter due to concentrated radioactive elements; this contrasts with the , where thinner sedimentary layers and higher conductive heat loss from yield different profiles. The global average geothermal at the surface is approximately 87 milliwatts per square meter, varying regionally: about 65 milliwatts per square meter on continents (driven more by crustal radiogenic sources) and 101 milliwatts per square meter in oceanic areas (influenced by younger lithospheric cooling). These fluxes sustain near-surface temperature gradients of 25–30°C per kilometer in stable cratonic regions, enabling resource development where local enhancements from or faulting amplify heat flow. Volcanic and tectonic settings, such as mid-ocean ridges or subduction zones, locally boost heat availability through mantle upwelling and , but even in non-magmatic areas, baseline crustal radiogenic heating supports shallow geothermal applications like ground-source heat pumps by maintaining subsurface temperatures above ambient air levels. Quantifying the radiogenic fraction remains model-dependent, with estimates suggesting it supplies 40–50% of continental surface heat flow, underscoring its role in long-term resource despite debates over mantle versus crustal partitioning.

History

Pre-20th Century Uses

Humans have utilized geothermal resources for direct heating applications since prehistoric times. Archaeological evidence from suggests that employed hot springs for cooking, bathing, warmth, and medicinal treatments at least 10,000 years ago. Similar practices persisted among Native American tribes, who regarded geothermal sites as neutral grounds for respite amid conflicts and used the waters for cleansing and mineral extraction. Ancient civilizations across and also harnessed geothermal heat primarily for bathing and therapeutic purposes. The Romans engineered extensive bath complexes over natural hot springs, such as those at (modern Bath, ), constructed around 70 AD, where geothermal waters reaching temperatures of 46–49 °C facilitated public hygiene, socializing, and underfloor heating systems in select locations. In , hot springs, formed by geothermal activity, supported bathing rituals documented from the in the 7th century, with sites like Shirahama Onsen providing naturally heated waters rich in minerals for health benefits. Māori communities in integrated geothermal pools and vents into daily life before European arrival in the , employing them for cooking, , heating, and treating ailments, viewing such features as tapu (sacred) sources of sustenance and healing. The transition to organized industrial exploitation began in the early . In 1827, French engineer François Jacques de Larderel initiated the first large-scale commercial use near Larderello, , , channeling steam from natural fumaroles and shallow boreholes to evaporate geothermal waters for production, yielding compounds for glassmaking, ceramics, and pharmaceuticals; this operation expanded to multiple factories by the 1830s, marking the inception of geothermal-derived chemical processing. These pre-electricity applications underscored geothermal energy's role in direct thermal utilization, predating mechanized power generation by nearly a century.

20th Century Development

The development of geothermal energy for electricity generation began in Italy at the Larderello field in Tuscany. On July 4, 1904, Prince Piero Ginori Conti successfully generated electricity from geothermal steam to power five light bulbs using a dynamo, marking the first demonstration of geothermal electric power production. This experiment laid the groundwork for further advancements, leading to the commissioning of the world's first commercial geothermal power plant in 1913 at the same site, with an initial capacity of 250 kilowatts that supplied local needs including the nearby borax plant. By the mid-20th century, Larderello had expanded, contributing significantly to Italy's energy supply amid wartime demands during World War I and II. In the 1950s, pioneered the use of geothermal hot water for power generation at Wairakei, where exploratory drilling began in 1950. The first turbine came online on November 15, 1958, producing 12.5 megawatts using flash technology to separate from geothermal fluids, a distinct from Italy's dry systems. This marked the world's first wet geothermal power station, with full Stage 1 completion by 1960 at 153 megawatts, enabling large-scale electricity export to the national grid. Concurrently, in the United States, field in saw its first exploratory well in 1922, but commercial power generation started with Pacific Gas and Electric's Unit 1 in 1960, initially at 11 megawatts, leveraging abundant dry resources. The latter half of the century witnessed broader adoption, particularly in , where geothermal resources shifted from traditional bathing and cooking to systems. Reykjavik's first municipal network was established in the 1930s, reducing reliance on imported and expanding to heat over 90% of homes by century's end. followed, with 's first plant at operational by 1969, though direct heating applications dominated early development. Globally, by 2000, installed geothermal capacity exceeded 8,000 megawatts across 20 countries, driven by technological refinements in drilling and steam utilization that mitigated resource depletion risks observed in fields like Larderello and .

21st Century Advances

Global installed capacity grew from approximately 8 GW in 2000 to 15 GW by 2023, reflecting annual expansion rates of around 3.5%, with significant contributions from new plants in , , and . This period saw incremental improvements in conventional hydrothermal technologies, including plants that enhanced efficiency for lower-temperature resources, enabling deployment in regions like the ' field reinjection efforts. A major focus of 21st-century innovation has been enhanced geothermal systems (EGS), which involve hydraulic stimulation of hot dry rock formations to create artificial reservoirs, potentially unlocking geothermal potential worldwide beyond limited hydrothermal sites. Development accelerated with U.S. Department of Energy initiatives, including the Frontier Observatory for Research in Geothermal Energy () project launched in 2018 at , to test EGS feasibility through iterative field experiments. Private sector progress included Fervo Energy's 2023 pilot in , which demonstrated rapid drilling and stimulation techniques yielding commercial-grade output, paving the way for contracts delivering up to 50 MW by 2025-2026. These advances build on decades of research but gained momentum from improved horizontal drilling borrowed from oil and gas sectors, reducing costs by up to 50% in recent demonstrations. Research into supercritical geothermal resources, where fluids exceed 374°C and 22 MPa for exponentially higher , marked another frontier, with Iceland's IDDP-2 well in 2016 successfully tapping such conditions to produce equivalent to 35 MW from one . advanced its NEDO-funded supercritical project through 2022, targeting depths over 4 km, while identified the Rotokawa site in 2025 for its first exploratory supercritical well, supported by government funding of NZ$10 million. These efforts, though challenged by extreme drilling demands, promise efficiencies up to ten times conventional systems, contingent on materials innovations like high-temperature-resistant casings.

Resources

Global Distribution and Reserves

Geothermal resources are predominantly located in tectonically active regions characterized by high heat flow from Earth's interior, including zones, mid-ocean ridges, rift valleys, and volcanic hotspots. These areas feature shallow chambers, thin , or elevated geothermal gradients, enabling accessible high-temperature fluids or rocks suitable for energy extraction. The majority of viable resources lie along the , the in , and island arcs in and the Mediterranean. Global assessments indicate vast untapped geothermal potential, far exceeding current utilization. The technical potential for from enhanced geothermal systems (EGS) at depths less than 5,000 meters is estimated at 42 terawatts (TW) of power capacity over 20 years of operation, equivalent to 21,000 exajoules (EJ) of . For conventional hydrothermal resources, identified high-enthalpy reserves suitable for power are more limited, with global estimates around 200 gigawatts (GW) of economically recoverable capacity, though exploration continues to expand known inventories. Installed capacity reached 15.4 GW by the end of 2024, representing less than 1% of the technical potential.
CountryEstimated Conventional Potential (GW)Installed Capacity (MW, end-2024)
Indonesia~29~2,300
United States~30 (hydrothermal + EGS potential >500)~3,700
Philippines~5-10~1,900
Türkiye~4-6~1,700
Kenya~10~900
New Zealand~1-2~1,000
Iceland~2~800
Key countries with significant reserves include , which holds the largest identified conventional potential due to its volcanic archipelago, and the , where western states like and host substantial hydrothermal fields and EGS prospects exceeding 500 GW in total. The and Türkiye also feature high potential from subduction-related volcanism, while Kenya's resources support over 40% of its electricity from geothermal. These estimates derive from geological surveys and volumetric assessments, with actual recoverability depending on technological and economic factors; ASEAN nations collectively account for about 15% of global EGS technical potential.

