Decarbonization is not the only force driving Europe’s geothermal market. Following Russia’s invasion of Ukraine, the European Union (EU) rapidly shifted its energy procurement structure away from pipeline gas toward LNG and more diversified suppliers. Although the risk of supply disruptions during a crisis has declined, European gas prices are now more exposed to global LNG supply and demand, maritime transport constraints, and geopolitical developments. When gas-fired generation is the marginal source of power, that volatility feeds through to electricity prices.

Wholesale electricity prices have fallen from their 2022 peak but remain above pre-crisis levels. Using its broad measure, the European Commission’s “Energy Prices and Costs in Europe” puts the EU’s energy import bill at €604 billion in 2022 and €427 billion in 2024. By contrast, Eurostat’s narrower measure—covering extra-EU trade in oil, natural gas, and solid fuels—records imports of €375.9 billion in 2024. The two figures are not directly comparable because their product coverage and methodologies differ. Both, however, underscore the continuing scale of payments flowing out of the EU for imported energy. Industrial gas and electricity prices can be several times those of major competitors, eroding the competitiveness of energy-intensive industries. Geothermal energy is therefore being reassessed as both a price-stabilization tool and an energy-security asset: it is indigenous, fuel-free, weather-independent, and capable of supplying both electricity and heat.

Power Is Decarbonizing, but the Broader Energy System Remains Fossil-Fuel Dominated

Europe’s energy mix must be understood by distinguishing primary energy and final consumption from electricity generation. Fossil fuels—oil, natural gas, and coal—still account for roughly two-thirds of the EU’s total energy available. The power sector, however, is further ahead: in 2025, renewables supplied 47.2% of EU electricity, nuclear power 23.2%, and fossil fuels 29.6%. Together, renewables and nuclear provided about 70% of generation from low-carbon sources.

By technology, wind and solar supplied 30% of EU electricity in 2025, surpassing fossil fuels as a whole, at 29%, for the first time. Nuclear accounted for 23%, gas-fired generation about 17%, and coal 9.2%. Wind remained the largest renewable source, followed by hydropower and solar. According to the European Commission’s electricity market report, solar generation reached 275 TWh in 2025, an increase of 18% year on year.

Yet decarbonizing electricity does not mean that the entire energy system has been transformed. Oil and gas remain embedded in transport, space heating, and industrial furnaces. In 2025, renewables accounted for 26.2% of gross final energy consumption, 49.9% of electricity consumption, and 27.3% of heating and cooling. The next policy challenge is therefore twofold: extend low-carbon electricity into transport, buildings, and industry through electrification, while replacing high-temperature heat that is difficult to electrify with geothermal energy, bioenergy, hydrogen, and other alternatives.

Price Risk Persists Even as Dependence on Russia Declines

The EU has sharply reduced its dependence on Russian gas. According to the European Commission, Russian gas supplied 45% of EU imports in 2021, but only about 12–13% in 2025. Norway and the United States each supplied roughly one-third of 2025 imports—89 bcm and 76 bcm, respectively—while LNG rose to 45% of total imports. The EU intends to end imports of Russian pipeline gas and LNG by November 2027.

Yet “decoupling from Russia” is not synonymous with “cheap energy.” LNG diversifies supply, but it also exposes Europe to competition with Asia for spot cargoes and to shipping constraints. The average EU wholesale gas price was €36/MWh in 2025, 5% higher than a year earlier. Even as gas-fired generation’s share declines, gas plants continue to set prices during tight market conditions, leaving electricity markets exposed to gas-price volatility. European companies need more than a shift from one imported fuel to another; they need a larger base of indigenous energy with predominantly fixed costs.

Heat Is the Main Arena for Geothermal’s Revival

What distinguishes Europe’s geothermal sector is the scale of its heat market, not merely its power generation. At the end of 2025, Europe had 150 geothermal power plants in operation with combined capacity exceeding 3.5 GW, of which only 1.02 GW was located within the EU. By contrast, 434 geothermal district heating and cooling systems, totaling more than 6 GWth, were operating, while over 500 projects representing approximately another 6 GWth were under development. The EU’s installed base of ground-source heat pumps also exceeded 2.5 million units.

