Chapter 8. Geothermal

Introduction

Geothermal energy presents a reliable and largely untapped resource in the U.S., especially as advancements in Enhanced Geothermal Systems (EGS) technology unlock new regions for development.  While site availability is still largely governed by geological factors, improved exploration tools and plant management strategies provide viable solutions to overcome limitations and support long-term grid reliability.

Geothermal energy is a renewable resource that draws on the Earth’s internal heat, which originates from the natural radioactive decay of minerals and residual thermal energy from the planet’s formation. This heat is stored beneath the Earth’s surface and can be accessed in two primary forms. The first is hydrothermal systems, where naturally heated water accumulates in porous or fractured rock formations. The second is hot dry rock, which contains significant heat but lacks sufficient fluid for natural heat transfer.  Generally speaking, ground temperatures increase by 25 °C for every kilometer of depth, so at depths of 4 km ground temperatures are typically 125 °C and at 7 km temperatures are 200 °C; however, due to irregularities the temperatures vary widely at these depths making certain locations more feasible than others [1].

Electricity generation from geothermal resources typically relies on three main types of power plant technologies. Dry steam plants use steam directly from geothermal reservoirs to drive turbines. Flash steam plants extract high-pressure hot water from the ground, which then rapidly vaporizes into steam when pressure is reduced. Binary cycle plants, on the other hand, transfer geothermal heat to a secondary fluid with a lower boiling point, which then vaporizes and drives a turbine. Thermal efficiency depends on the resource temperature relative to ambient conditions. Binary cycle plants typically operate at 10%–13% efficiency, while flash systems reach 15%–20%, depending on the geothermal fluid’s temperature and pressure. [3]

Geothermal energy offers several compelling advantages. It provides reliable baseload power with capacity factors often exceeding 90 percent, meaning geothermal plants can operate nearly continuously. Its environmental impact is minimal, with lifecycle greenhouse gas emissions estimated to be about one-sixth those of natural gas plants. Geothermal facilities require relatively little land compared to other renewable energy sources, and their consistent output helps stabilize electric grids that rely increasingly on intermittent sources like wind and solar. Despite these benefits, geothermal energy faces several challenges. Conventional hydrothermal plants are geographically limited to tectonically active regions with high-temperature reservoirs. While EGS offers greater flexibility in location, it involves high upfront costs, complex reservoir engineering, and potential risks such as induced seismicity. Managing the fracture networks and maintaining reservoir performance over time also present technical hurdles.  Nevertheless, both conventional hydrothermal technologies and next-generation EGS continue to advance and stand to be reliable sources of energy.

Maturity of the technology

Dry steam plants, the earliest technology first implemented at Larderello, Italy in 1904, channel natural steam directly from subsurface reservoirs through turbines to drive generators before condensing and reinjecting the steam.  Flash steam plants, which dominate today, extract high-pressure hot water (typically above 180 °C), allow it to “flash” into steam as pressure decreases, direct the steam to turbines, then re-inject any residual water.  Binary-cycle plants utilize lower-temperature geothermal fluids (around 100–180 °C) that transfer heat through a heat exchanger to a secondary organic working fluid with a low boiling point, which then vaporizes and drives a turbine within a closed-loop system. [4] 

Conventional geothermal depends on highly porous hot rock (hot aquifers).  While conventional geothermal is well established, its extent is limited to few locations where these hot aquifers are present.  Advances in horizontal drilling and fracturing technologies expanded the locations for feasible geothermal energy to locations where hot rock is not porous enough for conventional geothermal (Figure 8.2). Recently, the U.S. Geological Survey (USGS) assessed that EGS in the U.S. Great Basin alone could supply up to 10% of U.S. electricity demand, contingent on scaling current technologies that enable heat extraction from impermeable rock formations. These innovations, combined with AI-driven exploration and predictive modeling, are positioning geothermal energy as a scalable, reliable, and sustainable component of the future energy mix. [5]

1 Deployment Schedule

The deployment of a geothermal power plant involves a multi-phase schedule that typically spans 3 to 5 years, depending on project complexity, permitting requirements, and site-specific conditions. Geothermal development is highly dependent on subsurface characteristics and regulatory oversight, requiring early investment in geotechnical surveys, environmental assessments, and reservoir validation. From securing permits and interconnection approvals to procuring long-lead equipment and managing construction logistics, each step carries unique timing challenges that can influence overall delivery.

