Eavor Demobilizes Rigs from Geretsried: What It Really Means for Closed-Loop Geothermal For three years, two drilling rigs on a farm estate near Geretsried, a Bavarian town about 40 km south of Munich, stood as the symbol of the world's most ambitious closed-loop geothermal experiment. Now in October 2026, Eavor Technologies, the Calgary-based developer of the Eavor-Loop, has told the town and its heating utility that both rigs would leave the site . The company said keeping idle rigs and specialist services on site was costly, and that releasing them would help put the project in the strongest position to continue with Loop 2 once its commercial structure is reworked . On the surface, this is a logistics decision. Underneath, it is one of the clearest signals yet about where first-of-a-kind geothermal technology stands, and how hard it is to turn a technical proof into a bankable business. This article explains exactly what happened, what the move means and what it does not mean...
Top 10 Geothermal Problems: Why a 24/7 Resource Still Struggles to Scale
Image credit : Fida, C.E.O Geosilica... This is what scaling looks like downhole in geothermal pipes
Intelligence; Strategy for the Geothermal Decade
Geothermal energy is often presented as the clean firm resource that can support a renewable electricity system around the clock. It does not depend on sunshine, it can operate through calm weather, and it can provide heat and power for decades. Kenya already relies heavily on geothermal generation, Iceland uses geothermal heat across its economy, and next generation developers are now signing large power contracts with technology companies seeking reliable carbon free electricity. Yet the global geothermal sector remains small compared with solar and wind, with installed electricity capacity still near 16 GW.
That gap is not caused by one obstacle. It is produced by a chain of interlocking problems involving geology, drilling, finance, permitting, public acceptance, grid access, and technology. A project may solve one challenge and still fail because another appears later in the development cycle.
The ten problems below explain why geothermal remains strategically important but commercially difficult to scale.
1. High Upfront Exploration and Drilling Costs
Drilling is geothermal energy’s central economic challenge. A developer must spend heavily before knowing whether a reservoir will produce enough hot water or steam for commercial power generation. Early expenditure can include geological surveys, geochemical testing, seismic studies, slim holes, full size production wells, casing, cement, drilling fluids, lost circulation materials, well testing, and access roads.
Unlike a solar project, where equipment can be inspected before installation, geothermal developers must investigate an invisible resource beneath the ground. A well can reach the expected temperature but fail to encounter sufficient permeability. It can intersect fractures but produce too little fluid. It can also encounter corrosive brine, unstable formations, or severe circulation losses.
The drilling environment is especially difficult in hard crystalline rock and fractured volcanic terrain. Wells may deviate from their planned path, drilling assemblies can fail, and each hour of rig time adds to project expenditure. Casing and cement may represent a large share of total well cost, particularly when a well requires multiple casing strings or remedial work.
The industry has nevertheless demonstrated meaningful learning. Fervo Energy’s Project Red and Cape Station campaigns have shown that horizontal geothermal drilling and multi stage stimulation can become faster as crews gain experience. The company has promoted repeatable GeoBlock units as a way to standardize well pads, drilling practices, stimulation procedures, and surface facilities. Its record 396 MW agreement with Google shows that commercial buyers are beginning to support this model, although the project still faces first of a kind execution risk.
International experience also shows that drilling efficiency can improve when geothermal work adopts techniques from oil and gas. Integrated well construction campaigns in Indonesia have reported major reductions in drilling cost per meter and increases in daily footage. Polycrystalline diamond compact bits, improved drilling parameters, real time data, and better lost circulation management can reduce costs.
The problem is that learning curves do not help a developer that runs out of money during the first campaign. A company must survive unsuccessful or underperforming wells before it can benefit from improved drilling rates. The economic burden is therefore concentrated at the beginning, exactly when geological uncertainty and investor caution are highest.
2. Resource Uncertainty and Exploration Risk
Geothermal development is often described as a power business, but the early stages resemble mining. The developer is searching for a subsurface resource whose commercial value depends on temperature, permeability, fluid chemistry, pressure, and reservoir size.
