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Data: Mercator Research Institute on Global Commons and Climate Change (mcc-berlin.net)
Remaining Carbon Budget
The Carbon Clock estimate of the remaining CO2 emissions budget to limit global warming, previously displayed here, is currently under review and will be replaced by a version updated with the 2025 Nationally Determined Contribution (NDC) data, once it becomes available.
Realtime countdown of the remaining carbon dioxide (CO2) emissions budget until global warming reaches a maximum of 1.5°C / 2°C above pre-industrial levels.
The Intergovernmental Panel on Climate Change (IPCC), established in 1988 by the World Meteorological Organization (WMO) and the United Nations Environmental Programme (UNEP), evaluates scientific data related to climate change including estimates of the remaining amount of CO2 that can be released into the atmosphere to limit global warming to a maximum of 1.5°C / 2°C. This data was last updated in summer 2021, and is the basis of the MCC Carbon Clock.
IPCC bases the concept of a carbon budget on a nearly linear relationship between the cumulative emissions and the temperature rise. There is, however, a lag between the concentration of emissions in the atmosphere and their impact on temperature to be taken into account. With the starting point of annual emissions of CO2 from burning fossil fuels, industrial processes and land-use change estimated to be 42.2 gigatonnes per year [or 1,337 tonnes per second], the 1.5°C / 2°C budgets would be expected to be exhausted in approximately 5 and 23 years from August 2024, respectively.
Am I also contributing?
Are we thinking about the emission of greenhouse gasses such as methane and carbon when we do day to day activities like: driving a car, using energy to cook or heating our houses? Probably not. But by doing this we are making our small but constant contribution to the problem of Global Warming. We see from worsening weather disasters around the world that this returns as a boomerang back to our houses and families.
>80%
of all natural disasters were related to climate change
24.29%
USA share of global world cumulative CO₂ emission
100 million
people can be pushed into poverty by 2030 because of climate change impact
The overall trend in global average temperature indicates that warming is occurring in an increasing number of regions. Future Earth warming depends on our greenhouse gas emissions in the coming decades.
At present, approximately 11 billion metric tons of carbon are released into the atmosphere each year. As a result, the level of carbon dioxide in the atmosphere is on the rise every year, as it surpasses the natural capacity for removal.
10
warmest years on historical record have occurred since 2010
>2°F
is the total increase in the Earth's temperature since 1880
>2x
warming rate since 1981
Understanding the ultimate consequences of current trends
Observations from both satellites and the Earth’s surface are indisputable — the planet has warmed rapidly over the past 44 years. As far back as 1850, data from weather stations all over the globe make clear the Earth’s average temperature has been rising.
In recent days, as the Earth has reached its highest average temperatures in recorded history, warmer than any time in the last 125,000 years. Paleoclimatologists, who study the Earth’s climate history, are confident that the current decade is warmer than any period since before the last ice age, about 125,000 years ago.
Clean hydrogen has 3 main uses: energy storage, load balancing, and as feedstock/fuel. Used in all sectors, including steel, chemical, oil refining & heavy transport. Actions to accelerate decarbonization & increase clean hydrogen use include:
Invest in clean hydrogen supply;
Increase hydrogen demand as fuel/feedstock;
Use hydrogen for clean high-temperature heat;
Use hydrogen as low-carbon feedstock for ammonia/fertilizer;
Use hydrogen as clean fuel for heavy transport;
Create policies incentivizing electric power decarbonization;
Utilize hydrogen as a means for storing energy over extended periods;
Improve electrolyser technology & readiness in heavy industry/liquid transport fuels;
Increase use of Methane Pyrolysis & Water Electrolysis for clean hydrogen production;
Increase use of wind and solar in electricity production systems.
Increase the usage of Electricity
Reducing greenhouse gas emissions and achieving carbon neutrality requires widespread renewable energy and a huge increase in vehicles, products, and processes powered by electricity.
Electricity generated from increasingly renewable energy sources is the right way to create a clean energy system. Switching from direct use of fossil fuels to electricity improves air quality by reducing emissions of local pollutants.In order to increase the use of electricity, we can do the following:
Use more electric cars. Compared to traditional combustion engine vehicles, electric cars show a 3-5 times increase in energy efficiency;
Increase your electricity consumption within your household;
Upgrade your home with smart technology. Electrical appliances can be digitized with smart technology;
Use electric heat pump heating. Heat pumps use 4 times less energy than oil or gas boilers;
Electrify industrial processes in order to reduce energy intensity.
As the foremost element in the periodic table, hydrogen holds a unique position in the universe, given its status as the lightest and one of the most ancient and abundant chemical elements.
Never alone
Hydrogen, in its pure form, needs to be extracted since it is usually present in more intricate molecules, such as water or hydrocarbons, on Earth.