Exploration and Assessment

Exploration of geothermal resources begins with regional reconnaissance to identify promising areas, often using geological mapping to delineate fault zones, volcanic features, and heat flow anomalies, as these indicate potential permeability and fluid circulation pathways. This initial phase integrates remote sensing data, such as satellite-based thermal infrared surveys, to detect surface manifestations like hot springs or fumaroles, which signal underlying hydrothermal systems. Geophysical methods then refine targets; electrical resistivity tomography and magnetotellurics are particularly effective for mapping low-resistivity zones associated with hot, saline fluids in reservoirs, with success in delineating structures up to several kilometers deep. Seismic reflection surveys help identify fractures and cap rocks, while gravity and magnetic methods detect density contrasts from intrusions or alteration minerals. Geochemical sampling complements by analyzing soil gases, , and emissions for , , and ratios that trace deep heat sources and recharge areas. For hidden systems lacking surface expression—estimated to constitute a significant portion of untapped resources—integrated approaches combining multiple techniques reduce , as single methods often yield ambiguous results due to subsurface heterogeneity. Exploratory follows, typically involving slim-hole wells (4-6 inches diameter) to test temperatures, pressures, and flow rates at depths of 1-3 km, with full-size wells confirming commercial viability. Drilling success rates for exploration wells average around 60%, rising to 75% in appraisal phases, though historical rates in regions like have been lower due to targeting uncertainties. Resource assessment quantifies extractable heat using volumetric methods, which estimate volume, temperature, , and recovery factors (typically 2-10% for conventional systems), as applied by the U.S. Geological Survey (USGS) for identified fields. For regional evaluations, USGS employs heat flow models and magmatic budgets, appraising U.S. conventional resources at over 500,000 MW-years equivalent through 2050, though enhanced systems expand potential. Numerical simulation provides dynamic forecasts of production decline, incorporating poroelastic effects and reinjection, but requires site-specific data to mitigate overestimation risks from optimistic assumptions. Uncertainty quantification, via simulations, accounts for geological variability, with exploration costs comprising 20-40% of total project expenses, underscoring the need for phased risk mitigation. Advances in for are improving predictive accuracy, as demonstrated in recent NREL efforts targeting resources.

Technologies

Conventional Hydrothermal Systems

Conventional hydrothermal systems utilize naturally occurring subsurface reservoirs containing hot water or steam at temperatures typically above 150°C, along with sufficient permeability to allow fluid extraction without extensive enhancement. These systems form where magmatic heat sources warm groundwater in porous rock layers, often capped by impermeable strata that trap fluids and enable pressure buildup. Essential components include a heat source from Earth's interior, a permeable reservoir rock, circulating fluids (predominantly water), and pathways for recharge to sustain long-term productivity. Unlike engineered alternatives, these resources require no artificial fracturing or fluid addition for initial development, relying instead on pre-existing geological conditions. Exploitation involves vertical or directional wells, often 1-3 km deep, to access the ; production wells extract , while injection wells return spent water to maintain pressure and minimize . Power generation occurs via three primary plant types suited to conditions: dry plants pipe vapor directly to turbines, as at Larderello, , operational since with initial output from a 250 kW unit; flash plants separate from high-pressure hot water; and plants transfer heat from lower-temperature liquids (90-150°C) to a secondary organic for , enabling broader resource use. These configurations achieve capacity factors of 70-90%, providing dispatchable baseload power with minimal greenhouse gas emissions, typically under 50 g CO2/kWh. Prominent examples include field in , the world's largest complex with over 700 MW capacity across multiple units, tapping dry steam reservoirs that peaked at 2,000 MW before depletion necessitated reinjection practices starting in the . In , Wairakei, commissioned in 1958, pioneered flash technology with initial 157 MW output from wet steam resources. Iceland's Hellisheiði plant, utilizing hydrothermal fluids at 300°C, integrates (303 MW) with , demonstrating hybrid applications. Challenges include reservoir cooling and pressure drawdown without adequate reinjection, as evidenced by output declines at mature sites like , where production fell over 70% from peak levels by 2010 due to fluid extraction exceeding natural recharge. Exploration relies on geophysical surveys, including seismic imaging and , to delineate reservoirs, followed by slim-hole for confirmation. Globally, such systems account for nearly all operational geothermal capacity, totaling about 14 GW as of 2023, concentrated in tectonically active regions.

Enhanced Geothermal Systems

Enhanced geothermal systems (EGS) involve subsurface in hot dry rock formations lacking natural permeability to enable heat extraction for or direct use. These systems target rocks at depths of 3 to 10 kilometers with temperatures exceeding 150°C, injecting under to induce fractures, thereby creating an artificial that allows circulation to absorb and transport heat to the surface. Unlike conventional hydrothermal systems reliant on pre-existing permeable aquifers, EGS artificially enhances permeability through hydraulic stimulation, adapting techniques from and gas hydraulic fracturing. Research and development of EGS originated in the 1970s with pilot projects, such as the Fenton Hill experiment in , where the U.S. Department of demonstrated closed-loop circulation in hot dry rock, achieving initial heat extraction rates but facing issues with sustained flow. Subsequent international efforts, including Australia's Hot Dry Rock program and European initiatives under the EU's EGS Generic Technology Pilot Plant, refined stimulation methods to improve fracture networks and reduce loss. In the United States, the DOE's Geothermal Technologies Office has invested in advancing EGS since the early 2000s, focusing on reducing drilling costs through innovations like polycrystalline diamond compact bits and supercritical CO2 as a alternative to . Demonstration projects illustrate EGS feasibility amid technical hurdles. Fervo Energy's 2023 pilot in achieved flow rates exceeding 60 liters per second with temperatures over 200°C, marking progress in commercial-scale stimulation without significant seismic events. The site in , designated by the DOE in 2018, serves as a field for testing EGS creation, with ongoing experiments aiming to validate permeability enhancements to 10-15 millidarcy levels. Internationally, the Soultz-sous-Forêts project in , operational since 2016, has produced electricity from an EGS at 5 km depth, though output remains limited to 1.5 MW due to circulation inefficiencies. Key challenges include from stimulation, which can exceed magnitude 2 events and pose permitting risks, as observed in early trials where microseismic monitoring revealed unpredictable . Drilling in hard, high-temperature crystalline rock elevates costs, with well completion expenses reaching $10-20 million per kilometer, compounded by issues like lost circulation and . demands minimizing short-circuiting between injection and production wells to maintain heat extraction efficiency, often requiring advanced and modeling; without this, heat recovery factors drop below 1% annually. Economic viability hinges on achieving levelized costs below $0.05/kWh, but current demonstrations indicate $0.10-0.20/kWh due to these factors, necessitating subsidies or technological breakthroughs. Despite obstacles, EGS resource potential is vast, with U.S. estimates indicating 4,349 gigawatts-electric of deep EGS capacity, sufficient to supply baseload power to over 65 million homes if developed at scale. Advancements in horizontal drilling and multi-stage fracturing, borrowed from , promise to expand accessible volumes, potentially enabling 20-fold growth in U.S. geothermal capacity by 2050 through integration with existing power infrastructure.

