Geothermal boost for Amsterdam: OMV and Cocreators selected to lead regional heat projects The Aardwarmte Regio Amsterdam consortium — made up of Vattenfall, the Municipality of Amsterdam and Energie Beheer Nederland (EBN) — has selected OMV, in collaboration with Cocreators, as the operator to advance geothermal projects for collective heat networks across the Amsterdam region. The decision, reached after a European tender process, brings an experienced international energy company and a project-management specialist together with local partners to test feasibility, design potential geothermy doublets and, where viable, develop and implement geothermal heat production for district heating systems. Why this matters Decarbonising heating is one of the most urgent and technically complex elements of the energy transition in dense European cities. In the Netherlands, where gas has historically supplied much of the built environment, scaling low-carbon alternatives for space heating and ho...
Geothermal Power in the Western United States: A Transmission and Planning Roadmap to 2030
Introduction
The Western United States is approaching a decisive period for geothermal power. Electricity demand is rising because of data centers, industrial electrification, population growth, electric vehicles and the replacement of retiring fossil-fuel generation. At the same time, utilities are under growing pressure to add clean resources that can operate reliably when solar and wind output declines.
Geothermal power is well positioned to fill this role. Unlike weather-dependent generation, geothermal plants can provide firm electricity for long periods, support grid reliability and reduce the amount of storage required in deeply decarbonized power systems. However, the industry’s expansion will depend on more than subsurface heat and drilling technology. By 2030, transmission access, resource planning, project finance, permitting and utility procurement will determine whether geothermal becomes a major contributor to the western grid or remains a specialist resource concentrated in a few established markets.
The central challenge is straightforward: many of the most promising geothermal resources are located far from major electricity demand centers. New power plants will therefore require transmission capacity that must be planned years before projects reach commercial operation. A recent review of western resource and transmission planning found that transmission development is essential for significant geothermal growth and warned that geothermal access could become an afterthought if the industry does not participate actively in long-term grid planning.
Why 2030 Matters
The year 2030 represents more than a near-term milestone. It is the point at which decisions being made today will begin to determine the shape of the next generation of geothermal development.
Large geothermal projects typically require years of exploration, permitting, drilling, construction and interconnection. Conventional projects must confirm the resource through wells and manage reservoir performance over time. Enhanced geothermal systems, or EGS, must additionally demonstrate that engineered reservoirs can be created and operated reliably at commercial scale.
Projects that are expected to produce power by 2030 must therefore secure land, permits, financing, offtake agreements and transmission arrangements during the second half of the 2020s. Delays in any one of these areas can push commercial operation into the 2030s.
The western grid is also changing rapidly. New transmission lines are being developed to connect renewable resources with demand centers, while utilities are reassessing their resource portfolios in response to reliability risks and decarbonization targets. Several transmission projects are expected to be energized in the next few years, with others in advanced planning for operation in the early 2030s.
This creates a narrow opportunity for geothermal developers. If projects can be incorporated into transmission planning before new capacity is allocated to other resources, geothermal may gain access to strategic corridors. If developers wait until transmission projects are complete, available capacity may already be contracted or reserved.
Geothermal’s Role in the Western Grid
Geothermal power offers a combination of characteristics that are increasingly valuable to western utilities:
- High annual capacity factors.
- Low direct operational emissions.
- Production that is not dependent on sunlight or wind conditions.
- Potential availability during evening and overnight demand peaks.
- Long operating lives when reservoirs are properly managed.
- The ability to reduce dependence on natural gas and large quantities of battery storage.
Resource-planning studies commonly represent geothermal as a firm or flat block of power. Many planning models assign conventional geothermal capacity factors in the range of 80% to 90%, although actual performance depends on the plant, reservoir, maintenance schedule and operating strategy.
This reliability profile gives geothermal a different role from solar and wind. Solar power can produce large amounts of low-cost daytime electricity, while wind can supply energy during periods of strong resource availability. Geothermal can complement both technologies by providing consistent output and capacity during periods when variable generation is unavailable.
Geothermal should not be viewed only as a replacement for solar or wind. Its greater value may come from reducing the amount of firming capacity required around those resources. In a high-renewables system, a geothermal plant can provide dependable output during evening peaks, heat waves, winter demand periods and extended low-wind events.