The underlying reason is that space heating, hot water, and industrial heat represent a large share of Europe’s final energy demand, making the benefits of replacing natural gas immediate and tangible. Geothermal heat can be supplied directly to district heating networks, greenhouses, food processing facilities, and manufacturing processes without first being converted into electricity. It can also ease winter peaks on the power grid. Consequently, while dependable power for data centers—prominent in the US market—is also relevant, municipal district heating and industrial heat are central to project development in Europe.

EU Policy Shifts from Technology Neutrality to Practical Support for Geothermal Deployment

REPowerEU provides the policy foundation. Its objective is to end reliance on Russian fossil fuels through energy savings, diversified supply, and increased clean-energy production. Layered onto it are the revised Renewable Energy Directive’s targets for heating and cooling, district-heating planning under the revised Energy Efficiency Directive, electricity market reform, and the Affordable Energy Action Plan. The Net-Zero Industry Act designates heat pumps and geothermal energy as strategic net-zero technologies, making them eligible for support for manufacturing investment, faster permitting, and skills development.

Geothermal energy’s policy status became more explicit in 2026. The European Commission’s policy communication of April 22, 2026, “AccelerateEU—Energy Union: Affordable and Secure Energy through Accelerated Action” (COM(2026)370), set out a broad agenda to accelerate indigenous clean energy and electrification, including the rapid deployment of geothermal energy to displace natural gas. The Commission also compiled best practices covering geological data, permitting, finance, risk mitigation, and business models. The policy focus extends well beyond higher subsidy rates. It is to combine open subsurface data, exploration-risk insurance, aggregation of municipal heat demand, long-term offtake, and one-stop permitting so that pre-discovery resource risk becomes investable.

Geothermal energy counts toward REPowerEU’s renewable-energy objectives, but there is no dedicated deployment quota for the technology. The revised Renewable Energy Directive adopted in the wake of REPowerEU is technology-neutral: it requires renewables to reach at least 42.5% of EU gross final energy consumption by 2030, with an aspirational target of 45%. Geothermal power, direct use of geothermal heat, and renewable heat supplied by ground-source heat pumps count toward that share under the applicable statistical rules.

At REPowerEU’s launch, however, immediate measures centered on solar, wind, heat pumps, biomethane, and hydrogen; deep geothermal had no stand-alone target. Its policy position was subsequently strengthened through the revised directive’s heating and cooling targets, district-heating plans, the Net-Zero Industry Act, and the 2026 AccelerateEU initiative and electrification action plan. Geothermal energy is thus included in the overall renewables target, but it was not assigned a technology-specific quantitative target from the outset.

Integrating Three Policy Priorities: Renewable Expansion and Industrial Electrification

The EU is unequivocally committed to expanding renewable energy. Approximately 77 GW of renewable capacity was added in 2024 and another 70 GW in 2025. Solar accounted for 56 GW and wind 13 GW of the 2025 additions, while solar generation rose 18% year on year to 275 TWh. Deployment is rapid, but renewables supplied only 26.2% of gross final energy consumption in 2025, against the legally binding 2030 target of 42.5% and the aspirational target of 45%. Expansion must therefore reach beyond electricity into heating and cooling, transport, and industry.

Three objectives converge in the expansion of renewables. The first is decarbonization: cutting net greenhouse-gas emissions by at least 55% from 1990 levels by 2030. The second is energy security: reducing exposure to imported fossil fuels and geopolitical pressure. The third is industrial development: manufacturing wind turbines, heat pumps, geothermal equipment, batteries, electrolyzers, and grid equipment within Europe to generate investment, employment, and exports. The Net-Zero Industry Act seeks to bring EU manufacturing capacity for strategic net-zero technologies close to at least 40% of annual deployment needs by 2030.