Fuel of stars
Hydrogen powers stars through nuclear fusion. This creates energy and all the other chemicals elements which are found on Earth.
Hydrogen is an essential part for manufacturing Ammoniam Nitrate fertilizers. Half of the world's food is grown using hydrogen-based ammonia fertilizer.
Hydrogen fuel cells make electricity from combining hydrogen and oxygen. Power plants are showing increased interest in using hydrogen, and gas turbines can convert from natural gas to hydrogen combustion.
Steelmaking is an industry that is beginning to successfully use hydrogen in two ways to eliminate almost all greenhouse emissions from the steelmaking process. First for Direct Reduced Iron (DRI) replacing coke (from coal) with hydrogen to remove oxygen from iron ore. Second for heat to melt the iron ore into DRI and then into low carbon steel.
Hydrogen is used in production of explosives, fertilizers, and other chemicals; to convert heavier hydrocarbons to lightweight hydrocarbons to produce many value-added chemicals; to hydrogenate organic compounds; and to remove impurities like sulfur, halides, oxygen, metals, and/or nitrogen. It's also in household cleaners like ammonium hydroxide.
Using clean hydrogen makes it possible to reduce emissions while "cracking" heavier petroleum into lightweight hydrocarbons to produce many value-added chemicals.
The World needs MORE hydrogen, to move toward Turquoise and Green hydrogen, and away from Grey hydrogen
Where We are Now
The temperature trend shows the increase can reach 5.9°F (3.28°C) by 2050
High CO2 emissions (7-8 kg CO2 /kg H2)
Only 2% produced with carbon capture (2Mt)
Worldwide 98% Hydrogen production (94 Mt) without carbon capture emits CO2(900 Mt)
62% from methane without carbon capture
Fossil Fuel electricity generation pollutes the environment
Fossil Fuel provides 33-35% efficiency
What We Want to Achieve
By 2030
25% Produced(24Mt) with carbon capture
Stop more climate change limiting warming to 2.4°F (1.3°C) by 2050
Hydrogen for low-carbon industrial heat
100% Hydrogen as a sustainable industrial feedstock
Statistics Source: IEA Global Hydrogen Review 2022
Most Common Hydrogen Sources
These methods now produce 85% of the world's Greenhouse Gas carbon emissions
SMR (Steam Methane Reforming) + WGS (Water Gas Shift)
SMR is a way of producing syngas (Hydrogen and Carbon monoxide) by mixing hydrocarbons (like natural gas) with water. This mixture goes into a special container called a reformer vessel where a high-pressure mixture of steam and methane comes into contact with a nickel catalyst. As a result of the reaction, hydrogen and carbon monoxide are produced.
To make more hydrogen, carbon monoxide from the first reaction is mixed with water through the WGS reaction. As a result, we receive more hydrogen and a gas called carbon dioxide. For each unit of hydrogen produced there are 6 units of carbon dioxide produced and in almost all cases released into the atmosphere. Carbon dioxide is a harmful gas causing climate change.
$863 ($0.86 per kilogram of Hydrogen)
(Electricity = $474 + Methane $383 + Water $6 US EIA May 2024*)
SMR + WGS with Carbon Capture
The SMR method involves combining natural gas with high-temperature steam and a catalyst to generate a blend of hydrogen and carbon monoxide. Then, more water is added to the mixture to make more hydrogen and a gas called carbon dioxide.
For each unit of hydrogen produced there are 6 units of carbon dioxide produced. In a few experimental trials, to help the environment, the carbon dioxide is captured and stored underground using a special technology called CCUS (Carbon Capture, Utilization, and Storage). This leaves almost pure hydrogen.
One of the main problems with carbon capture and storage is that without careful management of storage, the CO2 can flow from these underground reservoirs into the surrounding air and contribute to climate change, or spoil the nearby water supply. Another is the risk of creating earthquake tremors caused by the storage increasing underground pressure, known as human caused seismicity.
$1,253 ($1.25 per kilogram of Hydrogen)
(Electricity $474 + Methane $505 + Water $4 US + CCS $270 EIA May 2024*)
Newer, Clean Hydrogen Sources
Methane Pyrolysis
This technology based on natural gas emits no greenhouse gases as it does not produce CO2. Methane Pyrolysis refers to a method of generating hydrogen by breaking down methane into its basic components, namely hydrogen and solid carbon.
Oxygen is not involved at all within this process (no CO or CO2 is produced). Thus, for the production of hydrogen gas there is no need for an additional of CO or for CO2 separation.
The concept of Green Hydrogen involves generating hydrogen from renewable energy sources by means of electrolysis, a process that splits water into its fundamental constituents, hydrogen and oxygen, using an electric current. This process can be powered by a range of renewable energy sources, such as solar energy, wind power, and hydropower.
