DOE Backed 21 Geothermal Projects With $99 Million. The Test Is Whether Drilling Can Deliver 24/7 Power.
The Energy Department is placing a targeted bet on a resource the United States already understands how to reach: heat beneath the ground.
On September 21, the Department of Energy announced more than $99 million for 21 geothermal projects across the country. Five projects are designed to test enhanced geothermal systems, or EGS, under field conditions. Sixteen will drill and collect subsurface data to characterize conventional and next-generation resources.
The announcement is meaningful, but its limits matter. These projects have been selected for award negotiations; selection is not a final funding commitment. DOE can cancel negotiations or rescind a selection. Nor does a successful test automatically become a commercial power plant. The real investment question is whether drilling, reservoir engineering, permitting, and financing can turn promising heat into repeatable electricity at a competitive cost.
Executive Takeaways
- DOE selected 21 projects for negotiations totaling more than $99 million: five field-scale EGS tests and 16 exploration-drilling projects.
- The portfolio stretches from Alaska and the Pacific Northwest to California, Nevada, Utah, Idaho, New Mexico, and Oregon.
- Geothermal can provide around-the-clock power; DOE says operating plants typically achieve capacity factors near 90%.
- America currently has just over 4 gigawatts of geothermal generating capacity, while DOE analysis identifies potential for at least 90 gigawatts by 2050 if technology and costs improve.
- The decisive variables are drilling success, sustained reservoir performance, development time, and the cost of delivered electricity—not the headline award amount.
Main Analysis
A research portfolio built around field evidence
The new program is divided into two practical groups. The five EGS demonstrations will test engineered reservoirs at depths and temperatures relevant to commercial development. The 16 exploration projects will drill wells, collect cores and temperature logs, test fluid flow, and refine models of promising resources.
That structure reflects the two central risks in geothermal development. The first is discovery risk: developers can spend heavily before they know whether a site has sufficient heat, fluid, and permeability. The second is engineering risk: even when the rock is hot, a project must create or maintain reliable circulation without unacceptable cost or operational problems.
DOE’s list includes technically distinct projects. Fervo Energy plans to drill and stimulate EGS wells in Idaho’s Elmore County and deploy high-temperature seismic monitoring at or above 200°C. Quaise Energy will test equipment in central Oregon at bottomhole temperatures between 265°C and 365°C, beyond the range where most conventional EGS tools and materials have been validated. University of Utah researchers will develop an EGS doublet at Nevada’s Dixie Valley West field to test whether engineered reservoirs adjacent to existing hydrothermal systems can sustain circulation and commercially relevant heat output.
The exploration portfolio is equally broad. GeoAlaska plans to evaluate a volcanic resource on Mt. Augustine with a deeper target above 350°C. Other teams will drill in California, Nevada, Utah, Idaho, New Mexico, Oregon, and Washington. Several projects will test horizontal drilling, modern logging, real-time model updates, and oil-and-gas-style completion techniques.
The $99 million is not buying 21 power plants. It is buying evidence about where the heat is, how the rock behaves, and whether repeatable drilling can reduce the risk of the next private dollar.
Why 24/7 power makes geothermal strategically different
Geothermal occupies an unusual position in the power mix. It is domestic, fuel-free at the point of generation, and capable of operating around the clock. DOE says geothermal plants typically achieve a capacity factor near 90%, meaning they can generate close to their rated output during most hours of the year.
That reliability has become more valuable as electricity demand grows and grid operators seek firm capacity. A megawatt that is available on a cold evening or during a windless heat wave does not have the same system value as a megawatt available only when weather conditions cooperate. Geothermal does not eliminate the need for transmission, storage, gas, nuclear, or demand response, but it can add another source of dependable domestic generation.
The resource is also a potential bridge for America’s drilling workforce. Geothermal development uses skills familiar to oil-and-gas companies: subsurface imaging, well design, high-temperature materials, horizontal drilling, stimulation, cementing, and reservoir management. That overlap could shorten learning curves and expand the supplier base—if developers can translate petroleum-sector speed and discipline into geothermal economics.
