How Ormat Plans to Commercialize Enhanced Geothermal

The targets Ormat set

Ormat Technologies split its September 8, 2026 investor day in two. The morning covered the conventional business: a plan to reach 3.5-3.7 GW of total capacity, $1.5-1.6 billion of run-rate revenue and $1.0-1.1 billion of adjusted EBITDA by 2030, every figure labelled “excluding EGS”.¹ The second half was a management panel on enhanced geothermal systems, and until that session Ormat had never put a capacity number or a date on its EGS ambitions. It now targets 100 MW of operating EGS capacity in 2030-2031 and 1 GW in 2033-2035, and describes an EGS development pipeline of 3-4 GW of preliminary potential.

Keeping the two halves apart was deliberate. CFO Assi Ginzburg confirmed in the Q&A that “in the plan that we presented, none of the numbers are EGS. They are all traditional, which mean there is basically an upside on the original plan, which is the EGS that we mentioned here.”² Exclusion from the output targets does not mean no EGS spending before 2030; the capital plan is covered below. Ormat brings decades of geothermal development and operating experience to the effort, and management noted that the company drilled an EGS well about twenty years ago that failed on cost and technology.

The 1 GW date is a range rather than a year because the constraints are external. CEO Doron Blachar said it “mainly relates to the interconnection and the ability to get enough water rights to drill this project.” Every capacity figure in the table depends on resource confirmation, land and water rights, permits, grid access and project economics, as the deck’s footnotes state.

Two subsurface pathways

Ormat is testing two reservoir designs with two partners in Nevada. Daniel Moelk, the executive vice president for subsurface, wells and next generation, said the choice of technology at any future site “will always be a site-specific decision” and a “technology readiness decision”.

The first pilot is with SLB at Desert Peak, an existing Ormat field. It follows the design most of the industry is pursuing: two horizontal wells, a dedicated injector and a dedicated producer (a pairing the industry calls a doublet), connected by a stimulated fracture network so that cold water injected in one well returns hot from the other. The second is with Sage Geosystems, in which Ormat has invested $25 million. Sage’s “huff and puff” system uses independent pressurized reservoirs where each well alternately takes water in and gives it back, so no two wells need to be connected underground.

The schedule below is the one in Ormat’s presentation; on stage, Moelk gave the Sage dates only in outline.

The Desert Peak schedule is later than the one Ormat gave a month earlier. On its August 6, 2026 second-quarter earnings call the company said it was on track to begin drilling at Desert Peak in the fourth quarter of 2026.⁴ At the investor day Moelk described 2026 as the exploration phase that “will end by the end of this year when we start mobilizing rigs and choosing our final targets,” with both wells drilled in 2027 and testing in 2028. Management gave no reason for the later dates.

Both pilots are built to answer the same five questions: whether the wells can be executed safely and repeatably, how many megawatts each well delivers, whether reservoir performance matches the models, how much water is lost, and what a megawatt costs at commercial scale. Moelk said the pilots would start in a proven range of 180-220 degrees Celsius, and that Dixie Valley wells are anticipated at 4,500-6,500 feet of vertical depth, to be determined during exploration, with laterals as long as the rigs allow. The subsurface cost target for mid-term commercial development is below $3 million per megawatt.

Asked which problem is harder, water loss or reservoir cooling, Moelk chose water. Cooling can be managed by how fast heat is produced, but water loss “is dictated by how you build it. After you’ve built it, you’ve built it,” which is why he said the reservoir architecture and the partners’ subsurface technology matter most. Ormat declined to give water-consumption targets before the pilots run.

The partnerships extend beyond the pilots. Moelk said Ormat has signed commercial agreements giving it access to both partners’ technologies for later projects, and is hiring its own well, reservoir, completion and production engineers so that it can design and operate EGS projects itself. Blachar described the goal as being able to build projects “without relying on Sage or SLB,” while adding that the partners remain available. That team is being built now, alongside the one working on the conventional 2030 plan.

Dixie Valley, the first project

Ormat chose its first planned commercial EGS site from the roughly 500,000 acres it already controls. Dixie Valley in Churchill County, Nevada, hosts an operating Ormat geothermal plant, and management screened it as one of the best locations in the state for EGS. The plan is 280 MW in three phases: 25 MW with a commercial operation date targeted for the end of 2029 into 2030, a further 75 MW targeted for the end of 2030 into 2031, and 180 MW in 2032, the last phase explicitly subject to interconnection. Ormat labels all of these as management targets that depend on drilling and testing results, permits, water, interconnection, PPAs, financing and final investment approvals.

Ormat marks land, interconnection and water rights as secured, with the PPA under negotiation. The land is held under lease rather than owned outright: the company maps its Dixie Valley area leases around the existing plant, and notes that secured rights may remain subject to term limits, conditions and approvals. The interconnection detail matters too. The executed generator interconnection agreement covers 60 MW; additional capacity remains subject to pending requests, studies, network upgrades, costs, approvals and further agreements, and Ormat cautions that the secured rights may not support the full planned 280 MW. Water rights come from the existing plant, which does not use all the water it is entitled to. The PPA is being negotiated with existing customers.