This value is especially important as utilities retire coal and gas generation. Replacing fossil-fuel plants with solar and batteries alone may be technically possible, but it can require substantial overbuilding, long-duration storage and transmission investment. Geothermal can reduce some of these requirements if it is available at competitive prices and connected to the grid in time.
The Western Resource Geography
The western United States contains several geothermal development regions, but the resource is not evenly distributed. Conventional hydrothermal resources are concentrated in areas with favorable geological conditions, including parts of California, Nevada, Utah, Oregon, Idaho and New Mexico.
Next-generation geothermal technologies could expand the geographic range of development. EGS is designed to access hot rock formations that do not contain naturally permeable reservoirs or sufficient fluid flow. Closed-loop and other advanced systems could further reduce reliance on naturally occurring hydrothermal conditions.
This geographic expansion is important because it could allow geothermal projects to be developed closer to major loads. It also introduces new planning and regulatory challenges. Regions with limited commercial geothermal experience may lack detailed subsurface data, established permitting procedures, experienced drilling contractors and utility familiarity with geothermal contracts.
California remains the largest near-term geothermal market in the West. Its resource planning and procurement decisions have created a stronger demand signal than exists in most neighboring states. The state’s planning scenarios have identified substantial geothermal additions during the 2030s, while transmission studies have focused heavily on the Imperial transmission zone and southern Nevada.
Nevada also has significant potential because it already hosts a large geothermal portfolio and is connected to western electricity markets. Additional projects could serve Nevada customers, California buyers and other regional markets if sufficient transmission capacity becomes available.
Utah is emerging as an important center for next-generation geothermal development. Its location gives projects the potential to serve fast-growing western loads, including data centers and industrial customers. Transmission connections linking Utah with California, Nevada and other states will influence whether these projects can sell power into broader markets.
New Mexico, Arizona and Colorado also represent strategic opportunities. New Mexico’s transmission network was developed substantially to move wind power, but those lines could also support geothermal exports. Arizona has limited conventional geothermal resources but could access projects in neighboring states through regional transmission. Colorado has no operating commercial geothermal power plants but has begun supporting geothermal research, incentives and project development.
California has played the leading role in western geothermal procurement. The state’s experience demonstrates how policy can transform geothermal from a marginal planning option into a major clean-firm resource.
Following electricity reliability problems during the early 2020s, California regulators directed load-serving entities to procure firm, zero-emission resources. The 2021 procurement decision established a target of approximately 1 GW of firm zero-emission capacity, with geothermal identified as a leading candidate. A subsequent 2023 decision identified a potential need for up to 1,863 MW of new geothermal capacity by 2033.
The significance of these decisions extends beyond the specific megawatts involved. They provided developers with a clearer market signal, encouraged utilities to issue solicitations and improved the prospects of securing project finance.
California’s resource planning has also shown that geothermal deployment could grow considerably under more aggressive decarbonization scenarios. The state’s core planning scenario included around 2 GW of new geothermal by 2035, while a high gas-retirement sensitivity case selected as much as 4.6 GW by 2035 and approximately 5.1 GW by 2045.
These figures should not be treated as guaranteed procurement. They are planning outcomes that depend on costs, resource availability, transmission, environmental requirements and actual project execution. Nevertheless, they demonstrate the scale of the opportunity if geothermal is assigned an appropriate reliability value.
California’s approach also highlights the importance of consistent modeling. Earlier planning cycles did not select geothermal at levels consistent with its reliability contribution. Later decisions corrected this imbalance by recognizing the need for clean firm capacity after gas plants retire and variable renewable generation expands.
By 2030, California will likely remain the most important buyer of new western geothermal power. Its demand could support projects located outside the state, particularly where developers can demonstrate reliable transmission access and competitive delivered costs.
The most important barrier to geothermal expansion by 2030 may not be drilling or reservoir engineering. It may be transmission.
Geothermal resources are location-specific. A solar project can often be built across a wide range of sites with appropriate land and irradiation. A wind project depends on wind quality but may also have multiple development zones. A geothermal project must be located where subsurface temperatures, permeability and fluid conditions are adequate, or where an engineered system can be developed economically.