Permitting & Regulatory Approvals

Since geothermal system integrate with the subsurface, comprehensive geotechnical investigations, including subsurface drilling, laboratory testing, and hazard assessments, must be initiated early in the development schedule to inform foundation design and evaluate site-specific constraints such as soil stability, seismic activity, and slope integrity.  Geothermal plant feasibility is highly dependent on site-specific reservoir characteristics, including subsurface temperature (typically ranging from 150°C to 370°C), fluid saturation, and permeability. These parameters are commonly evaluated through geothermal resource assessments conducted by the U.S. Geological Survey (USGS) and the Department of Energy (DOE). In parallel, project viability is influenced by permitting requirements under the National Environmental Policy Act (NEPA, 40 CFR Parts 1500–1508) and the Clean Water Act (CWA, 33 USC 1251 et seq.), which require environmental impact assessments focusing on land disturbance and water use.

Accessing geothermal resources on federal lands requires lease agreements through the Bureau of Land Management (BLM) under the Geothermal Steam Act (30 USC 1001 et seq.). The leasing process, which includes environmental review and public engagement, typically spans 6 to 18 months. Construction timelines are largely driven by the need to install pipelines, power transmission lines, and surface infrastructure to support fluid extraction and electricity generation. Depending on site terrain and accessibility, construction generally takes 12 to 24 months. [6]

Before commercial operations begin, acceptance testing must verify that all systems comply with NEPA-mandated mitigation measures and CWA stormwater controls. This process can add an additional 1 to 3 months to the project schedule, as detailed in BLM geothermal program guidance. In parallel, the transport of geothermal fluids, construction materials, or power plant components particularly those classified as hazardous must comply with Department of Transportation (DOT) regulations. [7] Securing these approvals typically takes one to two weeks, though route planning, special permits, and logistical constraints can introduce delays and increase costs. [8]

Under 10 U.S.C. § 2917, military departments may develop geothermal resources on DoD lands if projects serve the public interest, consider energy security, and do not hinder commercial development. DoDI 4165.70 provides guidance for real property management, including inventory, planning, and stewardship. Environmental compliance is directed by DoDD 4715.1E, which establishes DoD’s environmental and safety policies. DoDI 4715.03 further requires sustainable management of natural resources to ensure compliance with laws and support mission needs. [9]

Interconnection

Geothermal power plants require grid interconnection to deliver electricity from the generation site to the transmission network. Because geothermal sites are often located in remote or geologically active regions, proximity to high-voltage transmission infrastructure is a critical consideration during site selection. Interconnection involves constructing substations, step-up transformers, and sometimes miles of new transmission lines to connect with the nearest utility-controlled node.

Technically, geothermal plants provide stable, dispatchable baseload power, which is advantageous for grid planning. However, they must still comply with standard interconnection protocols, including voltage control, protection coordination, fault ride-through, and compliance with IEEE 1547 (or equivalent for larger systems). From a regulatory perspective, geothermal developers must submit interconnection applications through Independent System Operators (ISOs) or utilities, often requiring feasibility studies, system impact assessments, and facilities studies to determine grid readiness. The permitting and approval process can take 12–36 months, depending on project size and regional constraints.

Given the long development timelines for geothermal projects, early coordination with transmission authorities and strategic siting near existing infrastructure can reduce delays and improve overall project economics.

Procurement

Geothermal systems at the present time are built unique to each site and built to order, which increases cost and schedule compared to modular technologies that are being implemented at scale.  Table 8.1 summarizes the primary manufacturers, developers, and operators involved in the global geothermal power industry, categorized by their roles in equipment supply, project development, and plant operation across various geothermal technologies.