Surface evidence can be misleading. A hot spring may indicate heat but not productive permeability. A geophysical anomaly may identify a promising structure but not prove that the structure can deliver sustainable flow. A temperature gradient may look attractive while the rock remains too tight to support commercial production.
World Bank research shows that geothermal well success rates generally improve as a field moves from exploration into development and operation. One review reported an average success rate of approximately 59 percent across the first five wells, rising to about 74 percent during field development and roughly 83 percent in operating fields. This creates a difficult financing sequence: the wells that provide the most valuable information are often the wells with the highest failure risk.
Hot sedimentary aquifer projects illustrate the problem. These developments seek permeable, hot water bearing formations in sedimentary basins, often for district heating or industrial heat. Some projects fail because the formation is too tight, the temperature is insufficient, the water chemistry is difficult, or the expected flow rate cannot be sustained.
Conventional geothermal fields are not immune. The Geysers in California became one of the world’s largest geothermal complexes, but aggressive production reduced reservoir pressure and caused output to decline. Wastewater injection later helped stabilize the field, demonstrating that even a successful resource requires careful reservoir management.
Other projects have failed because a small number of test wells created an overly optimistic picture of the resource. Bottle Rock and South Geysers in California became examples of the danger of developing generation capacity before the steam field had been adequately characterized. Nevada’s Blue Mountain project also experienced severe production and temperature problems after commissioning, contributing to the failure of its original developer.
Exploration risk is not limited to developing countries or inexperienced companies. Switzerland’s deep geothermal projects have produced a mixed record of successful wells, partial successes, induced seismicity, and dry or commercially disappointing wells. The lesson is straightforward: advanced economies with strong geological institutions can still misread a reservoir.
3. Long Development Timelines
Utility scale geothermal projects frequently require many years between initial exploration and commercial operation. The development sequence may include reconnaissance, surface exploration, land acquisition, environmental studies, exploration drilling, flow testing, reservoir modelling, project design, permitting, financing, transmission planning, construction, commissioning, and long term performance testing.
These stages do not always proceed in a simple order. A poor well can force a redesign of the reservoir model. A revised wellfield can trigger additional environmental review. A transmission constraint can delay plant construction. A seismic event can suspend stimulation and require a new risk assessment.
In the United States, the Department of Energy has identified permitting and related administrative processes as important constraints on geothermal deployment. DOE modelling found that permitting improvements could substantially increase cumulative geothermal capacity compared with business as usual. One scenario produced 4.4 GW, or 74 percent, more capacity, while another produced 6.7 GW, or 113 percent, more capacity by 2050.
Federal land development can require separate reviews for land use planning, leasing, exploration, confirmation drilling, field development, and plant construction. If these reviews occur sequentially, a project can spend years moving through administrative gates before the developer proves the commercial resource.
California provides a clear example of how permitting and litigation can affect project schedules. Expansion of the Casa Diablo geothermal facility in the Mammoth Lakes area required a lengthy approval process involving environmental review and legal challenges. The broader lesson is that even an expansion near an existing geothermal field can face long delays.
Time is not neutral in energy markets. A delay increases interest during construction, raises the cost of engineering and procurement, postpones revenue, and creates a risk that the original power buyer will change strategy. A data centre developer seeking electricity in 2028 may not wait for a geothermal facility delayed until 2034.
Next generation companies are trying to shorten timelines through repeatable well pads, standardized plant designs, modular generation, and direct contracts with large energy users. These approaches may reduce some delays, but they cannot eliminate resource testing, environmental review, community consultation, or reservoir confirmation.
4. Limited Suitable Geological Sites
Conventional geothermal power is most competitive where high temperatures, natural permeability, and sufficient fluid occur together at accessible depths. These conditions are concentrated in volcanic regions, tectonic boundaries, rift systems, and geological hotspots.
That explains the importance of locations such as The Geysers in California, Olkaria in Kenya, Hellisheidi in Iceland, Wairakei in New Zealand, Larderello in Italy, and major fields in Indonesia and the Philippines. These regions possess unusually favourable combinations of heat and permeability.