This limits the ability of geothermal developers to move projects closer to load. If the resource is distant from cities, industrial customers or major substations, a transmission solution is necessary.
Transmission projects require long development periods. They involve route selection, environmental review, land acquisition, cost allocation, regulatory approval, construction and interconnection studies. These timelines do not always match the development schedule of geothermal projects.
The result is a coordination problem. A geothermal developer may not commit billions of dollars to drilling without confidence that power can be delivered to customers. A transmission planner may be reluctant to build capacity for a project that has not yet proven its resource. Utilities may wait for a firm power contract before supporting either investment.
This cycle must be broken through coordinated planning.
By 2030, the geothermal industry should be seeking more than individual interconnection agreements. Developers, utilities, state agencies and regional transmission organizations need to identify geothermal development zones and plan the associated network upgrades before projects reach final investment decisions.
A western geothermal transmission roadmap should answer several practical questions:
- Which geothermal regions can deliver power by 2030?
- Which substations and corridors are closest to high-potential resources?
- What upgrades are required to connect projects?
- Which lines can support multiple geothermal projects?
- How can costs be allocated among utilities and beneficiaries?
- Which projects can serve California, Nevada, Utah, Arizona and the Pacific Northwest?
- How will EGS projects outside traditional geothermal regions be represented in planning models?
Transmission planning should also recognize that geothermal projects may provide more than energy. Their high capacity value can help meet resource adequacy requirements, potentially strengthening the case for transmission investment.
Enhanced geothermal systems are central to the industry’s long-term growth strategy. Conventional hydrothermal resources are valuable but geographically limited. EGS could expand geothermal deployment into areas where hot rock exists but natural permeability and fluid circulation are insufficient.
The technology involves drilling wells into hot rock, creating or enhancing fracture networks and circulating fluid through the engineered reservoir. The heated fluid is then brought to the surface to generate electricity.
EGS offers the potential for firm, dispatchable power from a much larger resource base. However, the technology must prove that reservoirs can be created predictably, maintained safely and operated economically over extended periods.
The period leading to 2030 will be an important commercial test. Developers need to demonstrate:
- Repeatable drilling performance.
- Reliable reservoir stimulation.
- Controlled fluid circulation.
- Commercial power output.
- Low induced-seismicity risk.
- Sustainable reservoir behavior.
- Competitive project costs.
- A clear permitting pathway.
- Financing structures that reflect technology risk.
A 2025 analysis of next-generation geothermal identified a pathway in which large EGS projects could deliver 100–500 MW, with projects beginning development in the late 2020s potentially reaching commercial operation between 2030 and 2034.
Other assessments have described the need for early commercial deployment across several states to validate the technology under different geological conditions. One analysis estimated that commercial liftoff could require 2–5 GW across four to six states, supported by substantial early investment.
These estimates indicate why 2030 matters. The industry does not need to deploy hundreds of gigawatts by that year to demonstrate success. It needs to establish enough projects in different geological and market environments to prove that geothermal can move from individual demonstrations to a repeatable development model.
Data centers are becoming a major source of electricity demand in the West. Their loads are typically large, concentrated and relatively firm, which makes them a natural market for geothermal power.
Corporate customers increasingly want clean electricity that is available around the clock rather than only on an annual energy-matching basis. Solar and wind contracts can help meet annual consumption targets, but they may not provide power during every hour of operation. Geothermal can offer a stronger match between clean-energy procurement and continuous load.
This creates opportunities for direct contracts between geothermal developers and technology companies, data-center operators or industrial customers. Corporate buyers may also accept prices that are higher than wholesale averages if geothermal helps them secure reliable power, meet emissions targets and reduce exposure to grid constraints.
The relationship between data centers and geothermal can take several forms:
- Utility-scale geothermal plants selling power through long-term contracts.
- Dedicated geothermal generation serving a nearby data center.
- Behind-the-meter or islandable systems.
- Hybrid geothermal, solar and storage projects.
- Corporate power purchase agreements.
- Clean-firm capacity contracts that value reliability separately from energy.