Large, specialized geothermal equipment faces extended manufacturing timelines, often taking 18–24 months due to limited global capacity and high demand. At the same time, material sourcing is a bottleneck: corrosion‑resistant alloys and rare-earth elements for components like casings and sensors can add 30–40 weeks to procurement timelines. [10] Logistics and regulatory factors further slow delivery. Oversized components require special permits, seasonal routing, and may face port congestion. Additionally, equipment certification across jurisdictions can add 6 to 14 months, especially when re-approvals are needed for components produced under one set of standards but used in another. [11]

Construction and Start-Up

A typical geothermal plant schedule spans 36 to 60 months, with procurement beginning midway through development and lasting 12 to 18 months. Development activities, typically lasting 12 to 24 months, often face delays due to permitting, resource confirmation, and evolving design, which can push procurement planning back by 3 to 6 months. Additional delays may result from supplier backlogs, shipping constraints, and extended contracting cycles, potentially adding 3 to 9 months. Construction generally takes 18 to 30 months but may be extended by 4 to 8 months if key equipment deliveries, such as piping or heat exchangers, are delayed. Late procurement of control systems, testing tools, or vendor services can further extend commissioning by 2 to 4 months, especially when integration depends on supplier availability.

2 Operational Capabilities

Dispatchability and Flexibility

Geothermal power plants are considered highly dispatchable generation sources because their output depends on stable, controllable geothermal heat rather than variable environmental conditions.  Long-term dispatchability depends on reservoir management practices, as excessive extraction without adequate reinjection can reduce reservoir pressure and temperature, impacting output. Temperature changes in the reservoir may impact fluid enthalpy and turbine efficiency, causing 2–5% operational losses due to equipment wear and thermal stress. Over time, reservoir depletion and scaling reduce resource quality, requiring careful management to maintain dispatch flexibility. Addressing challenges such as pressure decline, thermal changes, and grid limitations is essential to ensure geothermal energy remains a reliable component of the power mix over the long term.

Geothermal power plants are becoming increasingly flexible due to improvements in plant design and operational strategies. While traditionally considered baseload generators, modern geothermal systems are being adapted to provide more dynamic responses to changing grid demands. This includes the ability to modulate output and ramp generation up or down, especially in binary cycle plants where flow rates and working fluid conditions can be more easily adjusted. These advancements are positioning geothermal energy to play a more supportive role in systems with high levels of variable renewable energy.

Start Times and Ramp Rates

As a thermal cycle plant, cold starts for geothermal power plants typically require a warm-up period ranging from approximately 30 minutes to several hours before reaching full operational capacity.[12] [13]

Once operational, flash steam plants typically achieve ramp rates between 2% and 5% of their nominal output per minute by controlling steam flow through bypass or venting mechanisms. Binary or Organic Rankine Cycle (ORC) geothermal systems offer significantly greater flexibility, with standard ramp rates around 15% per minute and the ability to reach up to 30% per minute under flexible operation modes. [14] [15]

Grid Stability and Power Quality

Geothermal power plants contribute to power system stability through the turbine and generator rotational inertia. This inertial capability is quantified by the inertia constant (H), which is the ratio of stored kinetic energy to the generator’s MVA rating. For geothermal steam turbines, H typically ranges from 4 to 9 seconds, reflecting the substantial rotating mass of their synchronous machines and enabling them to provide significant inertial support to the grid.[16]

Geothermal power plants are advancing grid power quality through innovations in control systems, reactive power support, and voltage regulation. Unlike intermittent renewable sources, geothermal provides stable, baseload power, which inherently supports grid frequency and voltage stability. Modern geothermal facilities are increasingly equipped with digital control systems and synchronous generators that can deliver reactive power, helping to correct power factor and support voltage levels across the grid. Additionally, some plants are integrating power electronics and dynamic controls, similar to those used in inverter-based resources, to provide fast response ancillary services such as frequency regulation and voltage ride-through. These advancements make geothermal a valuable contributor to grid reliability, especially in regions with high renewable penetration where power quality support is critical.

Synchronization and Control

Modern geothermal power plants (particularly those utilizing binary cycle configurations) are increasingly designed around modular Organic Rankine Cycle (ORC) systems. These modules can be precisely synchronized to operate in unison, enabling the plant to respond effectively to large and variable electrical loads. This coordinated operation allows for seamless scaling of output, ensuring stable performance even as demand fluctuates.