The resource is not absent elsewhere, but development becomes more difficult when wells must be deeper, temperatures are lower, permeability is weak, or fluid chemistry is aggressive. A project may remain technically possible but become commercially unattractive.
Enhanced geothermal systems attempt to expand the resource base by creating or improving permeability in hot rock. Closed loop systems attempt to circulate fluid through engineered heat exchangers without depending on a naturally permeable reservoir. Superhot rock projects seek temperatures above approximately 400°C, where each well could theoretically deliver much more energy.
Each approach introduces new risks. EGS requires stimulation and careful seismic management. Closed loop systems face heat transfer and drilling cost challenges. Superhot wells must survive extreme temperatures, pressure, corrosion, lost circulation, and difficult well control conditions.
Geography also creates social and political constraints. Some promising geothermal resources lie beneath protected areas, pastoral land, Indigenous territories, agricultural zones, or densely populated regions. East African Rift resources can overlap with grazing systems and conservation landscapes. Japanese resources are often close to hot spring communities. European reservoirs may sit beneath cities, farms, or industrial districts.
A global geothermal industry cannot rely only on the best reservoirs. It must develop lower quality resources without allowing drilling, stimulation, and surface infrastructure costs to overwhelm the value of the electricity or heat produced.
5. Environmental and Social Concerns
Geothermal energy has a low lifecycle carbon footprint compared with fossil fuel generation, but it is not environmentally invisible. Projects can affect land, water, air quality, ecosystems, cultural sites, and local livelihoods.
Hydrogen sulfide is one of the best known concerns. Geothermal fluids can contain hydrogen sulfide, which has a distinctive odour and can create public health concerns at elevated concentrations. Icelandic facilities near Reykjavík have invested in gas capture, reinjection, monitoring, and mineralization initiatives to reduce emissions.
Hellisheiði has become an important example of environmental improvement. The CarbFix and SulFix initiatives have explored the injection and mineralization of carbon dioxide and hydrogen sulfide. Such projects show that emissions can be managed, but they also demonstrate that management requires additional equipment, monitoring, operating expenditure, and public communication.
Water chemistry creates another challenge. Produced brine may contain silica, arsenic, boron, mercury, and other dissolved substances. Reinjection is often necessary to maintain reservoir pressure and reduce surface disposal, but injection wells can clog, lose injectivity, or interact unpredictably with the reservoir.
Land and livelihood impacts can be even more significant than emissions. Kenya’s Olkaria development has generated substantial electricity and strengthened the country’s renewable energy system, but resettlement and community relations have remained controversial. World Bank inspection processes identified concerns involving affected person definitions, Indigenous Peoples policy, compensation, grazing access, water, housing, and livelihood restoration.
The Olkaria experience illustrates why compensation alone may not restore a pastoral economy. A payment to a household does not automatically replace communal grazing land, cultural landscapes, water access, livestock routes, or social networks.
Social licence must therefore be treated as an operating requirement, not simply an environmental impact assessment chapter. Communities near geothermal fields may accept drilling when they see reliable employment, water infrastructure, roads, electricity access, revenue sharing, and meaningful participation in decisions.
A technically successful project can still suffer years of opposition if local people believe benefits are concentrated elsewhere while costs remain local. Geothermal developers that ignore this risk may face protests, litigation, permit delays, or operational restrictions.
6. Induced Seismicity
Induced seismicity is one of geothermal energy’s most sensitive risks, especially for EGS. Hydraulic stimulation changes subsurface pressure and stress. If injected fluid reaches a critically stressed fault, it can trigger earthquakes.
The Basel project in Switzerland became a major warning. Stimulation at depth produced felt seismicity, including an event reported around magnitude 3.4. The project was suspended and ultimately abandoned after public opposition, insurance claims, and risk concerns.
St. Gallen later demonstrated that even a different geological setting can create difficult outcomes. Seismic events occurred during a geothermal operation, contributing to operational changes and renewed debate about whether induced seismicity could be reliably controlled.