The electricity used in the electrolysis process is derived exclusively from renewable sources, ensuring a sustainable and environmentally-friendly production of hydrogen. It generates zero carbon dioxide emissions and, as a result, prevents global warming.
Natural geologic hydrogen refers to hydrogen gas that is naturally present within the Earth's subsurface.
Known as "White" hydrogen, it can be generated through various geological processes. The study of geologic hydrogen and its potential as an energy resource is an active area of research, as it holds promise for renewable energy applications, particularly in the context of hydrogen fuel cells and clean energy production.
It's important to note that the creation of geologic hydrogen is generally a slow and long-term process, occurring over geological timescales. This is because the other methods are human production technology methods and this is creation by a natural phenomena. The availability and abundance of geologic hydrogen can vary significantly depending on the specific geological setting and the interplay of various factors such as rock composition, temperature, pressure, and the presence of suitable reactants.
Here are some of the main sources and mechanisms of geologic hydrogen generation:
01
Serpentinization
Serpentinization is a chemical reaction that occurs when water interacts with certain types of rocks, particularly ultramafic rocks rich in minerals such as olivine and pyroxene. This process results in the formation of serpentine minerals and produces hydrogen gas as a byproduct. Serpentinization typically takes place in environments such as hydrothermal systems, oceanic crust, and certain tectonic settings.
02
Radiolysis
In regions with high concentrations of radioactive elements, such as uranium and thorium, the decay of these elements releases radiation. This radiation can interact with surrounding water or other fluids, splitting the water molecules and generating hydrogen gas through a process called radiolysis. This mechanism is believed to contribute to the production of hydrogen in certain deep geological settings, such as deep groundwater systems and radioactive mineral deposits.
03
Geothermal activity
Geothermal systems, which involve the circulation of hot water or steam through fractured rocks, can generate hydrogen gas as a result of various processes. High-temperature hydrothermal systems can cause the thermal decomposition of hydrocarbons, releasing hydrogen gas. Additionally, the interaction between water and hot rocks in geothermal reservoirs can lead to the production of hydrogen through serpentinization or other geochemical reactions.
04
Abiotic methane cracking
Abiotic methane refers to methane gas that is not directly derived from biological sources, such as microbial activity. In certain geological environments, abiotic methane can be generated through processes like thermal decomposition of organic matter or reactions between carbon dioxide and hydrogen. This methane can subsequently undergo thermal or catalytic cracking, producing hydrogen gas.
Success Stories
Steps Taken by Different Countries to Move Forward to Net Zero Emissions
96
£4 billion
100 MW+
1st place
green hydrogen plants are owned by Australia. It possesses the highest count of establishments globally. Australia is expected to have the lowest costs of green hydrogen production by 2050 due to an abundance of solar and wind resources.
was committed by the UK to hydrogen technology and production facilities by 2030 to cultivate a hydrogen economy and create 9,000 jobs.
green hydrogen production sites are being developed by Canadian company First Hydrogen in Quebec and Manitoba. These plans are being developed in conjunction with Canadian and North American automotive strategies.
in the list of largest hydropower producers in the world belongs to China. It is followed by Brazil, USA and Canada.
By 2047
In 2017
200,000
110 countries
green hydrogen will help India make a quantum leap toward energy independence. The country’s National Hydrogen Mission was launched in 2021.
Japan became the first country to formulate a national hydrogen strategy as part of its ambition to become the world's first "hydrogen society" by deploying this fuel in all sectors.
fuel-cell electric vehicles production by 2025 is the goal stated by South Korea. In 2021, South Korea also approved the Hydrogen Power Economic Development and Safety Control Law, the first in the world to promote hydrogen vehicles, charging stations, and fuel cells.
have legally committed to reach net zero emissions by 2050.
Conclusion
The World needs MORE hydrogen
SMR + WGS
Keep current hydrogen production methods BUT
+
Clean Hydrogen Production Methods
make additional steps to broaden them with cleaner production methods
=
More Hydrogen
And as a result the world will get more vital hydrogen and become one step closer to net zero emission
Сurrent Situation
The market is dominated by grey hydrogen produced from natural gas through a fossil fuel-powered SMR process. Every year, the production of grey hydrogen amounts to approximately 70 to 80 million tons, and it is primarily used in industrial chemistry. More than 80% is used for the synthesis of ammonia and its derivatives (fertilizer for agriculture, 50 perecent of food worldwide) or for oil refining operations. Unfortunately, for every 1 kg of grey hydrogen, almost 6-8 kg of carbon dioxide is emitted into the atmosphere.