Such modularity also supports integration with variable renewable energy sources, allowing geothermal plants to provide either baseload power or dispatchable capacity, depending on system design. Furthermore, enhanced geothermal systems (EGS) are being explored for their potential to operate flexibly by leveraging the natural energy storage capacity of underground reservoirs. This capability enables dynamic shifting between energy generation and storage, improving the plant’s responsiveness to grid demands.

Parasitic Loads and Degradation

Parasitic loads are an inherent feature of geothermal power plants and can significantly impact net electricity output. In flash steam parasitic loads typically range from 3% of the gross electrical output and result from the energy required to operate pumps, cooling systems, and other auxiliary equipment essential for heat extraction and fluid circulation. In binary cycle plants parasitic loads can be even higher, sometimes reaching 13%, depending on the specific system design and operating conditions. [15] [17]

In closed-loop binary geothermal plants, degradation from thermal drawdown over time can reduce net output by 1–3% annually. While the closed-loop design minimizes fluid loss and chemical interaction with the reservoir, reducing some causes of decline, thermal drawdown still occurs as heat is continuously extracted. [15][17]

3 Service Reliability

Availability & Failures

Geothermal power plants are highly reliable sources of baseload electricity due to their durable infrastructure, minimal fuel supply needs, and advanced redundancy systems. Modular designs, continuous monitoring, and proactive maintenance help ensure consistent power delivery even under fault conditions. However, external risks such as severe weather, seismic activity, and regulatory challenges still require careful management to maintain long-term resilience.

Geothermal plants typically achieve MTBF values ranging from 12,000 to 30,000 operational hours. the robustness of geothermal wells and the absence of fuel supply interruptions contribute to consistent operational performance. the robustness of geothermal wells and the absence of fuel supply interruptions contribute to consistent operational performance.  The most common cause of equipment failure in geothermal plants is caused by corrosion, erosion, and scaling of the metal components in contact with the hot saturated brine water often containing H₂S.  [18]

Redundant & Resilient Architecture

To ensure reliable power generation and operational resilience, geothermal power plants adopt a multi-layered redundancy strategy. This includes modular N+1-unit configurations, dual pumping systems, and redundant circulation pumps with dual manifold loops. These systems are designed to maintain uninterrupted fluid flow through production and injection wells, even in the event of equipment or pipeline failures.

Some facilities also incorporate bypass circuits that allow geothermal brine to continue circulating when turbines are offline. This helps preserve well integrity and maintain thermal balance within the reservoir. Although these redundancy measures increase capital expenditures and add complexity to system design, they are essential for minimizing downtime, stabilizing reservoir conditions, and ensuring continuous power delivery—particularly in regions that depend on baseload generation or during grid contingencies.

The broader redundancy framework also encompasses flexible turbine and cooling subsystems, strategic reinjection designs, distributed well infrastructure, and advanced reservoir modeling and control systems. Plants often maintain spare-part readiness and implement grid-responsive operations, while optimizing reservoir structures to enhance fracture performance and long-term sustainability. Together, these integrated strategies support continuous energy production, rapid fault recovery, and the enduring viability of geothermal resources.

External Risks

Geothermal power plants, while generally reliable and resilient, are still exposed to several external risks that can disrupt operations. These risks include:

Weather Related: Heavy rainfall and flooding can damage access roads, substation equipment, and cooling systems, especially if the plant is located in a remote area with limited drainage infrastructure. Ice storms or snow can disrupt transmission infrastructure or hinder site access for maintenance. Wildfires can threaten above-ground facilities and power lines.

Geological: Geothermal plants inherently rely on geologically active areas, which exposes them to seismic risks which can be induced due to the fluid injection or extraction processes. While most events are small, larger tremors can damage well casings, pipelines, and surface equipment. Volcanic activity is a less common but plausible risk in some high-enthalpy geothermal areas.

Operational and Environmental Disruptions: Well scaling, corrosion, and reservoir depletion can lead to unexpected downtimes if not managed properly. Moreover, community opposition or regulatory delays (especially related to groundwater use or induced seismicity) can halt operations or expansion plans. In some regions, geothermal development overlaps with protected lands or Indigenous territories, which introduces legal and operational risks.