Pohang in South Korea remains the most consequential case. On 15 November 2017, a magnitude 5.5 earthquake struck near an EGS project. A Korean government investigation concluded that high pressure stimulation, particularly through the PX 2 well, activated a previously unmapped fault and triggered the earthquake. Scientific studies have also linked pore pressure increases, fault weakening, and earthquake interaction to the event.
The consequences extended beyond physical damage. Public confidence collapsed, the project was terminated, legal disputes followed, and the event became a reference point in geothermal permitting debates worldwide.
Modern projects use several mitigation measures:
Detailed geological and structural mapping before stimulation.
Dense local seismic monitoring networks.
Small stepwise stimulation stages.
Traffic light systems that define when injection must be reduced or stopped.
Pressure management and controlled bleed off.
Independent review of seismic risk models.
Community notification and emergency communication procedures.
These measures reduce risk but cannot eliminate it. The fundamental tension remains: the fractures needed to create a productive EGS reservoir can also provide pathways to faults capable of generating felt earthquakes.
Risk tolerance also varies by location. A rural basin may accept low magnitude events that would be unacceptable beneath a major city. Developers must therefore match technology and stimulation intensity to the local geological and social context.
7. Regulatory and Permitting Barriers
Geothermal regulation is often fragmented across mining, water, environmental, land, energy, construction, and seismic authorities. The developer may need approvals for exploration, drilling, water abstraction, injection, road construction, transmission, emissions, and plant operation.
In the United States, geothermal has historically lacked some of the regulatory advantages available to oil and gas. Federal projects can encounter multiple National Environmental Policy Act reviews and separate decisions by agencies with different mandates.
The result is a mismatch between geothermal’s strategic value and its administrative treatment. A project that could provide clean firm power for decades may face a process designed for sequential review rather than coordinated development.
The Department of Energy’s permitting analysis shows that policy reform can have a major effect on geothermal deployment. Faster exploration exclusions, coordinated federal review, standardized data requirements, and clearer agency responsibilities could unlock projects without weakening environmental safeguards.
State regulation can create additional uncertainty. California’s debate over geothermal exploration exemptions demonstrated the tension between faster development and concerns involving seismicity, stimulation fluids, groundwater, and environmental disclosure.
Europe faces a different but related problem. Deep geothermal projects may fall under mining laws, groundwater rules, municipal planning powers, and local seismic requirements. After Basel and Strasbourg, authorities in some regions have become more cautious about stimulation projects, particularly near cities.
In emerging markets, overlapping land and forestry licences can delay development. Indonesia and the Philippines have extensive geothermal potential but developers may face restrictions involving protected forests, local communities, infrastructure, and concession boundaries.
Permitting reform should not mean automatic approval. It should mean predictable timelines, clear information requirements, early community engagement, coordinated reviews, and proportionate treatment of low risk exploration.
A project can survive an expensive well. It may not survive years of uncertainty over whether it will receive a final permit.
8. Financial and Investment Gaps
Geothermal financing is difficult because capital is required before the resource has been proven. Conventional project finance generally prefers predictable cash flow, established technology, creditworthy offtakers, and limited construction uncertainty. Early geothermal development offers the opposite.
Banks may finance a plant after a reservoir has been confirmed and supported by flow tests. They are far less willing to finance the first exploration wells in an undrilled area. This creates a financing gap between public exploration support and private infrastructure finance.
Risk mitigation facilities attempt to bridge this gap. The Geothermal Risk Mitigation Facility has supported early stage exploration in East Africa. Development banks have also used grants, concessional loans, guarantees, contingent finance, and technical assistance to reduce the risk carried by private developers.
The Philippines has pursued a Geothermal Resource De Risking Facility backed by the Asian Development Bank and implemented through LandBank. The structure reflects a wider reality: early geothermal risk remains difficult for private capital to absorb without public participation.
Offtake is equally important. A project needs a buyer willing to sign a long term contract at a price that supports drilling, construction, financing, and reservoir management. Fervo’s commercial pathway illustrates the value of a strong strategic buyer. Its Project Red pilot helped demonstrate the concept, followed by agreements involving Google, NV Energy, Southern California Edison, and later a 396 MW PPA with Google for Cape Station.