More than 95% of the world's hydrogen production is based on fossil fuels with greenhouse gas emissions. Nevertheless, to achieve a more stable future and promote the transition of pure energy, the global goal is to reduce the use of other “colors” of hydrogen and focus on the production of a clean product, such as green or turquoise hydrogen. Reaching the zero carbon footprint will require a gradual transition from grey to green/turquoise hydrogen in the coming years.
It is possible to produce decarbonized hydrogen. An option is to use another feedstock, namely water, and convert it in large electrolyzers into H2 and oxygen (O2), which are returned to the atmosphere. If the electricity used to power the electrolyzers is 100% renewable energy (photovoltaic panels, wind turbines, etc.), then hydrogen becomes green. Currently, it is about 0.1% of the total production of hydrogen, but it is expected that it will increase since the cost of renewable energy continues to fall.
U.S. additions to electric generation capacity from 2000 to 2025. The U.S. Energy Information Administration (EIA) reports that the United States is building power plants at a record pace. As indicated on the chart, nearly all new electric generating capacity either already installed or planned for 2025 is from clean energy sources, while new power plants coming on line 25 years ago, in 2000, were predominantly fueled by natural gas. New wind power plants began to come on line in 2001 and new solar plants, 10 years, later in 2011. Since 2023, the U.S. power industry has built more solar than any other type of power plant. The EIA predicts that clean energy (wind, solar, and battery storage) will deliver 93% of new power-plant capacity in 2025.
Global surface air temperature departures between 1940 and 2024 from the average temperature for the period 1991-2020 (averages below the 11-year average are blue and those above are red). The average in October 2024 was +0.80 degrees Celsius above the reference period average, down from +0.85 degrees Celsius above the reference period average in 2023, which was the warmest October on record.
Technological advances are expanding where geothermal electricity canbe produced - making it a cost-competitive, secure alternative to gas forindustry and other power-intensive users.
About
This analysis examines how advances in geothermal technology are changingthe prospects for geothermal electricity in Europe: its resource potential, costsand deployment trends. The report considers how policy conditions shape thepace of new projects and geothermal’s role in evolving electricity systems.
Cost-competitive geothermal isready to scale across Europe
Around 43 GW of enhanced geothermal capacity in the European Union could be developed at costs below 100 €/MWh today, comparable to coal and gas electricity. The largest potential is concentrated in Hungary, followed by Poland, Germany and France.
While representing only a fraction of Europe’s total geothermal potential, the identified EU-level deployment could deliver around 301 TWh of electricity per year, reflecting geothermal’s high capacity factor. This is equivalent to about 42% of coal- and gas-fired generation in the EU in 2025.
Geothermal power plants are well suited to a changing energy system, offering firm power, battery-like storage capabilities, and the potential to meet rising electricity demand from data centres. Recent US analysis finds that geothermal could cost-effectively supply up to 64% of the United States’ anticipated increase in data-centre electricity demand by the early 2030s.
The EU risks losing its geothermal leadership without stronger political prioritisation. Globally, geothermal could meet up to 15% of growth in electricity demand by 2050. Yet deployment across the EU remains slow and uneven, reflecting the absence of a coherent EU-level policy framework and increasing the risk that future scale-up shifts outside Europe.
Modern geothermal is pushing the energy transition to new depths, opening up clean power resources that were long considered out of reach and too expensive. But today, geothermal electricity can be cheaper than gas. It’s also cleaner and reduces Europe’s reliance on fossil imports. The challenge for Europe is no longer whether the resource exists, but whether technological progress is matched by policies that enable scale and reduce early-stage risk.
Tatiana Mindekova Policy Advisor, Ember
The EU’s Geothermal Action Plan must include clear commitments to liberate Europe’s power sector from costly fossil fuel dependency. The potential to replace 42% of coal and gas generation with geothermal is simply too significant to ignore. Ember’s report highlights the crucial role geothermal plays in delivering affordable energy, security, and competitiveness. With Energy Ministers and the European Parliament calling for concrete action, it is now up to the European Commission to remove the barriers to mass geothermal deployment.
Sanjeev Kumar Policy Director, European Geothermal Energy Council
Europe has far more geothermal potential than is commonly accounted for. Next-generation geothermal strengthens Europe’s heat sector and extends its impact to clean, secure, and reliable electricity across much of the continent. Continued investment in innovation and supportive policy can turn this resource into a major pillar of EU’s clean firm power system.
Jenna Hill Superhot Rock Geothermal Innovation Manager, Clean Air Task Force
Technologies allow geothermal to deliver scalable and clean power across much of Europe. Not just in volcanic regions. Across the European Union, around 43 GW of enhanced geothermal capacity could be developed at costs below 100 €/MWh, placing geothermal firmly within reach as a competitive source of firm, low-carbon electricity. Yet much of this technological progress has gone largely unnoticed and geothermal is still widely viewed as unavailable across much of Europe.