Ensuring the resilience of geothermal power plants requires a comprehensive strategy that integrates robust site selection, durable infrastructure, continuous monitoring, proactive maintenance, and coordinated planning to address environmental, geological, and interdependent infrastructure risks.

4 Environmental Sustainability

Due to its low emissions profile, geothermal development often encounters fewer air quality permitting challenges, making it an attractive option for sustainable, baseload electricity. Geothermal systems inherently incorporate reinjection of cooled fluids to maintain reservoir pressure and long-term viability. Hydrothermal systems, whether dry steam or flash-based, cycle the same water or steam continuously, minimizing emissions. Binary-cycle plants further reduce environmental impact by isolating the working fluid from geothermal brine, thus avoiding atmospheric release of greenhouse gases and particulates.

Emissions and Air Quality Impacts

Overall, geothermal power is considered one of the cleanest and most environmentally benign energy sources, with negligible emissions contributions to smog formation, acid rain, or climate change. According to the U.S. Department of Energy (DOE), geothermal facilities emit minimal quantities of greenhouse gases, with carbon dioxide (CO₂) emissions typically less than 5% of those from fossil fuel plants on a per-megawatt-hour basis. Most modern geothermal plants, especially binary cycle systems, operate as closed-loop systems and emit no air pollutants during normal operation.

Some geothermal plants (primarily flash steam systems) may release small amounts of non-condensable gases such as hydrogen sulfide (H₂S) and carbon dioxide (CO₂), which occur naturally in geothermal reservoirs. However, these emissions are generally very low and well within regulatory limits. Advanced abatement technologies, such as thermal oxidizers, scrubbers, and the Stretford process, can remove over 99% of H₂S and other trace gases before they reach the atmosphere.  [19]

Water Consumption

Water consumption varies by plant type: flash steam plants may use ~5.3 gal/MWh of freshwater; closed-loop binary systems can operate with negligible freshwater use, but some reports cite usage as high as 5,147 gal/MWh when using fresh cooling water.  [20][21]

Excessive withdrawal of freshwater for cooling, particularly in closed loop systems that rely on groundwater sources, can lead to declining aquifer levels and reduced water availability for other local users. Additionally, improper reinjection of geothermal fluids may risk thermal or chemical contamination of shallow groundwater if not well managed, sustainable practices, such as using recycled water and deep reinjection wells, help mitigate these risks.

End of Life & Recyclability

While geothermal electricity generation produces minimal direct emissions during operation, there are associated environmental impacts at the end of life (EoL) stage due to infrastructure decommissioning and material disposal. The EoL phase contributes approximately ~2–5 grams of CO₂-equivalent per kilowatt-hour. Decommissioned geothermal facilities generate substantial volumes of recoverable materials, particularly metals such as steel, aluminum, and copper. Studies indicate that around 37% of the steel and 69% of the aluminum used in geothermal infrastructure can be recycled, with additional but unspecified recovery potential for copper. Estimates suggest that 30% to 60% of the total EoL waste from geothermal plants may be landfilled due to limited recycling pathways for these materials. [22]

Hazardous Materials & Waste Management

Geothermal power plants involve a variety of hazardous materials and waste streams throughout their construction, operation, and maintenance phases. During drilling and well stimulation operators may use hydraulic fracturing (fracking) techniques to improve reservoir permeability. This process can involve the use of chemical additives, such as corrosion inhibitors, surfactants, acids, and scale preventers, some of which are similar to those used in oil and gas fracking. These chemicals must be handled, stored, and disposed of according to environmental regulations to avoid soil or groundwater contamination. In addition, geothermal fluids extracted from underground reservoirs often contain dissolved minerals, heavy metals (like arsenic, mercury, or boron), and naturally occurring radioactive materials (NORMs). As fluids are cycled through the system, they may deposit scales or sludges within piping and separators that must be periodically removed and treated as hazardous waste. Facilities must implement closed-loop systems, secondary containment, and wastewater reinjection strategies to minimize surface discharge and environmental exposure. Proper handling of drilling muds spent fluids, and solid waste from separators is critical for ensuring long-term sustainability and regulatory compliance in geothermal operations.