The commercial gap is still large
The United States leads the world in geothermal generating capacity, but the domestic fleet remains just over 4 gigawatts, according to DOE. The department’s modeling suggests technical advances could lift capacity to at least 90 gigawatts by 2050, nearly 25 times the current level. DOE also says EGS could eventually serve the equivalent of more than 65 million American homes and businesses.
Those figures are modeled potential, not a forecast or guarantee. Reaching them would require successful projects, lower drilling costs, faster permitting, transmission access, bankable long-term contracts, and credible performance data. DOE’s Enhanced Geothermal Shot has targeted a 90% reduction in EGS costs to $45 per megawatt-hour by 2035. That is an ambitious benchmark, not the current market price of a standardized product.
Recent oil-and-gas experience shows how quickly drilling economics can improve when activity scales and operators repeat similar designs. But geothermal wells face different temperatures, geology, corrosion, and reservoir requirements. A high-temperature well that reaches its target is only the beginning; the system must sustain usable heat and flow over time.
Facts, Analysis, and Conditional Scenarios
What DOE has confirmed: more than $99 million is associated with 21 selections; five are field-scale EGS tests; 16 are exploration-drilling projects; and resulting data are intended for public release through the Geothermal Data Repository. The selections remain subject to negotiations and possible cancellation.
Our analysis: the strongest near-term value may be shared technical data rather than immediate electricity production. Public temperature logs, drilling records, cores, seismic observations, and reservoir tests can reduce duplicated exploration work and improve the assumptions used by future developers and lenders.
Base case: several projects validate useful drilling and reservoir techniques, but commercialization remains regional and selective. Geothermal grows first where heat quality, grid access, existing infrastructure, and customer contracts align.
Upside case: field tests demonstrate sustained flow, drilling time falls, and repeatable horizontal-well designs emerge. Large power buyers and utilities sign long-duration contracts, allowing multiple projects to reach financing and construction.
Downside case: wells encounter lower temperatures or poorer permeability than modeled, stimulation underperforms, and costs remain site-specific. Award negotiations, permitting, or interconnection delays slow the program before sufficient data reach the market.
Practical Implications
For investors: separate geothermal exposure by stage. A drilling-technology supplier, an exploration developer, a contracted generator, and a speculative resource owner carry different risks. Watch cash needs, well results, offtake terms, and the distinction between announced potential and financed capacity.
For utilities and large power buyers: compare geothermal on system value, not only headline energy cost. Firm output may reduce the need for storage or backup capacity, but contracts must allocate drilling, completion, and reservoir-performance risk clearly.
For communities: jobs and tax revenue depend on projects moving beyond tests. Local officials should ask about water management, induced-seismicity monitoring, land use, transmission, emergency planning, and the financial responsibility for well closure.
For drilling and industrial companies: the opportunity lies in transferring existing capabilities without assuming the operating environment is identical to oil and gas. High-temperature electronics, tools, cement, sensors, and corrosion-resistant components could become important bottlenecks.
What to Watch
- Which selections complete award negotiations and how much funding is ultimately obligated.
- Drilling speed, cost per well, temperature confirmation, and stimulation results from the five field-scale tests.
- Whether projects demonstrate sustained flow and heat output rather than short test results.
- Publication of usable datasets through DOE’s Geothermal Data Repository.
- Power-purchase agreements, interconnection approvals, and private capital following successful tests.
Action Checklist
- Distinguish a project selection from a negotiated award and a completed power plant.
- Track technical milestones: temperature, permeability, flow rate, decline, and drilling time.
- Compare delivered power economics, including transmission and financing—not drilling cost alone.
- Identify which companies own transferable drilling, sensing, cementing, and high-temperature equipment capabilities.
- Stress-test geothermal opportunities against delays, failed wells, and weaker-than-modeled reservoir performance.
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Sources & Methodology
This article relies on the Department of Energy’s September 21 project announcement, its project-by-project descriptions, DOE’s Office of Geothermal overview, and the department’s geothermal technology summary. Basic plant mechanics were checked against the U.S. Energy Information Administration. We label selections, modeled potential, targets, and confirmed operating data separately. Scenarios are conditional analytical frameworks, not forecasts or individualized investment advice.