A proposed enhanced-geothermal data-center corridor has been described as beginning with 500 MW by 2029, illustrating the scale of potential corporate demand. [3]
However, behind-the-meter development does not eliminate all challenges. Projects still require drilling, cooling systems, water management, environmental permits and equipment supply chains. If the data center is connected to the wider grid, interconnection and transmission constraints remain relevant.
Corporate demand can help accelerate geothermal deployment by providing long-term offtake agreements. Yet developers must avoid relying on a small number of buyers. A resilient market should include utilities, community choice aggregators, municipalities, industrial customers and corporate purchasers.
Planning Models Must Improve
Geothermal’s treatment in resource-planning models will strongly influence its deployment by 2030.
Most utility models simplify geothermal as a flat block of generation. This representation captures some of its value but may not fully reflect operational flexibility, ramping capability, hybrid configurations or the ability to provide ancillary services.
Geothermal can be modeled in several ways:
- Baseload generation with high annual availability.
- Dispatchable clean capacity.
- Flexible generation that follows demand within operating limits.
- A resource-adequacy asset with high capacity value.
- A firm complement to variable renewables.
- A long-duration clean-energy resource.
- A source of electricity and heat.
The choice of representation affects whether a model selects geothermal. If the model assigns high value to batteries but underestimates geothermal reliability, geothermal may be screened out even when it could reduce total system costs.
Cost assumptions are equally important. Developers face high early-stage costs because exploration wells may fail, drilling conditions may vary and project timelines can be long. Once a resource is confirmed, however, the operating profile can be attractive.
Planning models should account for learning curves and portfolio effects. The cost of the first project in a new region may be high because infrastructure, data and supply chains are undeveloped. Later projects may benefit from shared roads, substations, drilling knowledge, local contractors and improved geological understanding.
Models should also examine transmission constraints explicitly. A geothermal project should not be treated as fully available if its output cannot reach customers. Conversely, a project that can use a planned transmission corridor should receive credit for the value of that infrastructure.
State and federal policy will determine how quickly western geothermal projects can move from concepts to construction.
A recent policy assessment identified five key deployment levers: subsurface data collection, predictable regulatory frameworks, early-stage financing, transmission infrastructure and continued research and development. [4]
Subsurface Data
Geothermal development is less risky when developers have access to high-quality geological and well data. Many western states possess historical well logs, temperature records and geological surveys, but some information remains difficult to use because it is stored in paper documents or incompatible formats.
Digitizing historical well logs could provide substantial value at relatively low cost. One assessment estimated that digitizing the most relevant geothermal well records in many western states could cost from several hundred thousand dollars to approximately $1.5 million per state, far less than collecting equivalent information through new drilling.
States should create open, standardized geothermal data platforms that protect confidential commercial information while making public geological information easier to analyze.
Permitting
Permitting rules must distinguish between different geothermal activities. Exploration wells, production wells, stimulation operations, power plants, transmission lines and water infrastructure may involve separate agencies and approval processes.
Unclear jurisdiction can delay projects and increase financing costs. States can improve investment conditions by establishing clear timelines, coordinated agency reviews, standardized environmental requirements and dedicated geothermal permitting teams.
Early-Stage Finance
Geothermal projects have a financing gap between venture capital and conventional infrastructure finance. They are too capital-intensive for many early-stage investors but too risky for traditional lenders before resource confirmation.
Public support can reduce this gap through:
- Exploration grants.
- Loan guarantees.
- Milestone-based convertible loans.
- Insurance for unsuccessful wells.
- Tax credits.
- State-backed drilling funds.
- Production incentives.
- Public-private demonstration partnerships.
The goal should not be to permanently subsidize geothermal generation. It should be to reduce early geological and commercial risk until private capital can finance projects on normal infrastructure terms.
Procurement
Utilities need stronger incentives to purchase clean firm power. Competitive procurement can compare geothermal with batteries, gas with carbon controls, hydroelectric imports, nuclear generation and other firm resources.
Procurement mechanisms should value both energy and capacity. A contract that pays only for megawatt-hours may undervalue geothermal’s contribution during reliability events.