Suitable areas for geothermal energy production continue to expand
Geothermal power generation was long considered viable only in volcanic regions such as Iceland or Indonesia. Conventional geothermal relied on underground rock formations that were both hot and naturally permeable, allowing water already present at depth to circulate and transport heat. These rare conditions confined large-scale deployment to a limited number of regions worldwide. As a result, geothermal energy remained a niche contributor to global electricity generation (99TWh or less than 0,5% in 2024) despite its dispatchable nature and low emissions profile.
During the last decade, progress in geothermal technologies – often referred to as ‘next generation geothermal’ – has removed the need for naturally occurring permeability, meaning the presence of open pores in rock that allow fluids to flow. New approaches can now create or enhance these flow pathways artificially. Combined with more cost-effective deep drilling and advances in power-conversion systems that enable electricity generation at lower temperatures, significantly expanding the range of geological settings suitable for geothermal power generation. As a result, geothermal deployment is expected to accelerate rapidly: by 2030, nearly 1.5 GW of new capacity is expected to come online each year globally, three times the level added in 2024. At the global level, geothermal could meet up to 15% of the growth in electricity demand by 2050.
Next-generation geothermal can already deliver cost-competitive power at scale in Europe
Recent advances in geothermal systems mean that geothermal electricity can now be produced at prices comparable to coal- and gas-fired generation, even outside traditionally high-temperature zones. Focusing on projects with estimated costs below 100 €/MWh – consistent with prices (short-run marginal costs) set by coal- and gas-fired generation in European power markets – and accounting for reservoir behaviour, plant performance and drilling depth, the techno-economic potential for geothermal power in continental Europe reaches around 50 GW.
Under this threshold, Hungary accounts for the largest share, with around 28 GW, followed by Türkiye with almost 6 GW and Poland, Germany, and France with around 4 GW each.
For EU member states alone, this corresponds to around 43 GW of deployable geothermal capacity, capable of generating approximately 301.3 TWh of electricity per year given geothermal’s high capacity factor. This is equivalent to around 42% of all coal- and gas-fired electricity generation in the EU in 2025.
At these cost levels, geothermal power would be competitive with the prices set by coal- and gas-fired generation in European power markets, where short-run marginal cost has been oscillating between 90 and 150 €/MWh in 2025. Not only can geothermal power capacity be developed at low prices, but as a technology with no fuel costs, it brings the additional benefit of being insulated from fuel price volatility and exposure to rising carbon costs, strengthening its role as a stable source of firm, low-carbon electricity over time.
New ways of harnessing and storing energy
The potential of geothermal energy for electricity generation is expanded by changes in the design of geothermal projects. The term next-generation geothermal encompasses several design improvements to geothermal systems. These include accessing underground heat without relying on natural heat pathways, using artificial heat carriers, or creating closed-loop systems. A type of next generation technology most commonly deployed is Enhanced Geothermal System(s) (EGS). EGS can engineer reservoirs in deep, hot rock where natural water or permeability is low or absent, unlocking potential beyond traditional hotspots.
In EGS projects, wells are drilled into hot rock and permeability is created or enhanced to allow a working fluid to circulate and extract heat. The heated fluid is brought to the surface through these artificial cracks to generate electricity. Experience from recent projects shows that seismic risks resulting from such drilling can be managed through monitoring and operational controls.
Geothermal reservoirs can be operated flexibly to absorb surplus wind or solar electricity indirectly, primarily through increased pumping and injection, and later the release of stored thermal and pressure energy to generate additional power. By varying injection and production rates, operators can “charge” the reservoir and later “discharge” it to increase output during high-value periods. Simulations show that heat can be stored for several days with efficiencies comparable to lithium-ion batteries. Because this capability is built into the same infrastructure used for power generation, it adds flexibility at low additional cost.
In addition, geothermal operations can generate value beyond electricity through the recovery of critical minerals from produced brines. Lithium concentrations in geothermal brines typically range in levels that can be commercially viable using new direct lithium extraction techniques. These methods recover up to 95 % of the lithium contained in the brine, compared with roughly 60 % from hard-rock mining, while using far less water and generating almost no carbon emissions.
Falling costs, deeper wells
Geothermal electricity is already cost-competitive with fossil fuels in Europe. The levelised cost of electricity (LCOE) of geothermal power – the cost of producing one unit of electricity based on the construction and operating costs of a power plant over its lifetime – is already low, at around USD 60 /MWh, placing it below most fossil-fuel generation (~ USD 100 / MWh in Europe). This reflects geothermal’s high capacity factors and the fact that existing projects have largely been developed in favourable geological conditions using conventional designs, with average depth of well between 1 to 3km.