5 Site Feasibility

Proximity to Energy Resources and Infrastructure

Site suitability depends on several factors: subsurface temperature gradients, rock permeability, and fluid availability, as well as surface-level considerations such as land use, environmental constraints, and proximity to transmission infrastructure. Geothermal energy availability in the United States is predominantly concentrated in the western regions, where elevated geothermal gradients and tectonic activity make the Earth’s heat more accessible. Established geothermal fields like The Geysers in California and the Salton Sea region offer proven reliability and existing infrastructure, making them prime candidates for expansion. Meanwhile, emerging EGS technologies are unlocking new development zones in the central and eastern U.S. by enhancing permeability in otherwise non-productive formations.

National Renewable Energy Laboratory’s (NREL) Geothermal Prospector and U.S. Geological Survey (USGS) datasets identify over 3,000 hydrothermal wells and numerous high-potential Enhanced Geothermal System (EGS) zones [17].   These resources could support hundreds of gigawatts in additional capacity across the US, particularly as exploration and drilling technologies improve. This potential is illustrated in Figure 8.3 which compares geothermal resource estimates from the GeoVision and Enhanced Geothermal Shot analyses [6]. The figure highlights the vast untapped geothermal capacity particularly in western states while also emphasizing emerging opportunities in central and eastern regions through deep EGS.

Land Use & Power Density

Geothermal power plants require a moderately compact footprint for their core generation equipment. A 100 MW plant typically occupies about an acre for turbine-generator units, separators, and control systems.  Additional space allocated for cooling infrastructure is usually 5 to 15 acres depending on the cooling method. Binary plants, which require more extensive heat exchange systems, tend to use more land than dry steam or flash configurations.

The well field, consisting of production and injection wells, contributes significantly to land use. Each well pad occupies 0.25 to 0.5 acres, and spans over 2.5 to 4.1 acres for subsurface activity.  While the overall geothermal lease area may span large areas, only a fraction is occupied by active infrastructure and the rest is free for other uses. [23]

As an example, a 100 MW facility may require 15 to 30 wells, resulting in 4 to 15 acres of land occupied by equipment pads over a span of 50 to 75 acres with subsurface activity.  Service roads and operational access paths further add 1 to 2 acres, supporting movement between well pads, control buildings, and maintenance zones. Auxiliary systems such as switchyards and brine treatment facilities require an additional 2 to 5 acres. When combined, the total directly utilized land for a 100 MW geothermal plant generally ranges from spanning over 40 to 100 acres, resulting in a power density of 1 to 8 MW per acre. More compact dry steam and flash systems can approach 3 MW per acre, while broader well field requirements reduce the overall density when included in full-area assessments.  Of that surface land area, only 15% to 20% is used by equipment, pads and roads, the rest is free for other uses.

Aesthetics & Acoustic Considerations

Geothermal power plants are generally less visually intrusive than many other forms of energy infrastructure. However, concerns about their appearance can still arise, particularly in scenic landscapes or environmentally protected areas. These facilities typically include components such as drilling rigs, steam pipelines, cooling towers, and well pads.

The size of cooling infrastructure in geothermal plants varies widely depending on the plant scale, resource temperature, and cooling method. For instance, natural draft cooling towers in geothermal applications can reach heights of ~100 to 180 ft (as in Ohaaki, NZ). For air-cooled condensers in smaller binary geothermal plants (~5 MW), the condenser bundles may span 13,000-15,000 ft² of ground area and use finned tubes ~60 ft long. Wet cooling towers are more compact than air-cooled, but the equipment tends to be larger than in large nuclear/coal plants for equivalent capacity because geothermal plants often operate at lower temperature differentials. [24][25]

Many geothermal plants use arrays of multiple cooling cells, which can create an industrial skyline even at moderate scales. The visual impact of these towers extends beyond their size. Persistent steam plumes, stark concrete finishes, and aviation safety lighting at night all contribute to their visibility and the public attention they attract.