States can also establish clean-firm targets or require utilities to evaluate geothermal in resource plans using transparent assumptions. Such policies would provide developers with demand visibility and support investment before 2030.
Regional Coordination
The western electricity system crosses state boundaries, but energy policy remains largely state-based. This creates a mismatch between resource geography and electricity demand.
A geothermal project in Utah may sell power to California. A project in Nevada may serve customers in Arizona or the Pacific Northwest. A transmission line built to export wind from New Mexico may later support geothermal power. These possibilities require planning across utility territories and state borders.
Regional coordination should focus on:
- Shared geothermal resource assessments.
- Common planning assumptions.
- Coordinated transmission studies.
- Regional clean-firm procurement.
- Joint treatment of interconnection queues.
- Shared permitting information.
- Cross-border power purchase agreements.
- Cost allocation for multi-state transmission.
The West does not necessarily need a single regional electricity market to improve geothermal deployment, but fragmented planning should not prevent projects from serving regional demand.
The geothermal industry also needs to participate more actively in transmission proceedings. Developers should provide planners with credible project maps, development timelines, expected capacity, operating characteristics and interconnection requirements.
Without this information, transmission models may assume that geothermal resources are unavailable or too uncertain to justify network expansion. This can become a self-reinforcing cycle in which geothermal is excluded because transmission is unavailable, while transmission is not planned because geothermal is excluded.
State-by-State Outlook to 2030
California
California is likely to remain the leading geothermal market through 2030. Its clean-energy requirements, reliability concerns and procurement decisions create a stronger demand signal than in most western states.
The key issues are transmission access, project delivery and the ability of geothermal developers to meet contracted timelines. The Imperial Valley will remain important, but California buyers may increasingly look to projects in Nevada, Utah and other neighboring states.
Nevada
Nevada has an established geothermal industry and an important position between California and the interior West. Its resources could serve both local demand and regional buyers.
The state’s growth will depend on transmission, corporate procurement and utility willingness to contract for new projects. Nevada could become a major hub for conventional geothermal and EGS development.
Utah
Utah may become one of the most important EGS markets before 2030. The state has strong geological potential, access to western markets and rapidly growing electricity demand.
Large projects in Utah could demonstrate that next-generation geothermal can provide firm power at a scale relevant to utilities and data centers. Their success will depend on drilling performance, financing and transmission connections.
Arizona
Arizona’s demand is growing, but its conventional geothermal resources are more limited than those of Nevada and California. The state may therefore rely partly on imported geothermal power.
Transmission connections to New Mexico, Nevada, Utah and California will determine how much geothermal can contribute to Arizona’s future portfolio.
New Mexico
New Mexico has strong renewable-energy resources and a transmission network designed in part to export wind power. Those assets could support geothermal development if projects are identified and incorporated into planning.
The state could serve as both a geothermal producer and a regional transmission hub.
Colorado
Colorado is developing policies and research programs to support geothermal energy, although it does not yet have operating commercial geothermal power plants. By 2030, the state may be more important as a demonstration market and clean-firm buyer than as a large established producer.
Pacific Northwest
The Pacific Northwest has geothermal potential but relatively little operating capacity. Utilities may increasingly consider geothermal as they manage reliability, hydroelectric variability and clean-energy requirements.
Transmission expansion could allow the region to import geothermal power from the interior West or export future projects to California.
The Supply Chain Challenge
Geothermal expansion will require a stronger industrial supply chain. Drilling rigs, high-temperature tools, casing, cement, pumps, turbines, generators, control systems and specialized engineering services must be available at commercial scale.
The industry will compete with oil and gas, mining and other infrastructure sectors for drilling equipment and skilled workers. Rising activity could create opportunities for energy-service companies to diversify into geothermal.
Supply-chain priorities include:
- More high-temperature drilling tools.
- Improved well-control systems.
- Standardized geothermal plant designs.
- Turbines suited to different resource temperatures.
- Better stimulation and monitoring equipment.
- Expanded drilling crews.
- Specialized reservoir engineering.
- Domestic manufacturing capacity.
- Shared training programs.