Industrial electrification connects these three goals. The EU envisions an “electro-continent” in which electric furnaces, electric boilers, heat pumps, electric vehicles, data centers, and low-carbon hydrogen are powered by domestic clean electricity. The European Commission estimates that electricity’s share of final energy consumption must roughly double, from about 23% today to around 50% by 2040. Renewables are not merely a source of decarbonized power: they reduce gas imports, improve electricity-price predictability, and underpin an investment environment supportive of European manufacturing.

The Grid Risks Becoming the Missing Link in Renewable Expansion

As renewable capacity expands, transmission and distribution networks increasingly become the constraint. Europe’s grids extend for more than 11 million km, yet about 40% of distribution networks are over 40 years old. Connecting offshore wind, inland wind and solar, and rooftop photovoltaics to demand centers requires simultaneous reinforcement of cross-border interconnectors, domestic transmission backbones, and distribution systems.

The European Commission estimates that cross-border transmission capacity must increase substantially by 2030 and that €584 billion of grid investment will be required over the coming decade. Permitting, cost allocation, shortages of transformers and cables, workforce constraints, and local acceptance nevertheless prolong project timelines. By mid-2026, grid-connection queues had emerged in at least 16 countries, creating a risk that approximately 120 GW of mature renewable projects would not connect on schedule by 2030.

The problem has shifted from a shortage of generating capacity to mismatches in location and time. Prices fall—and output is sometimes curtailed—during solar-heavy daytime hours, while gas plants raise prices in the evening and during periods of low wind. Remedies include anticipatory grid investment, maturity screening for connection applications, batteries, demand response, cross-border trading, and flexible connection agreements. Geothermal energy is not independent of the grid, but stable electricity or heat supplied near demand centers can reduce peak-hour congestion and the need for long-distance transmission investment.

Leadership Varies by End Use

Country/Region	Market Characteristics	Growth Drivers
Türkiye	One of Europe’s largest power-generation markets; three new plants commissioned in 2025	High-temperature resources, private development, power revenues
Italy	The EU’s largest geothermal power producer, with a long operating history	High-temperature resources in Tuscany and established infrastructure
Iceland	Integrated use for power generation and district heating	High-temperature volcanic resources, industrial heat, and grid stability
France	A mature district-heating market centered on the Paris Basin	Municipal heat networks, exploration-risk support, and long-term contracts
Germany	Deep geothermal in the south, nationwide heat transition, and next-generation demonstrations	Replacement of gas heating, municipal heat planning, and a strong industrial base
Netherlands	Expanding from greenhouse heating into urban and industrial uses	Dense heat demand, gas substitution, and drilling expertise
Central and Eastern Europe	Expanding heat use and power generation in sedimentary basins	Coal and gas substitution, EU funding, and district-heating networks

In simple capacity terms, geothermal power generation across Europe, including non-EU countries, is concentrated in Türkiye, Iceland, and Italy. Installed capacity within the EU is only about 1 GW, far below that of wind and solar. The heat market, however, extends across France, Germany, the Netherlands, Poland, and beyond. The future leaders will not necessarily be the countries with the hottest resources, but those that integrate demand density, heat networks, risk insurance, permitting, and municipal procurement capacity.

Next-Generation Geothermal Redraws the Resource Map

Next-generation geothermal falls into three broad categories. Enhanced geothermal systems (EGS) create flow paths in low-permeability rock and circulate water through them. Closed-loop systems seal a working fluid within the wellbore and recover heat by conduction from the surrounding rock. Superhot and supercritical geothermal targets deeper, hotter formations to increase output per well. In Europe, Horizon Europe and other programs have supported drilling, high-temperature materials, subsurface monitoring, CO₂ working fluids, and induced-seismicity management.

The significance of market expansion lies in easing geographical constraints. Ember estimates that the EU has approximately 43 GW of EGS potential developable at below €100/MWh under current conditions, equivalent to around 301 TWh per year, with particularly large potential in Hungary, Poland, Germany, and France. These figures describe resource and cost-model potential, however; actual deployment must also account for drilling capacity, grid access or heat demand, public acceptance, and the cost of capital.