“The commercial drilling will start when we have the pilots. … That should happen sometime in mid-2028, which should take us to the first COD towards the end of 2029. It is 18 months, a bit aggressive, but we usually put aggressive targets to ourselves.”

— Doron Blachar, Chief Executive Officer, Ormat Technologies

The sequence is therefore: appraisal and monitoring wells at Dixie Valley funded in the second half of 2027, appraisal information by late 2027, a commercial drilling decision in mid-2028 once at least one pilot has worked, and construction of Phase 1 through 2029. Management described initially operating an Ormega100 unit at partial load and connecting further well pairs as they are drilled. Blachar spoke of one unit serving the first 25 MW and 75 MW phases; the presentation gives the unit’s net design output as 72-80 MW and does not reconcile the gross or net basis of the phase figures with it.

The PPA under negotiation is shaped for a project whose subsurface cost is not yet known. Paul Thomsen, vice president of business development, described a capped price to protect the buyer and a floor tied to Ormat’s rate of return, so that if drilling costs push the required price above the cap the buyer can exit and Ormat is not locked into an uneconomic contract. Ginzburg said a PPA is a precondition for heavy investment because it is what makes tax-credit monetization and project finance possible.

Land, grid and customers

Ormat has been screening the western United States for EGS with GeothermEx, a geothermal consultancy owned by SLB, state by state. Six states are complete: Oregon, Idaho, Nevada, Utah, Colorado and New Mexico. The company’s estimate from that work is that only about 2% of the identified EGS acreage in those states is currently held by geothermal developers.

Ormat identifies approximately 70,000 acres of EGS land position across existing rights, awarded leases and non-binding letters of intent, with preliminary potential of 3-4 GW. Its own footnote says an auction award or letter of intent may not result in an executed lease, and that capacity estimates depend on resource confirmation, land rights, water, permitting, interconnection and project economics. Thomsen gave the components, all rounded: roughly 30,000 acres of existing Nevada leases screened as high potential, about 1 GW by his estimate, with transmission, interconnection and water rights already in place; about 14,000 acres in Utah won at a Bureau of Land Management sale three weeks before the event, sized at roughly 660 MW; 10,000 acres in New Mexico at roughly 470 MW; and letters of intent with private landowners in Oregon and Idaho covering around 150,000 acres for evaluation, of which about 20,000 acres of subsurface and 1,000 acres of surface could be used.

Management sees private land as a way to obtain water rights and shorten permitting. Blachar also described talks with large landowners about “powered land,” siting data centres on the property for behind-the-meter supply. The 1 GW target itself is planned in front of the meter, using grid interconnection Ormat already has or has filed for. Two more Bureau of Land Management lease sales, in Nevada and Idaho, are expected before the end of 2026.

Grid access is the part of the plan that draws most on Ormat’s existing positions. Thomsen said the business development team used to file for 38.5 MW or 50 MW at a time; it has now submitted about 1 GW of EGS interconnection requests across six sites in two states, which Thomsen described as roughly 400 MW in Nevada and filings under way for close to 700 MW in Utah. Submitted requests are not awarded capacity: Ormat’s own caveat is that they do not constitute executed agreements or assure deliverability, timing or completion. Thomsen added that the team had found hundreds of megawatts of spare capacity on existing Ormat interconnections and transmission rights. Blachar put U.S. interconnection lead times at four to seven years, which is why the filings are being made now for capacity needed after 2030.

On the customer side, EGS power purchase agreements are being discussed with utilities, hyperscalers and data-centre operators, both in front of and behind the meter. Ormat describes those discussions as preliminary and non-binding.

Ormega100 and the equipment business

Ormat is developing a standardized generating unit for its own projects and for third-party customers. The Ormega100 is an organic Rankine cycle package designed to target 106 MW gross and 72-80 MW net output depending on site configuration, with a design turbine efficiency of 90%. Gross output is what the generator produces; net output is what remains after the plant’s own pumps and fans are powered. Turbine efficiency is a component figure, not the plant’s overall thermal efficiency, and Ormat labels all three numbers as engineering design targets whose actual values depend on resource temperature, flow, ambient conditions, parasitic loads, site design and validation testing. Nirit Grushko, chief technology officer, said the point was standardization rather than size: one design, engineered once, deployed at every EGS site, with major turbine maintenance planned once a decade and autonomous operation.

“If we are looking on a current project, it will take us between 24-28 months. Our long-term goal is to reduce it below 18 months. Together with that, we want that the overall, the above-ground cost will reduce to $1.5 million per megawatt.”

— Nirit Grushko, Executive Vice President and Chief Technology Officer, Ormat Technologies

The presentation states the targets as below $1.5 million per megawatt of above-ground (EPC, or engineering, procurement and construction) cost, from $3-4 million today, and below 18 months of EPC time, from 24-28 months. Ormat’s factory in Yavne, Israel has current internal capacity for about four Ormega100 units, roughly 300 MW, a year. The target of ten units a year is to be met mainly through outsourcing with limited capital, and the design is intended to qualify for U.S. domestic-content tax rules; both depend on demand, suppliers and product validation.