Standardization will be particularly important for EGS. If every project is designed as a one-off experiment, costs will remain high and construction schedules will be difficult to predict. Modular wellfield, power-block and monitoring designs could help reduce project risk.
Economics and Competitiveness
The economics of geothermal differ from those of solar and wind because more capital is spent before the resource is fully confirmed. Exploration and drilling risk can make the early stage expensive, but geothermal plants can provide high-value output for decades once operating.
Project economics depend on:
- Resource temperature.
- Flow rate.
- Well depth.
- Drilling success rate.
- Reservoir lifetime.
- Plant efficiency.
- Transmission distance.
- Financing cost.
- Capacity payments.
- Contract duration.
- Construction schedule.
- Water and environmental requirements.
Geothermal’s competitiveness should therefore be evaluated using system value, not only levelized energy cost. A geothermal plant may produce fewer annual megawatt-hours than a large solar facility but provide more dependable capacity during critical hours.
One western planning review cited geothermal contract prices ranging from approximately $70/MWh to more than $100/MWh in selected recent transactions, illustrating the variation created by project type, customer and technology. These figures should not be treated as a universal market benchmark because contracts differ in risk allocation, escalation terms, transmission responsibility and capacity value.
By 2030, successful projects will likely combine several revenue streams:
- Energy sales.
- Capacity payments.
- Clean-energy certificates.
- Reliability services.
- Corporate premiums.
- Heat sales.
- Tax incentives.
- Potential revenue from co-produced minerals.
Geothermal and Lithium
The Salton Sea region illustrates how geothermal projects can be integrated with mineral production. Lithium extraction from geothermal brines could create an additional revenue stream while supporting battery supply chains.
This model is not applicable to every geothermal resource. It depends on brine chemistry, lithium concentration, extraction technology, water management and market conditions. Nevertheless, mineral revenues could improve project economics in areas where electricity prices alone are insufficient.
By 2030, integrated geothermal-lithium projects may influence how developers evaluate resource opportunities. The most attractive sites may be those that combine electricity production, mineral extraction and industrial demand.
Such projects also require careful environmental oversight. Water use, reinjection, chemical management, land impacts and community benefits must be addressed transparently.
What Success Looks Like by 2030
A successful western geothermal market by 2030 would not necessarily mean that geothermal has replaced solar, wind or storage. It would mean that the industry has established a repeatable path for commercial growth.
Success indicators would include:
- Multiple large geothermal projects operating or under construction.
- EGS projects producing commercial electricity.
- Utilities signing long-term clean-firm contracts.
- Geothermal included consistently in regional transmission plans.
- New transmission corridors designed to serve geothermal zones.
- Faster and clearer state permitting.
- Expanded drilling and equipment supply chains.
- Better subsurface data availability.
- Financing structures that reduce exploration risk.
- Corporate customers purchasing around-the-clock clean power.
- Resource-planning models assigning appropriate value to geothermal reliability.
The most important achievement would be confidence. Utilities must believe that geothermal projects can be delivered on schedule. Investors must understand the risks and available protections. Regulators must have clear procedures. Developers must know where transmission will be available.
Conclusion
The Western United States has an opportunity to make geothermal power a central part of its clean-energy transition by 2030. The resource can provide firm electricity, support reliability and reduce the need to overbuild variable renewables and storage.
But geothermal growth will not happen automatically. The industry must overcome transmission constraints, drilling risk, permitting delays, limited data, inconsistent planning assumptions and financing challenges.
California has created the strongest near-term market signal, while Nevada, Utah, New Mexico, Arizona, Colorado and the Pacific Northwest offer additional opportunities. EGS could expand the resource base, but commercial projects must prove that engineered reservoirs can operate reliably and economically.
The decisive work will occur before the power plants are built. Developers and utilities must coordinate transmission, offtake and resource planning during the second half of the 2020s. States must improve permitting, data systems and early-stage finance. Regional planners must treat geothermal as a clean-firm resource rather than a marginal technology.
By 2030, the western grid could have the beginnings of a geothermal network capable of expanding through the following decade. The outcome will depend on whether planning decisions made today recognize geothermal not simply as another renewable technology, but as a strategic source of firm, dispatchable and long-duration clean power.
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