Closed-Loop Systems

Closed-loop geothermal systems circulate a through sealed pipe networks drilled into hot dry rock, extracting via conduction across pipe walls without requiring natural permeability, subsurface fluid reservoirs, or hydraulic fracturing. These systems differ from conventional hydrothermal setups, which rely on existing hot or reservoirs, and enhanced geothermal systems (EGS), which inject into fractured rock to create artificial permeability for convective . In closed-loop designs, the fluid—typically , a water-glycol , or supercritical media—is pumped through configurations such as U-shaped vertical wells, tubing, or multilateral horizontal laterals, heated subsurface, then returned to the surface to drive turbines or engines for electricity generation. Key configurations include single-well vertical systems with downhole heat exchangers, which minimize drilling but limit output due to constrained surface area, and multi-well arrays like Eavor Technologies' Eavor-Loop™, connecting vertical injection and production wells via multiple horizontal branches to form a subsurface , enhancing contact with hot rock at depths of 3–5 km where temperatures exceed 150–200°C. Heat transfer occurs primarily through , with efficiencies typically lower than convective open systems—yielding thermal conductivities around 2–3 W/m·K for rock-pipe interfaces—but offering steady baseload output independent of site . Global resource potential for closed-loop systems is estimated at up to 9 terawatts electric (TWe), sufficient to meet 70% of current worldwide demand if fully developed, due to their applicability in diverse locations beyond tectonic hotspots. Advantages of closed-loop systems include reduced environmental risks, such as negligible from the absence of high-pressure fracturing, no net water consumption or production (addressing issues in arid regions), and avoidance of formation clogging or scaling since the subsurface remains sealed. They enable deployment in geologically stable areas lacking natural reservoirs, potentially lowering exploration risks and permitting barriers compared to EGS. However, challenges persist: conductive heat extraction demands extensive pipe lengths or for sufficient surface area, resulting in lower power densities (often 5–10 MW per well versus 20+ MW in hydrothermal plants) and requiring deeper to access viable temperatures, which elevates estimated at $5–10 million per MW installed. Long-term thermal decline in surrounding rock can reduce output by 1–2% annually without mitigation, though modeling suggests stable performance over decades with optimized well spacing. Commercial development accelerated in the 2020s, with pilot projects demonstrating feasibility. Eavor Technologies completed a demonstration Eavor-Loop in , , , in 2019, validating closed-loop heat extraction at 2–3 MW thermal scale, followed by a 64 MW expansion and commercial deployment in Geretsried, , targeting first power output in the first half of 2025 using horizontal techniques adapted from oil and gas. GreenFire Energy's GreenLoop system, a single-well closed-loop retrofittable to existing wells, tested in 2022 at field in , achieving heat extraction rates suitable for 1–5 MW per unit by deploying expandable heat exchangers downhole. XGS Energy reported successful field tests of its closed-loop reservoir in 2025, partnering with to develop a power plant in , leveraging insulated coaxial wells for improved . These efforts, supported by U.S. Department of Defense funding and private investment exceeding $500 million across firms by 2024, indicate closed-loop systems could scale to gigawatt capacities by 2030, though economic viability hinges on cost reductions below $5 million per well.

Applications

Electricity Generation

Geothermal electricity generation harnesses heat from subsurface reservoirs of hot water or steam to produce power through steam turbines connected to generators. Wells drilled into geothermal fields extract fluids at temperatures typically ranging from 150°C to over 350°C, which are then used to create steam that drives turbines, generating in a manner analogous to conventional steam plants but without fuel combustion. This process operates as baseload power with capacity factors often exceeding 70%, providing continuous output independent of weather conditions. Three primary plant types dominate geothermal electricity production: dry steam, flash steam, and . Dry steam plants, the oldest and simplest, pipe high-temperature steam (above 235°C) directly from the reservoir to turbines, as exemplified by facilities at in , the world's largest complex with over 700 MW capacity across 22 units. Flash steam plants, comprising about 70% of global installations, pump high-pressure hot water (above 180°C) to the surface, where it "flashes" into steam in low-pressure separators to spin turbines; separated water may be flashed again in double-flash configurations for higher efficiency. plants suit lower-temperature resources (107–182°C) by passing geothermal fluid through a to vaporize a secondary with a lower , such as , which drives a without direct contact, minimizing scaling and . As of the end of , global geothermal installed capacity reached approximately 16.9 GW, concentrated in 32 countries with modest annual growth of 3-4% over the prior decade, accounting for less than 0.4% of worldwide production. The leads with over 3.7 GW, primarily from and other fields, followed by (2.3 GW), the (1.9 GW), (1.7 GW), and (1.0 GW). Other notable facilities include the 1.3 GW Olkaria complex in and the 0.8 GW Cerro Prieto in , highlighting geothermal's viability in tectonically active regions. Despite potential for expansion, deployment lags due to high upfront exploration costs and site-specific resource requirements.

Direct Heating and Cooling

Direct geothermal heating involves extracting hot water or steam from subsurface reservoirs to provide for various low- to medium-temperature applications, bypassing . This method leverages naturally occurring geothermal fluids, typically at temperatures between 30°C and 150°C, for efficient via heat exchangers to avoid direct fluid contact with end-use systems. Globally, direct-use geothermal applications excluding shallow heat pumps produced an estimated 205 TWh (737 PJ) of in 2023, marking a roughly one-third increase from the prior year, with space heating accounting for a significant portion. District heating systems represent a primary application, where geothermal heat supplies residential, commercial, and industrial buildings through piped networks. Iceland exemplifies large-scale implementation, with Reykjavik's system utilizing geothermal sources to meet over 90% of the city's heating needs, supported by reservoirs like those at Nesjavellir. In , installed geothermal district heating capacity reached approximately 6 GWth across 29 countries as of 2025, with systems ranging from small-scale (0.5–2 MWth) to larger installations exceeding 50 MWth. Other notable examples include , , and expanding networks in and , where geothermal contributes to urban heating amid growing demand for decarbonized alternatives to fossil fuels. Agricultural and aquaculture uses exploit geothermal heat for controlled environments and processes. Greenhouses heated by geothermal fluids enable year-round crop production in regions with cold climates, such as in the and , where low-cost operation supports high yields of vegetables and flowers. Aquaculture facilities, including fish farms, maintain optimal water temperatures for species like and , with geothermal pond heating comprising about 1% of global direct-use applications. Additional agricultural drying of crops like onions, , and timber utilizes geothermal , reducing energy costs compared to conventional methods. Geothermal energy also supports recreational and therapeutic applications, such as heating pools, spas, and balneological facilities, which dominate direct-use categories in some regions due to accessible hot springs. In the United States, direct geothermal utilization includes spa heating and , with historical expansions since the demonstrating reliability for non-electricity needs. , including and pulp bleaching, further apply geothermal heat where temperatures align, enhancing efficiency over boiler-based systems. For cooling, geothermal systems primarily employ ground-source heat pumps (GSHPs), which circulate fluid through shallow ground loops (typically 1–100 meters deep) to exploit the earth's stable subsurface temperatures of 4.5–21°C for heat rejection during summer operation. These systems achieve coefficients of performance (COP) of 3–6, meaning they deliver 300–600% relative to input , far surpassing air-source alternatives, as the ground acts as a consistent without ambient air fluctuations. In heating mode, GSHPs extract stored solar and geothermal heat from the ground, while in cooling, they reverse the cycle to dump building heat underground. GSHPs constitute the largest share of geothermal direct-use capacity worldwide, often exceeding 70% in utilization breakdowns, with applications in residential, commercial, and institutional buildings for both heating and cooling. In the U.S., they offer up to 70% energy savings over conventional systems, supported by their longevity (loops last 50+ years, indoor components 25 years) and low operational emissions when paired with renewables. Direct geothermal cooling via absorption chillers, using higher-temperature fluids to drive chemical refrigeration, remains niche but viable in hot climates for large facilities, though less common than GSHPs due to site-specific requirements.