Like other thermal electric plants, geothermal plants have to address noise levels when near communities. Drilling operations in geothermal work can generate very high noise levels (on the order of ~120 dBA at close range) especially during air-drilling or steam venting; mitigation such as mufflers or sound enclosures can significantly reduce these emissions. Operational noise from facilities (e.g. turbines, cooling towers, pumping gear) has been measured at ~70 dBA Leq at ~100 feet (~30 m) for some geothermal plants in California. Regulatory noise limits in some jurisdictions are around 70 dBA for operations in agricultural or rural zones, and often lower (e.g. 55-65 dBA) in residential zones, depending on local law.[26]

Public Perception and Perceived Harm

Geothermal plants are generally viewed as clean energy sources, but they can raise social concerns related to visual impact, noise, and odor. Infrastructure such as cooling towers and steam plumes may disrupt scenic views, while drilling and operations can generate noise and release trace gases like hydrogen sulfide. Additionally, communities may fear impacts on groundwater or culturally sensitive land, especially when local engagement is limited.

6 Evolving Policy

Policy Volatility

Ownership of geothermal thermal resources presents a complex legal landscape shaped by varying state definitions and evolving policy frameworks. In the U.S., geothermal rights may be vested in the surface estate, mineral estate, or treated as a unique category altogether—depending on the jurisdiction. For example, California classifies geothermal energy as part of the mineral estate, while Texas recently enacted Senate Bill 785, which assigns ownership of subsurface geothermal energy to the surface rights holder, explicitly excluding minerals and groundwater. This patchwork of definitions complicates leasing, permitting, and development, especially on federal lands managed by agencies like the Bureau of Land Management (BLM), which has reformed its leasing policies to streamline geothermal development outside Known Geothermal Resource Areas (KGRAs). The lack of uniformity in legal treatment—whether geothermal is considered water, mineral, or sui generis—can lead to disputes over drilling rights, royalties, and environmental responsibilities, making early legal diligence essential for project viability. [27]

Geothermal energy projects on federal lands may face complex permitting processes under NEPA, the Geothermal Steam Act, and multiple agency reviews. Streamlining interagency coordination and reducing redundant state and federal requirements could speed up approvals and boost investment. Reforming policy to unify agency reviews and ensure stable financial support is crucial to advancing geothermal as a reliable clean energy source.

Incentives

At the federal level, the Inflation Reduction Act (IRA) of 2022 extended the Investment Tax Credit (ITC) for geothermal systems, offering a 30% credit through 2032. The IRA also supports geothermal through expanded DOE funding, including $84 million for Enhanced Geothermal Systems (EGS) demonstration projects. Geothermal projects may also elect to claim the Production Tax Credit (PTC) in lieu of the ITC.  When looking at the recently passed One Big Beautiful Bill Act (OBBBA), it maintains the IRA’s 30% ITC for geothermal systems through 2032, with a phase-down from 2033 to 2036 under the Clean Electricity Investment and Production Credits. New restrictions prohibit projects starting after December 31, 2025, from using material assistance from Prohibited Foreign Entities, potentially complicating supply chains. While preserving the IRA’s $84 million for Enhanced Geothermal Systems, the OBBBA rescinds other unobligated IRA funds, possibly limiting further geothermal support. [28]

7 Cost of Capacity & Energy

Geothermal power plants require substantial upfront capital investment and lengthy development periods. However, they benefit from moderate operational expenses and zero fuel costs, offering a distinct advantage over conventional fossil fuel-based generation. Compared to other renewable sources like solar and wind, geothermal energy typically incurs higher operation and maintenance (O&M) costs. These elevated expenses stem from the mechanical complexity of geothermal systems—such as turbines, pumps, and heat exchangers—which must function reliably under extreme temperatures and corrosive subterranean conditions. Nevertheless, geothermal energy provides valuable benefits, including consistent baseload power and minimal land footprint. In certain energy markets, these strengths can help offset the higher O&M costs, making geothermal a compelling option for long-term sustainable energy production.

Capital and Operational Expenditures

The primary capital expenditures (CAPEX) for geothermal power plants are associated with subsurface development, including resource exploration, drilling, and well field construction. These subsurface costs typically account for over 50% of total project CAPEX. Other major cost components include surface infrastructure such as power conversion systems, cooling towers, pipelines, and electrical interconnection facilities. Based on industry estimates [29] the turnkey installed cost for geothermal plants ranges from $5 million to $6.5 million per megawatt (MW) of capacity, depending on factors such as reservoir temperature, drilling success rate, depth, and site accessibility. Because geothermal plants are baseload generators, this upfront investment supports long-term, continuous operation with no fuel cost exposure.