Drilling and reservoir development remain the dominant drivers of capital expenditure, making early-stage investment risk a central barrier for deeper and more complex projects. Over the past decade, however, drilling and reservoir-engineering techniques adapted from the oil and gas sector have reduced well costs by roughly 40%, enabling economically viable access to hotter and deeper resources. As these capabilities scale, they expand the share of geothermal resources that can be developed at competitive cost.
Geothermal electricity potential increases as drilling reaches deeper, higher-temperature resources, but the depth at which suitable temperatures occur varies significantly across countries. In the European Union, assessments limited to resources accessible at depths of up to 2,000 m — where sufficiently high temperatures are available only in a subset of locations — yield a relatively constrained level of technical potential (139GW). As access extends to deeper and hotter resources, geothermal conditions become more widely available across the EU. Extending the depth range to 5,000 m increases the estimated potential by more than 50 times, while access to resources down to 7,000 m results in an increase of roughly 180 times.
In the EU, projects that take advantage of the newly accessible resources are already under construction, reaching depths beyond 4000m. Moreover, there are existing projects that have already reached depths close to 5000m, demonstrating that utilising geothermal resources at these depths commercially is already achievable with today’s technology.
Turning Europe’s early lead into long-term advantage
Europe shaped the early story of geothermal energy but its leadership is shifting as other regions turn those ideas into commercial success. Europe needs to match its technical expertise with the policy and investment momentum to lead the next phase of deployment.
Europe’s geothermal foundation and deployment
Europe played a central role in the development of geothermal energy. The world’s first geothermal electricity was produced in Italy, in 1904, and as of 2024, Europe had 147 geothermal power plants in operation. Of these, 21 have been producing electricity for more than 25 years, underscoring the long-term value of geothermal investments. In 2024, these plants produced around 20 TWh of electricity from just over 3.5 GW of installed capacity (roughly one-fifth of global geothermal capacity).
Geothermal generation in Europe remains highly concentrated. The majority of its output came from Türkiye, Italy and Iceland, which together accounted for nearly all geothermal generation in the region. Beyond these established markets, activity is spreading: several countries already produce geothermal electricity, including Croatia, France, Germany, Hungary, Austria and Portugal, while new capacity is under development in Belgium, Slovakia and Greece. Across Europe, around 50 geothermal power plants are currently moving through development, from early exploration to grid connection, with Germany leading in active projects.
Pilot EGS projects launched in France, Germany and Switzerland in the 2000s demonstrated that hot, impermeable rock could be converted into productive reservoirs. More than 100 EGS projects have now been carried out worldwide, with Europe accounting for the largest share (42), followed by the United States (33), Asia (15), and Oceania (12). More recently, EGS projects have moved from commercial demonstration to full scale development. Advanced geothermal systems are also progressing, with Europe’s first closed-loop project now operating as a grid-connected power plant in Germany.
Despite this progress, Europe is at risk of losing ground. Lengthy permitting processes, inconsistent national support and the absence of a coordinated EU strategy and accompanying policies have slowed commercial deployment. In contrast, projects in the United States and Canada are now scaling up many of the methods first tested in Europe, supported by targeted policy incentives and private investment. Delayed deployment also risks shifting learning effects, supply-chain development and cost reductions to other regions, increasing future costs for European projects even where resources are available. Without a stronger focus on market-scale financing, Europe may miss the economic and industrial benefits of technologies it helped pioneer.
Meeting the AI Power Surge
Geothermal power plants could play a crucial role in meeting the fast-growing electricity demand of data centres, whose global consumption could more than double by the early 2030s. As data-centre capacity expands, geothermal offers a stable, always-available source of electricity that can be developed alongside these sites. Its continuous output helps balance the wider power system and reliably serves data centres energy-intensive operations over the long term.
Recent research by Project InnerSpace shows that if current clustering trends continue, geothermal could economically meet up to 64 percent of new data centre demand in the US by the early 2030s and even more when developments are located near optimal resources.
At the same time, AI is reshaping geothermal development. By analysing seismic and geological data, it helps identify promising sites, streamline drilling and improve performance – creating a feedback loop in which each technology accelerates the other.
Major technology companies are no longer experimenting with geothermal – they are deploying it. Announced in 2021 and now fully operational, Google’s partnership with Fevro marked the world’s first enhanced geothermal project built for a data centre. Others are following suit, with Meta signing a 150-megawatt deal with Sage Geosystems in the United States. In Europe, no similar cooperations were announced.
From pilot projects to policy
In the United States, geothermal power is now firmly within the clean-energy toolkit. Federal legislation such as the Inflation Reduction Act has expanded investment and production tax credits to include geothermal electricity, establishing clearer economic signals for developers. Meanwhile, geothermal enjoys bipartisan backing because it leverages drilling and subsurface expertise tied to familiar industries and offers around-the-clock output.