Economics

Capital and Operational Costs

Capital costs for geothermal electricity generation are dominated by upfront investments in exploration, drilling, and plant construction, often accounting for 50-70% of total project expenses due to the need for deep wells to access hot fluids or rock. For conventional hydrothermal flash plants, capital expenditures (CAPEX) averaged approximately $4,350 per kW in 2022, with a range of $3,091 to $5,922 per kW depending on site-specific factors like resource temperature and well productivity. Binary cycle plants, suited to lower-temperature resources, incur higher CAPEX of $9,483 to $18,956 per kW, reflecting increased equipment complexity for lower-grade heat. Enhanced geothermal systems (EGS), which involve hydraulic stimulation of impermeable rock, exhibit even greater variability, with near-field EGS at $5,469 to $10,395 per kW and deeper variants up to $22,133 per kW, primarily from elevated drilling and stimulation risks. Drilling alone can comprise 20-35% of CAPEX in hydrothermal projects, escalating with depth and geological uncertainty.
Technology TypeCAPEX Range (2022, USD/kW)Key Cost Drivers
Hydrothermal Flash3,091–5,922Resource temperature, well productivity
Hydrothermal Binary9,483–18,956Lower fluid temperatures, cycle efficiency
Near-Field EGS5,469–10,395Stimulation success, fracture permeability
Deep EGS12,396–22,133Drilling depth, reservoir engineering
Operational and maintenance (O&M) costs for geothermal plants remain low relative to CAPEX, benefiting from the absence of fuel purchases and high reliability with capacity factors often exceeding 90%. Fixed O&M averages around $110 per kW per year globally, covering wellfield monitoring, brine reinjection, and turbine upkeep. Variable O&M is minimal, typically 1-3 mills per kWh ($0.001–0.003/kWh), associated with scaling, corrosion mitigation, and minor downtime for overhauls. These costs can rise with induced scaling from mineral precipitation or seismicity monitoring in EGS, but reinjection practices generally sustain long-term output with annual O&M representing 1-2% of initial CAPEX. Projections indicate modest reductions in both CAPEX and fixed O&M through 2035 via improved drilling technologies and scaled deployments, though site-specific geology limits broader cost convergence with intermittent renewables.

Levelized Cost of Energy

The levelized cost of energy (LCOE) for geothermal represents the average net present cost of electricity production over a plant's lifetime, incorporating capital expenditures, operations and maintenance, fuel (negligible for geothermal), and financing costs, divided by total output. For conventional hydrothermal geothermal plants, recent estimates place unsubsidized LCOE in the range of $60–$110 per megawatt-hour (MWh), varying by resource quality, location, and maturity. Lazard's Levelized Cost of Energy+ Version 18.0 (June 2025) reports $66–$109/MWh for geothermal, reflecting high upfront and costs offset by long plant lifespans (often 40–80 years) and capacity factors exceeding 80%. Global data from the (IRENA) indicate a weighted-average LCOE of USD 0.060/kWh for newly commissioned geothermal projects in 2024, down 16% from USD 0.071/kWh in 2023, driven by improved drilling efficiencies and economies in high-resource regions like and . Regional variations are stark: LCOE as low as USD 0.033/kWh in Turkey's established fields contrasts with higher values in exploratory sites, where drilling success rates below 50% elevate risks and costs. For geothermal systems (EGS), first-of-a-kind deployments yield LCOE around $200/MWh due to advanced stimulation needs, though projections suggest declines to $50–$100/MWh with scaling and oil-and-gas technology transfers. Geothermal's LCOE competitiveness stems from its baseload reliability, with costs lower than new-build ($70–$150/MWh) or nuclear ($140–$220/MWh) per , and more stable than variable renewables when paired with storage. However, site-specific limits deployment; U.S. (EIA) projections in the Annual Energy Outlook 2025 align geothermal LCOE near 8.5 cents/kWh for viable resources, but emphasize risks inflating effective costs by 20–50% in uncertain areas. Incentives like the U.S. Inflation Reduction Act's production tax credits can reduce effective LCOE by 30–40%, though unsubsidized analyses reveal geothermal's intrinsic advantages in dispatchability over intermittent sources.

Incentives and Market Factors

Government incentives for geothermal energy primarily consist of tax credits and subsidies aimed at offsetting high upfront exploration and development costs. In the United States, the of 2022 extended the Investment Tax Credit (ITC) at 30% and the Production Tax Credit (PTC) at $0.0275 per kWh (adjusted for 2023 values) for geothermal facilities beginning construction before January 1, 2035, with provisions allowing transferability of credits to third parties for monetization. For geothermal heat pumps, both residential and commercial installations qualify for a 30% federal through 2032, covering equipment and installation costs without a cap for qualifying projects meeting requirements. These measures have been preserved amid subsequent policy adjustments, including under the 2025 "One Big Beautiful Bill" Act, which maintained geothermal eligibility despite phasing out credits for other renewables. Internationally, policy support varies but increasingly emphasizes geothermal for baseload renewable capacity. The has designated geothermal as a priority for enhancing and meeting targets, with member states like and leveraging feed-in tariffs and grants to sustain over 1 GW of installed capacity as of 2024. In developing regions, such as and , international financing from bodies like the World Bank supports projects through concessional loans and risk-sharing mechanisms, addressing exploration uncertainties in high-potential volcanic areas. The recommends integrating geothermal into national energy plans via heat demand mapping and subsidies to accelerate adoption beyond . Market factors driving geothermal deployment include rising private investments in enhanced technologies and its dispatchable nature amid variable renewables growth. Global investment in geothermal reached over $700 million since 2020, with 2024 marking a peak of 25 equity deals totaling $623 million, largely targeting next-generation enhanced geothermal systems (EGS) for broader geographic applicability. The market is projected to expand from $9.81 billion in 2024 to $13.56 billion by 2030 at a 5.3% CAGR, fueled by for firm, low-emission power in centers and industrial applications, though from cheaper solar and limits penetration without incentives. In the U.S., planned additions of 1.2 GW by late 2025 reflect policy-enabled drilling efficiencies borrowed from oil and gas sectors, positioning geothermal as a competitive baseload option despite historical risks. Barriers persist, including long permitting timelines and resource-specific viability, which incentives mitigate by improving project bankability and attracting from tech firms seeking reliable decarbonization.