O&M costs for geothermal plants include fixed and variable components. Fixed OPEX ranges from $14,500 to $15,750 per MW per year, covering staffing, inspections, compliance, and preventive maintenance. Variable OPEX falls between $10 and $30 per megawatt-hour (MWh), depending on resource chemistry, heat exchanger fouling, and the need for chemical treatment.  Routine maintenance is typically scheduled during off-peak periods and requires approximately 100 to 200 hours of downtime annually. However, most commercial-scale systems are designed with modularity or redundancy, allowing uninterrupted generation during maintenance intervals.

Levelized Cost of Capacity and Levelized Cost of Energy

The Levelized Cost of Capacity (LCOC) for a geothermal system is estimated between $458,000 and $817,000 per MW per year, based on the fixed costs associated with maintaining continuous power delivery capability. Geothermal power plants are inherently designed for continuous generation, and shutting down or cycling geothermal systems for intermittent operation can lead to thermal stress, equipment degradation, and reservoir imbalances, which compromise both efficiency and long-term resource sustainability.  This makes them ideally situated for base-load power, but not for standby, peaking, or back-up power.

The Levelized Cost of Energy (LCOE) for geothermal systems typically ranges from $70 to $143 per MWh before incentives depending on resource quality and temperature, depth and cost of drilling, type of geothermal technology, plant size and economies of scale, permitting and capacity factor. LCOE is mostly driven by the CapEx (Figure 8.4) and is highly sensitive to heat resource depth, temperature, and drilling success rate. However, unlike fuel-based technologies, geothermal LCOE remains stable over time, making it an attractive option for regions seeking long-term price certainty and protection from the volatility of fossil fuel prices.  Especially where there is a good heat source, geothermal is an attractive option for primary co-located generation where the capacity factor is high.

Geothermal projects are positioned to benefit from either the PTC or ITC incentives, depending on project characteristics. The ITC, which offers an upfront tax credit based on capital investment, can be especially valuable for geothermal developments with high initial costs and long development timelines.  The PTC may be more advantageous for projects with high-capacity factors and high annual energy production yields. As a result, developers must evaluate on a case-by-case basis whether the PTC or ITC offers a more favorable return, depending on site-specific factors such as resource quality, drilling success rates, and financing structure. This positioning underscores the need for tailored incentive strategies when developing geothermal resources.  With the Federal tax incentives, LCOE’s can get into the $54/MWh to $114/MWh range as shown in Figure 8.5.

As shown in Figure 8.5 and Figure 8.6, utilization (capacity factor) and the hot rock temperature have the biggest impact on LCOE.  If the utilization is low, or the hot rock temperature is low, then the ITC is the better option.  If the capacity factor is high, and the rock temperature is high, then the PTC is more advantageous.

References

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[2] I. Stober and K Bucher, “Geothermal Energy: From Theoretical Models to Exploration and Development,” 2nd Edition, Springer Nature Switzerland AG 2021. ISBN 978-3-030-71685-1

[3] U.S. Energy Information Administration, “Geothermal Explained,” U.S. Energy Information Administration, 27 December 2022. [Online]. Available: https://www.eia.gov/energyexplained/geothermal/. [Accessed 16 June 2025].

[4] National Renewable Energy Laboratory, “Geothermal Electricity Production Basics,” National Renewable Energy Laboratory, 2025. [Online]. Available: https://www.nrel.gov/research/re-geo-elec-production/. [Accessed 16 June 2025].

[5] U.S. Geological Survey, “Enhanced Geothermal Systems in The Great Basin Could Supply 10 % of U.S. Electricity Demand,” U.S. Department of the Interior, 22 May 2025. [Online]. Available: https://www.usgs.gov/news/national-news-release/enhanced-geothermal-systems-great-basin-could-supply-10-us-electricity. [Accessed 16 June 2025].

[6] US Department of Energy, “GeoVision”. Available Online: https://www.energy.gov/eere/geothermal/geovision.  [Accessed 10 September 2025].

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