Why Geretsried—and Why Germany?

The Eavor-Loop project being developed by Canada’s Eavor Technologies in Geretsried, Bavaria, is a commercial-scale closed-loop system comprising multilateral horizontal wells drilled into rock at a depth of approximately 4,500 meters, with fluid circulating through sealed piping. At completion, the project is designed to deliver about 8.2 MW of electricity and 64 MW of heat, avoiding roughly 44,000 metric tons of CO₂ equivalent annually. On December 4, 2025, Eavor announced that the first loop had begun supplying electricity to the German grid, marking the start of “partial commercial operations.” This did not signify completion of the entire project or achievement of rated output; district-heat delivery and the construction and performance validation of the remaining loops form part of a phased ramp-up.

Four factors explain why Germany became the host country. First, the drive to end dependence on Russian gas gave the replacement of gas heating substantial political value. Second, municipal heat planning and district-heating networks allow efficient heat sales—not electricity alone—to serve as a core revenue stream. Third, a closed system can redefine resource risk by exploiting hot rock even where conventional exploration wells have failed. Fourth, public finance absorbed much of the first-of-a-kind technology and construction risk, including €91.6 million from the EU Innovation Fund and approximately €45 million in financing from the European Investment Bank.

It would nevertheless be premature to declare success. Grid supply from the first loop has been officially confirmed, but the disclosed status is partial commercial operation—not delivery of the full planned 8.2 MW of electricity and 64 MW of heat. The development encountered drilling delays and technical challenges in forming and circulating through the lateral branches. Eavor itself has cited sidetracking and fluid communication between laterals among the lessons learned. The decisive metrics for Geretsried will be the extent to which the remaining facilities improve drilling time, well connectivity, circulation performance, long-term thermal output, capacity factor, and total project cost.

Market Outlook: Heat Will Reach Scale Before Power Generation

At the national level, transition speeds and power mixes vary widely. France anchors its low-carbon electricity system in nuclear power. Germany combines wind and solar with gas and cross-border trading following its nuclear exit. The Nordic countries are strong in hydropower, wind, nuclear, and biomass. The Iberian Peninsula combines rapid solar and wind growth with weak interconnection to the rest of Europe. Central and Eastern Europe must reduce reliance on coal while managing the effects on prices and employment. These differences produce distinct national support policies and geothermal applications even under common EU targets.

For electrification to enhance industrial competitiveness, electricity prices must be stable enough to support long-term contracts. Even with a high renewable share, grid congestion and gas-fired marginal pricing can prevent consumers from capturing the full benefits of lower-cost generation. Increasing “clean flexibility” by combining continuous geothermal output with batteries, demand response, nuclear, and hydropower will determine effective decarbonization—not installed capacity alone.

In the short to medium term, growth will be led by district heating, industrial heat, greenhouse agriculture, and ground-source heat pumps. Where existing heat networks and creditworthy customers are available, projects can be developed even with lower-temperature resources, and the hedging value against gas prices can be embedded in contracts. Power generation will gradually expand beyond established resources in Italy, Türkiye, and Iceland to include binary plants, EGS, and closed-loop systems in Germany and Central and Eastern Europe.

The pace of adoption will depend on who bears the cost of unsuccessful exploration, whether drilling rigs and skilled crews can be kept continuously employed, and whether long-term heat buyers can be secured. Geothermal energy has minimal fuel costs but is highly sensitive to upfront investment and the cost of capital. If EU policy can integrate geological data, insurance, permitting, offtake, and public procurement into a unified project-development framework, a pipeline of more than 500 heat-supply projects could generate the learning effects of serial deployment. Without such integration, promising demonstrations may remain isolated one-offs.