Development Challenges

Exploration Risks

Exploration in geothermal energy development primarily involves geophysical surveys—such as seismic reflection, , and measurements—followed by slim-hole or full-sized test to confirm subsurface characteristics like , permeability, and flow rates. These activities are fraught with geological uncertainty, as subsurface heterogeneity often leads to discrepancies between surface predictions and actual conditions, resulting in a high for locating commercially viable resources. Financial risks dominate due to the substantial upfront costs of exploratory , with individual wells typically ranging from $5 million to $10 million for depths of 2-4 kilometers, representing 20-30% of total project capital in many cases. Global analyses indicate exploratory well success rates—defined as achieving sufficient production for further development—average 25-60%, varying by region and phase; for instance, initial wildcat wells in exhibit only a 25% success rate, while phased projects may reach 60% in early exploration. Technical risks include mischaracterization of extent or , often stemming from limited data resolution in pre-drill models, which can necessitate additional wells and escalate costs by millions per project. In volcanic or sedimentary basins, unexpected encounters with s, faults, or low-permeability zones further complicate outcomes, as seen in Swiss geothermal efforts where hydrocarbon presence has heightened drilling hazards. These factors contribute to prolonged timelines, with phases lasting 2-5 years, deterring without de-risking instruments like government-backed or shared-cost programs.

Technical and Scaling Issues

Geothermal energy extraction faces significant technical challenges in due to high subsurface temperatures and pressures, which accelerate equipment wear and complicate operations. In high-temperature environments exceeding 200°C, drilling fluids degrade thermally, leading to reduced and increased loss into formations, known as lost circulation, which accounts for substantial non-productive time and costs in geothermal wells. Additionally, measurement-while-drilling (MWD) tools often fail prematurely from heat exposure, as reported in Japanese geothermal projects where insufficient heat-resistant components cause damage at depths beyond 3 km. Casing integrity is further compromised by thermal cycling, resulting in collapse or bonding failures that hinder long-term well stability. Mineral scaling and represent persistent operational hurdles in geothermal systems, arising from the chemistry of produced fluids supersaturated with silica, carbonates, and sulfides upon and drops. Scale deposition clogs pipes, reduces efficiency by up to 50% in severe cases, and impairs injectivity in reservoirs, necessitating frequent chemical treatments or mechanical cleaning. from acidic or saline brines erodes well casings and surface equipment, with rates accelerated at temperatures above 150°C, demanding specialized alloys like or corrosion-resistant cements. These issues are exacerbated in scaling production, where increased flow rates promote rapid , limiting plant uptime to as low as 80% without mitigation. Scaling geothermal capacity beyond naturally productive hydrothermal reservoirs requires advanced , particularly through enhanced geothermal systems (EGS), which involve hydraulic of hot dry rock to create artificial permeability. However, achieving sustainable circulation loops remains technically demanding, as fracturing often results in uneven permeability distribution, leading to preferential flow paths and thermal short-circuiting that diminish extraction over time. Pilot EGS projects, such as those tested by the U.S. Department of Energy since the , have demonstrated heat recovery rates below 10 MW per well due to insufficient fracture connectivity, far short of commercial thresholds. Long-term management demands precise reinjection strategies to maintain , but heterogeneous rock matrices cause uneven recharge, risking premature depletion within 20-30 years without optimized modeling. For superhot rock geothermal targeting temperatures above 400°C at depths of 10-20 km, current technologies face insurmountable limits, with bit life reduced to hours under extreme conditions and no viable methods for sustained penetration beyond 5-7 km without breakthroughs in plasma or , which remain experimental as of 2023. These constraints confine scalable deployment to regions with pre-existing favorable , such as rift zones, underscoring the need for advances in high-temperature electronics and fracture proppants to enable broader adoption.

Induced Seismicity and Mitigation

Induced seismicity in geothermal energy projects arises primarily from the injection of fluids into subsurface reservoirs, which increases pore pressure along pre-existing faults and reduces effective normal stress, facilitating slip and earthquake generation. This phenomenon is more pronounced in enhanced geothermal systems (EGS), where high-pressure stimulation creates artificial fractures in low-permeability rock, compared to conventional hydrothermal fields that rely on natural permeability. While the majority of events are microseismic (magnitudes below 2.0) and imperceptible, larger events can occur, posing risks to and public , particularly in populated areas. A prominent example is the EGS project in , where stimulation from December 2006 to January 2007 induced over 10,000 microseismic events, culminating in a magnitude 3.4 on December 8, 2009, eight days after injection ceased. The event caused structural damage estimated at 9 million Swiss francs and led to the project's suspension and eventual abandonment due to concerns. Similarly, the EGS site in triggered a magnitude 5.4–5.5 on November 15, 2017, following hydraulic stimulations that ended 59 days prior; this was the second-largest quake in modern South Korean history, damaging hundreds of buildings and injuring dozens. Investigations confirmed the causal link through stress transfer from injections activating a previously unknown fault. Mitigation strategies emphasize proactive risk management through site characterization, real-time monitoring, and adaptive operational controls. Pre-injection assessments involve geophysical surveys to map faults and stress fields, avoiding sites with high seismic potential. During operations, dense seismometer networks enable near-real-time detection, often integrated with "traffic light" protocols that classify events by magnitude and proximity: green for continued injection, yellow for reduced rates or pauses, and red for immediate shutdown. For instance, a 6.1-km-deep stimulation in St. Gallen, Switzerland, in 2018 successfully limited events to below magnitude 1.6 by dynamically adjusting injection based on seismic feedback. Additional measures include hydraulic modeling to predict pressure buildup and post-event analyses to refine models, though challenges persist in forecasting maximum magnitudes due to reservoir heterogeneity. Regulatory frameworks, such as those from the U.S. Department of Energy, mandate these protocols to balance energy development with hazard minimization.