The Google agreement is significant because it links geothermal development to the demand for 24 hour carbon free power from data centres. It also demonstrates that large technology companies may accept higher prices or longer contracts when reliable clean capacity is strategically valuable.
Most developers do not have access to an offtaker with Google’s credit quality or energy demand. Smaller utilities may face political pressure to select lower cost solar and wind. Industrial customers may not want to sign a contract before the resource is proven.
Insurance markets also remain shallow for drilling failure, induced seismicity, resource decline, construction overruns, and reservoir underperformance. As long as developers must retain most of these risks on their balance sheets, the cost of capital will remain high.
Public guarantees, staged financing, portfolio approaches, and better subsurface insurance could allow investors to spread risk across multiple wells and fields instead of betting everything on one exploration campaign.
9. Grid Integration and Market Competition
Geothermal provides a valuable product, but many electricity markets do not pay adequately for firmness, capacity, flexibility, or avoided transmission investment. They often compare technologies using a simplified energy price rather than the full system value of reliable generation.
Solar and wind have expanded quickly because they can be deployed in modules, benefit from mature supply chains, and often achieve low headline costs. Battery storage can provide short duration flexibility. As a result, geothermal must compete not only against fossil fuels but also against combinations of solar, wind, transmission, demand response, and storage.
This does not make geothermal unnecessary. It changes the basis on which geothermal should compete. The resource must be valued as clean firm capacity, dependable energy, industrial heat, grid support, or a long duration complement to variable renewables.
Data centres are creating a new market opportunity. Their electricity demand is continuous, concentrated, and increasingly tied to carbon free procurement. A geothermal plant located near a data centre can potentially reduce reliance on congested transmission networks and provide power at hours when solar output is low.
Behind the meter development is not always simple. It may require new state laws, utility approvals, private wires, interconnection studies, and agreements on backup power. Nevertheless, it can reduce exposure to wholesale market prices and conventional transmission queues.
Interconnection remains a major constraint in the United States. Geothermal projects can wait years for transmission studies, network upgrades, and delivery rights. Fervo has had to adjust delivery strategies as transmission arrangements and California market conditions changed.
Emerging markets face a different challenge. Geothermal fields may be located far from major cities, while transmission networks remain weak. A field can produce reliable electricity but still struggle to sell it if the grid cannot transport the output.
Developers increasingly need to plan the resource, plant, transmission, storage, and offtake as one system. A technically excellent geothermal field without a route to market is not a bankable power project.
10. Technology and Scaling Limitations
The final problem is not a lack of innovation. It is the difficulty of converting promising demonstrations into repeatable industrial systems.
EGS has moved beyond laboratory research, but commercial deployment remains early. Horizontal wells, multi stage stimulation, high temperature logging, durable cement, downhole tools, pumps, and corrosion resistant materials must work together over long operating periods.
Superhot rock could provide extremely high energy output per well, but conditions above 400°C create severe engineering problems. Electronics, seals, drilling fluids, cement, casing, and well control systems must operate at temperatures beyond the range of many conventional geothermal tools.
Closed loop systems avoid some reservoir uncertainty by circulating fluid through engineered wellbores. However, they face a different challenge: the heat exchanger must collect enough energy from the rock to justify the drilling cost. If a single deep well produces too little thermal power, the levelized cost of energy can become uncompetitive.
Scaling also requires a workforce. Geothermal drilling depends on specialists who understand hard rock, fractured formations, well control, high temperature conditions, reservoir engineering, and local geology. The global workforce is not yet large enough to support hundreds of simultaneous projects.
Supply chains could become another bottleneck. High temperature pumps, large diameter casing, advanced bits, binary cycle turbines, drilling rigs, and specialized monitoring equipment are produced by a limited group of suppliers. Rapid demand growth could raise prices and extend delivery times.
Quality control becomes more important as projects grow. A small pilot can receive intensive attention from a single technical team. A multi gigawatt GeoCluster must manage dozens of wells, many stimulation stages, multiple contractors, and complex surface systems. More wells mean lower unit costs only if construction quality remains consistent.