Implications for Japan and Opportunities for Corporate Entry

The first lesson is to design geothermal not simply as a “power plant,” but as a business integrating electricity, heat, minerals, and regional infrastructure. Japan is also exposed to imported-fuel prices, and many of its geothermal resources overlap with national parks and hot-spring areas. Closed-loop systems may make it easier to avoid contact with hot-spring aquifers and could allow developers to target hot rock closer to cities and industrial zones. Geological conditions, long-term thermal output, and economics must nevertheless be verified site by site.

The second lesson is to redirect public support from equipment subsidies toward risk management. Integrating regional geological data, exploration-risk insurance, staged financing, aggregation of municipal heat demand, long-term contracts, and drilling-data sharing would make projects more accessible to private capital. Europe’s district-heating model could also support regional development in Japan through benefit-sharing with hot-spring operators, heat sales to agriculture and food processors, and distributed heat sources for emergencies.

The scope for Japanese companies is substantial. Chubu Electric Power and Kajima Corporation are involved in the Geretsried project, creating an opportunity to connect drilling and operating data from Europe’s first-of-a-kind facility with technical evaluation in Japan.

A pragmatic entry strategy for Japanese companies would be to partner with European developers, municipalities, and drilling contractors rather than assume resource risk alone—beginning with equipment supply and access to operating data, then expanding in stages into joint demonstrations, licensing, engineering, procurement and construction (EPC), and maintenance. Japanese companies are particularly well positioned to differentiate themselves through high-reliability equipment, quality control, long-term maintenance, low-temperature heat recovery, and corrosion-resistant materials. At the same time, they should not assume that closed-loop systems are inherently superior; each project requires scrutiny of thermal output and drilling cost per well, economics after subsidies, and the creditworthiness of heat customers.

Conclusion: European Geothermal Is Becoming an Energy-Security Industry Built Around Heat

Europe’s renewed interest in geothermal energy is about far more than raising the renewable share. It is an industrial-policy response that seeks to use subsurface heat locally and over the long term to address high energy prices, new dependence on LNG markets, weakening industrial competitiveness, the decarbonization of heating, and grid constraints simultaneously. Heat markets will lead in the near term, while next-generation power technologies remain at the stage of determining whether demonstrations can translate into scalable deployment.

Geretsried symbolizes this inflection point. First electricity production is an important step toward technical validation, but commercial proof will depend on the cost and performance of the remaining loops. If Europe develops institutions that absorb failure risk and transfer lessons from one project to the next, geothermal can evolve from a niche power source into heat and power infrastructure that permanently reduces gas imports. For Japanese companies, the opportunity is not simply to sell products into a mature market, but to participate early in the formation of its standards and supply chains.

References

1. European Commission, “Energy Prices and Costs in Europe,” 2025.
2. European Commission, “Market Analysis,” EU Gas and Electricity Market Reports, 2026.
3. European Commission, “REPowerEU,” 2026.
4. European Commission, “Geothermal Energy,” 2026.
5. European Commission, “Net-Zero Industry Act.”
6. European Geothermal Energy Council, “EGEC Geothermal Market Report 2025,” July 16, 2026.
7. Ember, “Hot Stuff: Geothermal Energy in Europe,” February 9, 2026.
8. Eavor Deutschland, “Project Geretsried,” 2026.
9. Eavor Technologies, “Technical Update from Geretsried: What We Built, What We Learned, and What Comes Next,” May 21, 2026.
10. Eurostat, “Renewable Energy and Natural Gas Supply Up in 2025,” June 29, 2026.
11. Eurostat, “Renewable Energy Statistics,” 2026.
12. European Commission, “10th Report on the State of the Energy Union,” November 6, 2025.
13. European Commission, “European Grids” and “EU Action Plan for Grids.”
14. Ember, “European Electricity Review 2026,” January 22, 2026.
15. European Commission, “AccelerateEU—Energy Union: Affordable and Secure Energy through Accelerated Action,” COM(2026)370, April 22, 2026.
16. Eurostat, “Imports of Energy Products to the EU Down in 2024,” March 21, 2025.
17. Eavor Technologies, “Eavor Technologies Achieves First Electricity Production at Geretsried Site,” December 4, 2025.