Sustainability

Resource Depletion Risks

Geothermal reservoirs, while drawing from the Earth's theoretically inexhaustible internal heat, exhibit finite local capacities that can deplete under excessive extraction, primarily through declines in pressure, temperature, and permeability. Sustained withdrawal of geothermal fluids without balancing recharge reduces the of produced or hot water, leading to output declines that can render fields uneconomic over decades. Empirical monitoring, such as , detects this via reductions in compressional (Vp) and shear (Vs) wave velocities, signaling pore fluid loss and increased rock in exploited zones. The Geysers field in California exemplifies these risks: peak steam production and electricity generation occurred in 1987 at approximately 2,000 MW gross, followed by a reservoir pressure drop of over 1,000 psi due to unreplaced fluid extraction, halving output to around 900 MW by the early 2000s. Without early reinjection, net capacity projections modeled declines to 475 MW, underscoring how vapor-dominated systems are particularly vulnerable to phase changes from liquid to vapor, exacerbating subsidence and permeability loss. Long-term analyses from 2011 forecasted a further drop to 700 MW over two decades under continued operation, based on historical production data and reservoir modeling. Other fields, such as those in vapor-dominated settings globally, show similar patterns: extraction rates exceeding 5-10% of mass annually can induce cooling by 1-2°C per year, per thermodynamic models, though liquid-dominated systems prove more resilient due to higher recharge potential. Resource assessments classify geothermal as semi-renewable, with depletion risks heightened in low-permeability formations where natural fails to sustain , potentially limiting field lifespans to 30-50 years absent advanced . These dynamics necessitate site-specific modeling to avoid irreversible drawdown, as evidenced by post-peak recovery challenges in overexploited basins.

Reinjection Practices

Reinjection entails returning cooled geothermal fluids, including separated and condensate, from production wells into the subsurface to sustain long-term resource viability. This practice replenishes extracted fluid volumes, thereby preserving hydraulic pressure and preventing compaction or that could impair permeability and heat extraction efficiency. In liquid-dominated systems, reinjection primarily targets disposal while maintaining thermal drawdown limits, whereas vapor-dominated fields emphasize condensate return to counteract depletion. Effective reinjection strategies distinguish between infield injection, which recycles fluids near production zones to enhance sweep efficiency, and outfield or peripheral injection, which targets distant aquifers to minimize thermal interference with active wells. Deep reinjection, often exceeding 2-3 km, facilitates heat recovery from deeper formations, supporting enhanced geothermal systems (EGS) by fracturing impermeable rocks and creating permeable pathways for sustained circulation. Monitoring reservoir parameters such as buildup, profiles, and tracer tests ensures optimal placement and rates, typically matching or exceeding extraction volumes to achieve quasi-steady-state conditions. A prominent example is the Geysers field in California, where steam production peaked at approximately 2,000 MW in the late 1980s but declined due to over-extraction-induced pressure drawdown; starting in the early 1990s, reinjection of treated municipal wastewater—reaching volumes of over 10 million gallons per day by the 2000s—restored pressure and stabilized output at around 700-900 MW, demonstrating reinjection's role in extending field life by decades. Globally, reinjection has become standard in fields like those in Iceland and New Zealand, where it mitigates depletion risks by sustaining recharge rates equivalent to natural precipitation infiltration, though site-specific hydrogeology dictates customized approaches to avoid localized cooling or mineral scaling.

Environmental Impacts

Greenhouse Gas Emissions

Geothermal power plants emit greenhouse gases primarily through the release of naturally occurring (CO₂) and (CH₄) dissolved in geothermal fluids extracted from reservoirs, rather than from processes used in plants. These direct emissions vary significantly by site , with some reservoirs containing elevated CO₂ levels—such as those in Italy's Larderello field or New Zealand's facilities—potentially exceeding 500 grams of CO₂ per (g CO₂/kWh) in unmitigated cases, though global averages remain far lower. Reinjection of spent fluids back into the reservoir can reduce these emissions by limiting atmospheric release, a practice increasingly standard in modern plants to maintain pressure and minimize losses. Lifecycle assessments, which include emissions from plant construction, operation, decommissioning, and upstream activities, estimate geothermal's full footprint at 6–50 g CO₂-equivalent per (g CO₂eq/kWh), with medians around 32–45 g CO₂eq/kWh across flash, binary, and enhanced geothermal systems. This places geothermal emissions comparable to or lower than many solar and technologies but orders of magnitude below (approximately 820–1,000 g CO₂eq/kWh) and (490 g CO₂eq/kWh). Factors influencing lifecycle totals include energy intensity and material use for , though these contribute minimally relative to operational fluid emissions.
Energy SourceLifecycle GHG Emissions (g CO₂eq/kWh)
Geothermal6–50
820–1,000
490
Onshore Wind11
Solar PV48
Despite site-specific variability, geothermal's low emissions profile supports its role in decarbonizing , provided high-emission reservoirs employ capture or reinjection technologies to align with global goals. Reports from bodies like the IPCC emphasize that even upper-bound estimates do not compromise geothermal's classification as a low-carbon source when aggregated globally.

Water Usage and Land Effects

Geothermal power plants exhibit relatively low consumption compared to and nuclear facilities, primarily due to the use of produced geothermal fluids in closed-loop systems and reinjection practices. Conventional hydrothermal plants, such as flash steam facilities, consume approximately 1,000 gallons per megawatt-hour (gal/MWh) of generated, with much of this loss attributed to evaporation in cooling towers or minor seepage during operations. plants, which use lower-temperature resources, often employ air-cooled systems in water-scarce regions, further reducing freshwater withdrawal to near zero while relying on non-potable geothermal that is separated and reinjected underground. Enhanced geothermal systems (EGS) may require higher initial water volumes for reservoir stimulation—up to 4,200 gal/MWh in some scenarios—but operational consumption aligns closer to hydrothermal levels with effective reinjection, which recycles over 90% of extracted fluids to maintain reservoir pressure and minimize net depletion. Reinjection, mandated in many jurisdictions to prevent resource drawdown, involves pumping cooled geothermal fluids back into the formation, which sustains long-term yield but can introduce challenges like scaling or if water chemistry is not managed through pretreatment. In arid locales, such as parts of the , this practice limits surface impacts but has occasionally led to localized from trace minerals or gases if injection zones fail, though monitoring and regulatory oversight mitigate such risks. Overall, geothermal's water intensity—around 1-2 acre-feet per year per MW capacity—remains far below coal's 20+ acre-feet or nuclear's similar demands, positioning it as water-efficient among baseload technologies. Geothermal facilities occupy a compact land footprint, typically 1-8 acres per megawatt of capacity, encompassing well pads, power blocks, and pipelines, which is substantially less than (up to 19 acres/MW) or solar photovoltaic arrays (5-10 acres/MW). This efficiency stems from subsurface resource extraction, allowing surface land to often remain usable for or post-construction, unlike sprawling solar or installations. In high-output fields like in , cumulative infrastructure spans thousands of acres but generates gigawatt-scale power with minimal incremental expansion needs. Potential land effects include , where excessive fluid extraction without balanced reinjection causes reservoir compaction and surface sinking, as observed in some early operations at Wairakei, , with up to 10 meters of settlement over decades. Modern practices, including comprehensive reinjection since the 1990s, have largely averted such issues in managed fields, with subsidence rates reduced to millimeters per year through pressure monitoring and adaptive injection strategies. Drilling and access roads cause temporary disturbance, but reclamation restores much of the site, and visual impacts are low due to low-profile plants integrated into volcanic terrains. In sensitive ecosystems, localized occurs, but the overall intensity—about 404 square meters per gigawatt-hour—supports geothermal's role in dense energy production with reduced spatial demands.