That last point links to the third-party opportunity. Ormat quotes a 70% share of the global binary geothermal market, measured as gross installed binary generating capacity from ThinkGeoEnergy data as of August 2026 and Ormat’s own database. It is a share of the installed base, not of EGS orders. Ofer Ben-Yosef, who runs energy storage and business development, worked the arithmetic on stage: if the DOE’s 90 GW of EGS arrives by 2050, that is a few gigawatts a year, and at Ormat’s share it is 1-2 GW of equipment demand annually. Halving that for caution still leaves “a $1 billion opportunity for equipment sales annually once EGS will ramp up.” Ormat calls this an illustrative addressable-market scenario, not a sales forecast.

The offer to other developers extends beyond turbines: EPC, operations and maintenance for owners without geothermal operating experience, and subsurface work routed through the SLB alliance. Blachar was clear about priority. Building Ormat’s own EGS portfolio is “the main focus,” and the product business is the second way to lead.

The economics and the funding

The illustrative 1 GW portfolio costs $5.5-6.5 billion, produces about $1 billion of annual revenue at an assumed $120/MWh PPA, generates about $1.1 billion of annual EBITDA with tax benefits or $0.8 billion without, and carries $175 million of annual operating and maintenance cost. All of it is a management scenario, not guidance. The slide prints the EBITDA pair as “0.8 / 1.1” above “with/without tax benefits”; Ginzburg stated on stage that the $1.1 billion figure includes the production tax credit, and this article follows the spoken version, which is the economically coherent one.

The capital figure is deliberately higher than some peers have published. Ginzburg said the first PPA will be signed on the assumption of $5.5-6.5 million per megawatt, against a long-run target of $4.5 million, made up of the $3 million subsurface and $1.5 million above-ground goals. Moelk attributed the cushion to design choices aimed at long well life and few make-up wells, so that the company can produce from its acreage for decades rather than consume it quickly. Ryan Levine of Citi pressed on the point, and the answer was that the extra capital is meant to buy lower decline rather than more megawatts.

The economics depend on securing PPAs at prices sufficient to cover still-uncertain development costs; the illustrative portfolio assumes $120/MWh. Management said EGS contracts would price higher than conventional geothermal to reflect the added risk. Blachar said conventional assets could be recontracted today at $110-120/MWh, so the illustration sits at the top of that range.

Ginzburg’s scenario also leans on tax credits. He put the production tax credit at more than $30/MWh, close to $37/MWh with domestic content, and estimated that close to $3 billion of a 1 GW build would be recovered through credit monetization over ten years of operation. Those are management assumptions, not proceeds in hand: Ormat conditions them on eligibility and compliance, and Ormat’s plan assumes eligible geothermal projects beginning construction by the end of 2033 can receive unreduced credits under the One Big Beautiful Bill Act, subject to applicable requirements.⁵

Ginzburg said Ormat expects to spend less than $30-40 million on EGS in 2026, covering the Sage investment, land and SLB pilot costs, and roughly $100 million in 2027 to fund the SLB pilot, the first Dixie Valley appraisal wells and product-segment equipment. Heavier spending would start in the second half of 2028 if the pilots succeed, funded by PPA-backed project finance, tax-credit monetization and, if needed, equity at the project level or later at the holding company. Management expects growth in EGS to be mainly organic and said it may consider technology investments, as it did with Sage; Ginzburg said no other developer apart from the one already listed is as close to a first plant.

What has to go right

The plan is sequenced so that little capital is committed before the pilots report. Appraisal information is due in the second half of 2027 and the main pilot testing phase is scheduled for 2028, so the 2029-2030 first-phase date assumes a positive mid-2028 decision and an 18-month build that Blachar himself called “a bit aggressive”; the deck shows the contingency running into 2030.

Three uncertainties remain: reservoir water losses, which depend on architecture and construction choices the pilots have not yet tested; interconnection timing, which governs both the Dixie Valley third phase and the 1 GW date; and achievable PPA pricing, since a plant costing $5.5-6.5 million per megawatt needs a tariff at or above the top of today’s conventional recontracting range.

Ormat’s proposed advantage is combining its operating fleet, manufacturing and development experience with existing land, water and grid rights. Whether that is enough was the question Dylan Nassano of Wolfe Research put to the CEO, asking what had changed after years of caution. Blachar’s answer was PPA prices above $100/MWh, hyperscaler demand and eighteen months of work with SLB and Sage. On the company’s own illustration, 1 GW of EGS would produce revenue of about $1 billion a year, comparable to the $1.0-1.1 billion the electricity segment targets for 2030, and EBITDA including tax benefits of about $1.1 billion, comparable to the $1.0-1.1 billion of consolidated adjusted EBITDA targeted for the same year. The two EBITDA measures are defined differently and the comparison is indicative only.