Companies such as Fervo, Eavor, Quaise, and other geothermal developers are testing different pathways. Fervo is pursuing factory style EGS development. Eavor is developing closed loop systems. Quaise is exploring millimetre wave drilling for deep and superhot resources. Utah FORGE continues to provide public research on EGS stimulation and circulation.
These projects demonstrate progress, but they do not yet prove that geothermal can scale at the speed of solar manufacturing. The industry still needs more operating history, lower failure rates, stronger supply chains, and clearer evidence that costs will continue to decline outside the best demonstration sites.
How the Problems Interact
The ten challenges do not operate independently. They reinforce each other.
High drilling costs make exploration failures more damaging. Exploration uncertainty increases the cost of finance. Expensive capital makes developers more sensitive to permitting delays. Long permitting processes increase the risk that a power buyer will change its plans. Seismicity concerns can then extend the approval process even further.
Social opposition can also become a financial issue. If a community rejects a project, the developer may face redesign costs, delays, litigation, or cancellation. A weak grid can reduce the value of a successful resource. A strong resource can still fail if the plant lacks a bankable offtake agreement.
This is why geothermal cannot be evaluated using resource quality alone. Investors must examine the entire development chain:
Is the resource sufficiently proven?
Can the developer finance the next drilling stage?
Are permits predictable and coordinated?
Does the project have community support?
Can stimulation be managed safely?
Is transmission available?
Will the market pay for clean firm capacity?
Can the technology operate reliably for decades?
The most successful developers will be those that manage these questions as one integrated system rather than treating them as separate departments.
What Can Break the Bottlenecks
Several strategies could improve geothermal’s prospects.
First, governments can share early exploration risk through grants, guarantees, concessional loans, drilling funds, and insurance. Public money should be targeted at information gathering, because a successful exploration well improves the bankability of the entire field.
Second, regulators can create predictable pathways for low risk exploration while maintaining strong safeguards for stimulation, groundwater, emissions, and community rights. Coordinated permitting offices could reduce duplication without removing environmental review.
Third, developers can standardize projects. Repeatable well pads, modular plants, common equipment, digital drilling systems, and GeoBlock style development could create manufacturing and learning effects.
Fourth, markets can reward the services geothermal provides. Capacity payments, clean firm contracts, long duration energy procurement, industrial heat agreements, and data centre PPAs may value geothermal more accurately than simple energy price comparisons.
Fifth, projects must treat local communities as long term partners. Benefit sharing, local employment, water access, transparent monitoring, grievance mechanisms, and livelihood restoration should be designed before construction begins.
Finally, the industry must be honest about risk. Overstated production forecasts and optimistic timelines damage investor confidence when projects underperform. Conservative resource modelling, independent reviews, transparent well data, and clear contingency plans are more valuable than promotional claims.
Conclusion
Geothermal energy is not failing because it lacks value. It is struggling because its value arrives only after a difficult sequence of geological, technical, financial, regulatory, and social decisions.
The resource can provide electricity when solar output falls and wind production changes. It can support data centres, industrial facilities, district heating networks, and national grids. Kenya, Iceland, Indonesia, the Philippines, New Zealand, Italy, and the United States have already shown that geothermal can operate at meaningful scale.
The next stage will depend on whether developers can reduce the cost and uncertainty of drilling while governments create conditions in which private capital can tolerate early risk. Fervo’s agreements with major offtakers show that clean firm power has strategic buyers, but the broader industry will need more than a handful of premium contracts.
The geothermal decade will not be won by pretending that the problems are minor. It will be won by measuring them, pricing them, managing them, and separating policy barriers from genuine physical limits.
Heat is widely available beneath the Earth’s surface. What remains scarce is affordable risk capital, reliable permitting, strong community partnerships, specialized equipment, and the institutional patience to develop a resource that may take years to prove.
Alphaxioms turns geothermal complexity into bankable decisions. This analysis is for developers, offtakers, investors, and public agencies that need to understand the risks behind the promise of 24 hour clean power.
Related: Geothermal Energy Costs: Why Drilling Discipline Decides Bankable Megawatts
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