Chiyoda Corporation and US-based Sage Geosystems announced on August 26, 2026, that they have launched a technical and business feasibility study (FS) to bring the next-generation geothermal technology known as "Pressure Geothermal" to commercial-scale power generation. This is not an announcement of a newly discovered underground heat source. Beyond the heat obtained by circulating water through hot rock, the study will examine whether pressure stored underground can be recovered at the surface—rather than discarded—and whether a power plant built on this principle can be made economically viable. The underground system Sage has been designing now enters a phase where Chiyoda will translate it into major equipment specifications and energy balances, leading to capital cost and levelized cost of electricity figures.
Not a Power Plant Build, But a Study of Surface Equipment Economics
The memorandum covers the surface facilities that receive the high-temperature, high-pressure fluid rising from the wellbore. Sage will provide wellhead pressure, temperature, fluid properties, and operating conditions. Based on these, Chiyoda will determine the configuration of major equipment, calculate power and heat balances, and estimate capital costs, operating costs, and the cost of electricity generated.
Accordingly, signing this memorandum does not imply a construction contract or investment decision. No candidate site, plant capacity, FS completion date, budget, or target electricity price has been disclosed. Rather, the current task is to generate the design values needed to eventually make such decisions.
There is good reason to work out the surface side first. According to a 2026 white paper on advanced geothermal compiled by the University of Houston, surface power plants and associated equipment can account for roughly half of total capital expenditure. Geothermal wells handle flow rates roughly ten times greater than typical unconventional oil and gas wells, and are also expected to maintain steady output over 20 to 30 years. The moment fluid emerges from underground, it has not yet become cheap electricity.
Recovering Discarded Pressure Before Even Considering Heat
Conventional geothermal power generation selects sites where natural steam or hot water has accumulated and fluid flows easily. Enhanced Geothermal Systems (EGS) loosen this geographic constraint by drilling into hot rock formations that lack water and have low permeability, then artificially creating fractures to circulate water.
However, if flow resistance in the fractures and wellbore is high, the pumps needed to push water back underground can consume a significant portion of the generated power. While typical EGS approaches use granular proppant to keep fractures open, Sage instead uses fluid pressure itself to hold fractures open. This relies on a "pressure window"—keeping operating pressure above the rock's minimum principal stress but below the pressure at which fractures begin to propagate.
On the production well side as well, pressure is not released into the atmosphere. Heat is transferred to the power generation cycle through a high-pressure heat exchanger, while the remaining pressure is routed back to the inlet of a high-suction-pressure pump. In Sage's concept, heat can be converted to electricity via a supercritical CO2 turbine, and pressure via a Pelton wheel or similar device. Because underground and surface systems are treated as a single high-pressure loop, in Pressure Geothermal the plant design itself governs the performance of the underground reservoir.
Pressure is not a cost-free fuel. In energy-storage operation, using surplus electricity to inject water introduces round-trip losses. In continuous power generation, pressure remaining on the production side is reused on the injection side, reducing the additional pressure differential the pump must supply. The energy balance this FS will examine involves counting the electricity obtained from heat and pressure against the electricity consumed by pumps and high-pressure equipment within the same system boundary, in order to determine net output.
A 2024 paper from Sage compared configurations using two wells, three wells, and two wells not connected underground that alternate between injection and production. In the last configuration, water is withdrawn from one well while being pushed into the other, with roles switched at regular intervals—potentially eliminating the need to precisely connect wells via underground fractures. However, it has not been disclosed which configuration this FS will assume.
The "6-9% Pumping Power" Figure Is Not a Measured Value
The benefit of not discarding pressure appears substantial. In a 2024 paper presented at the Geothermal Rising Conference by Sage engineers, pressurizing the surface system and using a high-suction-pressure pump reduced injection pump power consumption to 6-9% of what a non-pressurized system with a low-suction-pressure pump would require. In the three-well model, this meant a drop from 958 kWe to 43-58 kWe; in the alternating two-well model, from 856 kWe to an average of 80 kWe.
These are results from numerical simulation. The paper calculated fluid and rock mechanical behavior, but noted that comparisons incorporating long-term operational effects such as rock cooling and declining thermal output over time remain future research. The figure Sage cites on its own website—that net output is 25-50% higher than conventional hot dry rock methods—is also annotated as a model-derived value. It is not a measured comparison between operating commercial plants.
Pressure management also carries constraints in the opposite direction. If pressure is too low, fractures close and flow resistance increases; if too high, fractures propagate and water is lost. If pressure affects nearby faults, there is also a risk of induced seismicity. The 2024 paper found that continuous operation of a two-well, multi-fracture model caused some fractures to keep growing, leading to significant fluid loss. Raising pressure is not an unconditional efficiency improvement, but a control problem requiring a narrow operating range specific to each geology.
What a 1 MW Field Test Proved—and Didn't Prove
Sage does have field data. In tests conducted in South Texas from 2021 to 2023, the company created a single vertical fracture in an existing deep well, injected water to expand the rock, and then measured the output of the high-pressure water returning to the surface. A 2023 paper reports a cycle sustaining 200 kW for 15.5 hours and 450 kW for 5 hours 52 minutes. In a separate 44-minute cycle, average output was 742 kW, with a peak of approximately 1 MW.
What the field test confirmed is that a deep fracture can be inflated to act as a mechanical battery, releasing pressure energy with adjustable output when needed. The authors also reported that TexNet, which monitored the site, detected no induced seismicity during fracturing and injection.
On the other hand, this test was not a demonstration of commercial power generation involving continuous heat extraction from hot rock. Nor does a single-site test guarantee safety at locations with different geology. The output from pressure storage cannot simply be added to the net output of geothermal power generation. This FS needs to calculate, using the same equipment, how much heat and pressure obtained underground can be converted to electricity after subtracting in-house consumption such as pumping power.
A First Unit in 2027, a 150 MW Plan for 2030
The current state of commercialization also requires reading the numbers separately. On August 5, 2026, Ormat Technologies explained that for the Nevada demonstration it is pursuing with Sage, it is selecting the host power plant, advancing permitting and procurement of drilling services and equipment, and designing the integration of a two-well EGS into an existing power plant. Sage's current roadmap targets completion of this first pressure-geothermal power unit in 2027.
Larger-scale projects come later. Sage's current project list shows a 150 MW power generation project east of the Rockies scheduled for 2030, listed separately from the first Nevada unit. According to the publicly available roadmap, the 150 MW project is a distinct plan from the 2027 first unit, with a target date of 2030.
What Chiyoda's FS aims to fill is the gap between this first unit and larger-scale deployment: how many MW can be extracted from given wellhead temperature, pressure, and flow rate; what the cost of electricity is after subtracting capital and operating costs, including high-pressure equipment; and whether water makeup rates and long-term net output can be sustained. If these can be presented as concrete design values, the concept of harnessing underground pressure will move closer to commercial power generation. If not, Pressure Geothermal will remain at the stage of a promising model backed by limited field testing.