Biodiversity and Local Opposition

Geothermal energy development can disrupt local habitats through activities, installation, and facility footprints, potentially leading to fragmentation or displacement of in sensitive geothermal areas such as hot springs or that support endemic species. However, empirical peer-reviewed studies on direct impacts remain scarce, with analyses indicating minimal surface disturbance compared to other renewables due to geothermal's compact , typically 1-8 acres per megawatt. In subsurface environments, fluid extraction and reinjection may alter temperatures, reducing microbial by favoring thermophilic species over native assemblages, as observed in controlled geothermal simulations. In regions like , geothermal projects have raised concerns for endangered native birds and , where facility expansion could encroach on unique ecosystems tied to volcanic activity, prompting environmental assessments to evaluate habitat loss for species such as the Hawaiian petrel. strategies, including site avoidance and restoration, have been implemented in some cases, but critics argue that long-term monitoring is insufficient to confirm negligible net effects, given the technology's reliance on geologically active zones often overlapping with high . Local opposition to geothermal projects frequently arises from fears of , , noise, and cultural desecration, particularly in indigenous or rural communities. In Hawaii's Puna district, the Puna Geothermal Venture has faced sustained protests from viewing geothermal extraction as a violation of sacred landscapes associated with Pele, the , leading to litigation and project delays since the 1980s; a prior proposal for the Wao Kele o Puna site was abandoned in the 1990s after years of opposition. Similarly, in , residents opposed a 2023-proposed plant citing excessive noise from cooling towers, potential emissions, and diminished property values, resulting in regulatory scrutiny and public hearings. Nationwide in the United States, at least one geothermal project among 53 utility-scale renewables was delayed or blocked between 2008 and 2021 due to community pushback, often amplified by procedural barriers like disputes or not-in-my-backyard sentiments rather than purely technical risks. In , such as on Indonesia's Flores Island, 2025 protests halted developments over habitat threats to coral reefs and fisheries, highlighting tensions between national decarbonization goals and local ecological dependencies. These oppositions underscore site-specific trade-offs, where perceived risks—substantiated in cases by verifiable incidents like the in linked to geothermal operations—outweigh modeled benefits in public discourse, despite geothermal's generally low operational emissions profile.

Global Production

Installed Capacity and Growth

Global installed geothermal power capacity stood at 15.4 gigawatts (GW) by the end of 2024, primarily for . This figure reflects contributions from over 30 countries, with the majority concentrated in regions of high geothermal potential such as the . Alternative estimates place the total slightly higher at 16.9 GW, accounting for recent project completions and enhanced resource assessments. Historical growth has been gradual, with an average annual increase of about 2-3% over the past decade, lagging behind other renewables like solar and due to high upfront exploration costs and site-specific limitations. From 2020 to 2023, capacity expanded by 905 megawatts (MW), a 5.8% cumulative rise, driven by additions in established markets. In 2024 alone, at least 400 MW of new capacity came online, marking the highest annual addition in recent years and elevating the global total from approximately 14.7 GW at the start of the year. Capacity utilization remains a strength, averaging over 75% globally in 2023, far exceeding intermittent sources and underscoring geothermal's reliability for baseload power. Despite this, deployment has been constrained by regulatory hurdles, financing challenges for risks, and competition from cheaper alternatives, resulting in stalled projects in potential hotspots like and . Projections indicate potential for accelerated growth if enhanced geothermal systems (EGS) mature, but current trends suggest modest expansions to 17-18 GW by 2030 absent policy shifts.

Leading Countries and Projects

The United States leads global geothermal power capacity with 3,937 MW installed as of the end of 2024. The country's primary production occurs in the western states, particularly California's field, the world's largest geothermal complex with a capacity of approximately 1,520 MW across multiple units. Other significant U.S. sites include Nevada's Steamboat Hills and Oregon's Newberry Volcano, contributing to steady output despite challenges like in older fields. Indonesia ranks second with 2,653 MW of installed capacity at the end of 2024, leveraging its position on the for extensive hydrothermal resources. Key projects include the Sarulla complex in , operational since 2016 with 330 MW capacity, and expansions at Wayang Windu and Kamojang fields. The Philippines follows with 1,984 MW, where geothermal supplies about 10% of national electricity, highlighted by the Tiwi and Mak-Ban plants totaling over 700 MW combined. Turkey holds fourth place with 1,734 MW, having rapidly expanded from minimal capacity a decade prior through state-backed developments in western . Notable projects include the Kızıldere field, upgraded to over 200 MW, and Denizli's Germencik plant. maintains around 1,000 MW, with pioneering stations like Wairakei (operational since 1958, 360 MW) and modern additions such as Tauhara, emphasizing technology for lower-temperature resources. Iceland stands out for per-capita leadership, generating over 700 MW to supply about 30% of its and extensive , via plants like Hellisheiði (303 MW) and Nesjavellir. Kenya's Olkaria fields produce around 800 MW, representing over 40% of national power, with Phase VI expansions targeting 140 MW by 2025. These leaders account for the majority of the world's 16,873 MW total geothermal capacity as of late 2024, with ongoing projects in and Kenya poised to drive near-term growth.
CountryInstalled Capacity (MW, end-2024)
3,937
2,653
1,984
1,734
~1,000

Role in Energy Systems

Comparisons to Fossil Fuels

Geothermal energy offers baseload power generation with capacity factors typically between 70% and 95%, surpassing the averages for coal-fired plants (around 50%) and combined-cycle plants (around 55-60%), enabling consistent output without reliance on weather or fuel imports. This stems from the steady extraction of Earth's internal heat, contrasting with fossil fuels' vulnerability to supply disruptions and combustion inefficiencies. Lifecycle greenhouse gas emissions from geothermal plants average 6-122 grams of CO₂-equivalent per kilowatt-hour, far below coal's 820-1,000 g CO₂/kWh and natural gas's 400-500 g CO₂/kWh, due to minimal combustion and reliance on naturally occurring steam or hot water. Geothermal also emits 97-99% fewer sulfur compounds contributing to acid rain compared to fossil fuel plants. The unsubsidized levelized cost of energy (LCOE) for geothermal ranges from $70-120 per megawatt-hour, competitive with new coal ($65-150/MWh) and natural gas ($45-75/MWh for combined cycle), particularly when accounting for fossil fuels' fuel price volatility and potential carbon pricing; geothermal's high upfront drilling costs are offset by negligible fuel expenses and plant lifespans exceeding 30-50 years. In contrast, fossil fuels face escalating extraction costs as reserves deplete, with no equivalent to geothermal's renewable heat replenishment over geological timescales. Geothermal development uses less land per unit of energy than coal mining and ash disposal or extensive gas pipelines, while avoiding fossil fuels' combustion byproducts like particulate matter and nitrogen oxides that cause respiratory illnesses and smog. However, geothermal's geographic limitations—requiring suitable subsurface reservoirs—constrain scalability compared to fossil fuels' broader deployability, though enhanced geothermal systems aim to expand viable sites using oil and gas drilling techniques.