In Europe, several Member States, including Austria, Croatia, France, Hungary, Ireland, and Poland, have developed national geothermal road maps aimed at supporting subsurface investment, demonstration wells and domestic supply chains, in some cases backed by dedicated financing and targets.
Only more recently has momentum begun to build at the EU level. In 2024, both the EU Council and the Parliament voiced their support for accelerating geothermal and proposed a European Geothermal Alliance, to be set up by the Commission. As geothermal strongly aligns with the EU’s priorities on competitiveness, energy security and industrial decarbonisation, the forthcoming European Geothermal Action Plan is a much-needed and timely development.
However, translating strategic recognition into deployment will depend on how geothermal is integrated across broader EU policy instruments. As preparations for the next Multiannual Financial Framework advance, and initiatives such as the Industrial Decarbonisation Accelerator Act aim to strengthen permitting and demand signals for clean solutions, geothermal’s high upfront risk, long asset lifetimes and system value as a source of firm capacity make coordinated EU action particularly important. In practice, the effectiveness of European geothermal framework will hinge on progress in three areas at EU level:
Reducing investment risk and accelerating deployment, by deploying shared risk-mitigation tools and targeted EU financing for geothermal electricity projects at scale;
Removing regulatory and geological bottlenecks, through streamlined permitting processes and coordinated access to subsurface data;
Ensuring geothermal’s system value is fully recognised across electricity market design, energy planning and EU energy and climate modelling, reflecting its role as a source of firm, low-carbon power.
Raw geothermal energy surface densities in Europe are computed starting from Global Volumetric Potential (GVP) data from the Geomap tool by Project Innerspace, in particular from the modules with 150 °C cutoff temperature (minimum for power applications) and depths of 2000 m, 5000 m and 7000 m.
GVP data points, reported on a geographical grid with 0.17×0.17 degrees latitude-longitude resolution, are then averaged over the surface of each analysed country to obtain national energy values, expressed in PJ/km2.
The conversion to useful electrical energy is then performed by multiplying each country’s total by exergy efficiency (~30%, based on a 150 °C temperature for hot rock and on a 25 °C temperature for ambient) and utilization (~20%, based on conservative ranges out of the GEOPHIRES v2.0 simulation tool) factors. Capacity equivalents are calculated assuming an 80% load factor and a 25-years lifetime for a modern geothermal power plant. Results from the steps in this paragraph were used to validate the methodology through benchmarking with aggregated values from “The Future of Geothermal Energy” report by IEA.
The extraction of the original GVP data by Project Innerspace was performed in November 2025. Features and availability of modules within the Geomap tool might have changed since then.
Estimates for electricity generation in the EU are based on an 80% load factor, consistent with the rest of the methodology and representative of modern geothermal power plants. While cumulative generation and capacity estimates for 2025 only would yield a load factor of around 65%, future technological (improvements in plant operations) and market (increases in electrification and grid availability) conditions can justify assumptions for utilization of geothermal power capacity at or above this level.
Throughout the report, “Europe” refers to the European Union plus Iceland, Norway, Switzerland, Türkiye, United Kingdom and Western Balkan countries, reflecting the geographical scope of geological resource assessments and existing geothermal deployment. Where analysis refers specifically to the European Union, this is stated explicitly.
Acknowledgements
The authors would like to thank several Ember colleagues for their valuable contributions and comments, including Elisabeth Cremona, Pawel Czyzak, Reynaldo Dizon, Burcu Unal Kurban, Eli Terry, and others.
We would also like to extend our gratitude to our partners Clean Air Task Force and European Geothermal Energy Council for providing external review as well as valuable data and insights.
About 22% of light-duty vehicles sold in 2025 in the United States were hybrid, battery electric, or plug-in hybrid vehicles, up from 20% in 2024. Among those categories, hybrid electric vehicles have continued to gain market share while battery electric vehicles and plug-in hybrid vehicles decreased, according to estimates from Omdia. In the second half of 2025, battery electric vehicle sales increased before sharply declining in response to the expiration of tax credits at the end of September.
These different vehicle types affect the broader energy sector in different ways. Battery electric vehicles and plug-in hybrid vehicles can consume electricity from isolated power sources or, more commonly, from the grid. So, their use can affect electricity demand. By comparison, hybrid electric vehicles do not have plugs, so they don’t directly affect grid-delivered electricity demand and were not eligible for any of the federal tax credits that expired in September.
Two tax credits for purchasing or leasing new electric vehicles both expired on September 30, 2025: the New Clean Vehicle Credit and the Qualified Commercial Clean Vehicle Credit. Battery electric vehicle market share reached record highs immediately before the credits expired: 12% of light-duty vehicles sold in September. Battery electric vehicle sales then fell to less than 6% of the market in each of the remaining months of 2025. Last year marked the first year where annual sales and market share of battery electric vehicles declined.
Battery electric vehicle sales in particular are more common in the luxury vehicle market. U.S. luxury vehicles accounted for 14% of the total light-duty vehicle market in 2025, and within luxury sales, battery electric vehicles accounted for 23%. The expiration of the clean vehicle tax credits affected sales of luxury and non-luxury battery electric vehicles in similar ways.
Because sales figures in any year are relatively small compared with the total number of vehicles on the road, electric vehicles’ share of the total light-duty vehicle fleet is much less than the recent 9% sales share (7.5% battery electric vehicles and 1.6% plug-in hybrids). In our Monthly Energy Review, we maintain annual data series on light-duty vehicles, battery electric vehicles, plug-in hybrid vehicles, and hydrogen fuel cell electric vehicles based on data from S&P Global. In 2024, the most recent data year, electric vehicles accounted for 2% of all registered light-duty vehicles in the United States.
Natural gas, not solar panels and wind turbines, is the primary driver behind soaring power prices in Maine, according to a new report released this week by the state’s energy department.
Mainers pay some of the highest electricity rates in the country — only five states had higher residential prices in November 2025. They also spend a lot to heat their homes, given the prevalence of expensive fuel oil. Possible solutions to the problem of high energy costs are developing clean power, investing in load-flexibility strategies, and continuing to push for home-heating electrification, concludes the report, which was prepared by The Brattle Group.
As Americans grapple with unprecedented utility bills, clean energy has increasingly become a scapegoat, in Maine and beyond.
President Donald Trump has been perhaps the most notable voice, branding solar and wind the “scam of the century,” though concerns about renewable energy and affordability have come from both sides of the aisle. In Maine, Democratic lawmakers voted last June to cut support for community solar as a way to lower energy costs, and some Massachusetts legislators have proposed pulling back on energy efficiency and renewable power initiatives.
The new report is the latest in a growing body of research that challenges these arguments — and demonstrates that the major drivers of high energy costs have nothing to do with solar panels, wind turbines, or heat pumps.
The information comes just as the state launches the process of developing its latest two-year energy plan, which will take effect in 2027. The document outlines goals and lays out strategies for making energy cleaner, less expensive, and more reliable.
“It’s helpful to have the information out there for the general public and policymakers to understand what really is driving energy price volatility here in Maine,” said Dan Burgess, acting commissioner of the state energy department under Democratic Gov. Janet Mills.
Transmission and distribution expenses are partially to blame for the state’s rising bills, thanks to growing equipment and construction costs, the need to replace aging infrastructure, and repairs following storms.
But the factor that most influences power costs in Maine is the volatility of natural gas prices, the report finds. Maine is part of the six-state New England grid, which gets more than half its electricity from gas-burning power plants. Roughly 80% of the time, natural gas is the marginal generation resource — that is, it is the most expensive power source, which sets the price for all the energy flowing onto the grid at that moment.
“Natural gas is almost always what is setting the price here in New England,” Burgess said.
Between 2021 and 2023, electricity supply prices in Maine nearly tripled, rising from 6.4 cents per kilowatt-hour to 17 cents per kilowatt-hour. During that period, natural gas prices spiked in response to three winter storms and the Russian invasion of Ukraine.
Natural gas market trends suggest the fuel is only going to get more expensive, the report finds. As the United States continues to expand its liquefied natural gas export capacity, more competition for the supply is likely to drive up prices. Surging demand for electricity to power data centers — even those built beyond New England — could also increase natural gas prices nationally.
Some, including in the Trump administration, have argued that this issue is further exacerbated by New England’s failure to expand gas supply to keep pace with growing energy demand. Critics of that approach say it is misguided, however, and the Maine report does not suggest pipeline expansion as a solution to the state’s energy-cost problems.
Instead, the analysts propose three main paths toward more affordable energy bills in Maine. The first is accelerating clean energy development so that volatile natural gas prices have less impact — a feat made more difficult by the Trump administration’s vehement opposition to offshore wind, which was meant to be a cornerstone of the New England grid. The second is adopting what the report calls “load flexibility,” which means shifting some demand, like EV charging, to hours when there is less load on the grid.
The third is continuing the electrification of home heating.
Maine has earned headlines for its success in promoting heat pump installations; it hit its goal of 100,000 new heat pumps in 2023, two years before the target date, and is now aiming for a total of 275,000 new installations by 2027. In a state where roughly half of households still use heating oil for warmth, heat pumps offer a more affordable option than the pricey fossil fuel.
“We’re still the most home-heating-oil–reliant state in the country,” Burgess said. “Switching to heat pumps can reduce energy expenses.”
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