Comparisons to Intermittent Renewables

Geothermal energy provides baseload power with high reliability, operating continuously regardless of conditions, in contrast to solar and , which are intermittent and generate only when or is available. This dispatchability allows geothermal plants to respond to grid demands without reliance on storage, reducing the need for systems that intermittent renewables require to achieve firm capacity. Capacity factors underscore geothermal's superior utilization: U.S. geothermal plants averaged 74% in 2023, compared to 24% for solar photovoltaic and 35% for onshore . Globally, geothermal typically achieves 70-90% capacity factors, enabling it to produce 2-4 times more over time than equivalently rated solar or installations. This consistency minimizes curtailment and grid instability issues prevalent in high-penetration solar and systems, where output variability can exceed 90% daily fluctuations.
TechnologyAverage Capacity Factor (U.S., 2023)Key Limitation
Geothermal74%Resource-specific geography
Solar PV24%Day/night and weather dependence
Onshore Wind35%Wind speed variability
Data from U.S. Energy Information Administration. Levelized cost of energy (LCOE) comparisons favor solar and wind on a standalone basis due to lower upfront capital—solar PV at $24-96/MWh and onshore wind at $24-75/MWh unsubsidized in 2024—but these exclude intermittency costs like storage and transmission upgrades, which can double effective system costs. Geothermal's LCOE ranges $60-120/MWh, reflecting higher drilling expenses, yet its firm dispatchability yields higher net system value, often exceeding intermittent sources by providing premium baseload reliability without subsidies for storage. In integrated grids, geothermal reduces overall variability, complementing solar and wind by filling generation gaps, as evidenced in hybrid models where it stabilizes output and lowers total LCOE. One analysis notes geothermal's relative competitiveness improves through 2026 for reliability procurement, despite raw LCOE metrics. However, a 2023 Berkeley study found geothermal's net value lower in California due to market saturation of cheaper intermittents, though this overlooks long-term grid resilience benefits.

Future Prospects

Technological Innovations

Enhanced geothermal systems (EGS) represent a pivotal innovation, enabling access to geothermal resources in hot dry rock formations lacking natural permeability by injecting under to create artificial networks, thus forming subsurface exchangers. Developed since the 1970s, EGS has advanced through integration of hydraulic fracturing and horizontal drilling techniques borrowed from the oil and gas sector, allowing for multi-stage stimulation and longer well laterals that improve extraction efficiency. In 2023, Fervo Energy demonstrated commercial viability by producing 3.5 megawatts at its Project Red site in using these methods, with plans for a 400-megawatt Cape Station project operational by 2028. These systems could potentially supply up to 90 gigawatts in the United States by 2050, expanding geothermal from conventional hydrothermal sites to broader geological contexts. Advanced drilling technologies, including precision and durable high-temperature materials, have reduced costs and risks associated with reaching depths of 5-10 kilometers where temperatures exceed 200°C. The National Renewable Energy Laboratory (NREL) highlights the application of polycrystalline diamond compact bits and managed pressure , which enhance penetration rates in by up to 50% compared to traditional rotary methods. Fervo Energy's use of fiber-optic enabled real-time monitoring during has achieved unprecedented accuracy in targeting zones, minimizing dry wells and optimizing . Such innovations address the historical barrier of high upfront expenses, which constitute 30-50% of costs, potentially lowering levelized costs to $45-85 per megawatt-hour for EGS. Supercritical geothermal systems target reservoirs above 374°C where water enters a supercritical state, offering power densities up to ten times higher than conventional geothermal due to enhanced properties. The Iceland Deep Drilling Project (IDDP) in 2017 inadvertently accessed supercritical conditions at 2.5 kilometers, yielding fluid temperatures of 427°C and demonstrating potential for 10-megawatt output from a single well, though equipment failures highlighted material durability challenges. In September 2025, selected a site for the world's first dedicated supercritical geothermal pilot, involving well designs to depths of 5 kilometers with advanced casing to withstand corrosive, high-pressure fluids. Progress in plasma or millimeter-wave drilling, as pursued by companies like Quaise Energy, aims to vaporize rock for ultra-deep access, but remains in early testing phases with commercialization projected beyond 2030. Future directions for mid-deep geothermal energy emphasize scale-up via optimized well clusters and borehole layouts using numerical simulations, alongside integration with shallow geothermal systems, photovoltaics, and air-source heat pumps to achieve multi-energy complementarity and enhance system stability. Innovations include efficient heat exchange materials such as smart responsive and nanomaterials for anti-clogging, intelligent monitoring with IoT sensors for real-time parameters, and further EGS advancements; digital tools incorporating AI and big data facilitate dynamic prediction of reservoir behavior and process optimization. Binary cycle power plants have seen incremental improvements in working fluids and heat exchanger designs to utilize lower-temperature resources (107-182°C), achieving efficiencies of 10-15% through optimizations. Recent advancements include variants, which use ammonia-water mixtures for better temperature matching, boosting output by 20-30% over standard systems in retrofitted plants. However, these enhancements primarily refine existing infrastructure rather than enabling new resource access, with widespread adoption limited by the dominance of flash steam in high-enthalpy fields.

Expansion Potential and Barriers

Geothermal energy holds substantial expansion potential due to its vast global resource base, particularly through enhanced geothermal systems (EGS) that access hot dry rock formations beyond conventional hydrothermal reservoirs. The International Energy Agency estimates that geothermal could supply up to 15% of global electricity demand growth through 2050, equivalent to approximately 800 gigawatts (GW) of cost-effective deployment, leveraging deeper resources up to 5 kilometers where technical potential expands significantly. Currently contributing about 1% of global electricity, next-generation technologies like EGS could unlock resources in diverse geographies, with U.S. projections reaching 90-100 GW by 2050 under favorable conditions. Mid-deep geothermal expansion includes applications in building heating and cooling, agriculture such as greenhouse heating, and tourism via spa developments. Investment momentum supports this growth, with North American geothermal funding reaching $1.7 billion in the first quarter of 2025 alone—85% of the prior year's total—driven by breakthroughs in EGS and policy incentives. Globally, over 15 GW of projects are in development as of 2025, nearly doubling prior pipelines, indicating scalable pathways for baseload, low-emission power that outperforms intermittent renewables in reliability. EGS mitigates location constraints by engineering artificial reservoirs through hydraulic fracturing, potentially transforming geothermal into a widespread dispatchable resource comparable to fossil fuels in consistency but with near-zero operational emissions. Policy enhancements, such as incentives, unified mineral rights management, and energy management contracts, are proposed to facilitate deployment. Despite this promise, expansion faces significant barriers, primarily high upfront capital costs averaging $3,000–$6,000 per kilowatt installed, exceeding those of ($1,200–$1,800/kW) and solar ($800–$1,200/kW) due to expensive exploratory and well completion. Exploration risks remain elevated, with dry or unproductive wells leading to financial losses, compounded by lengthy permitting processes—often 5–7 years on —that deter investment amid competition from subsidized intermittent renewables with lower initial outlays. Technical challenges include drilling limitations in hard rock formations and risks of induced seismicity from EGS fracturing, which necessitate advanced monitoring and mitigation to avoid public opposition or regulatory halts. Non-technical hurdles, such as fragmented policy frameworks lacking streamlined approvals and transmission access, further impede deployment, as geothermal's high capacity factor (70–90%) undervalued in levelized cost metrics favoring cheaper but variable alternatives. Addressing these via technological advances in drilling efficiency and regulatory reforms could accelerate scaling, though systemic preferences for solar and wind in current energy transitions pose ongoing market barriers.

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