Ormat: Is the electricity segment erosion temporary or structural
Ormat’s electricity segment lost profitability in 2025 despite added capacity and better results in the other segments, because curtailments, wellfield pressure and a heavier fixed-cost base damaged fleet economics. The Switch agreement around Salt Wells shows real repricing potential, but it mainly solves the next contract roll rather than the bridge period.
What This Follow-up Is Isolating
The main article argued that Ormat’s 2025 weakness was not broad-based. Products improved. Storage improved. Electricity was the segment that diluted the quality of the year. This follow-up isolates that one question: was the electricity deterioration just a temporary operating stumble, or did 2025 show that the geothermal fleet now needs more capital, more remediation and more repricing just to defend its old margin structure.
The first number worth stopping on is the gap between the mild headline revenue decline and the much sharper margin damage underneath it. Electricity revenue fell only 1.2% to $693.9 million, but electricity gross profit fell 18.5% to $197.9 million and gross margin dropped to 28.5% from 34.6%. That is not a small wobble. It is a change in the economics of the segment.
That also tells you the problem is not simply “less generation.” Consolidated generation barely moved, 7.49 million MWh versus 7.45 million in 2024, but U.S. curtailments jumped to 277,923 MWh from 121,299 MWh, and the average realized price fell to $92.6 per MWh from $94.3. The fleet kept producing. It just sold a smaller share of that production, and it sold it through a cost base that got heavier.
That is the key read. The electricity weakness does not look like a single unlucky event. There is a structural layer here: an aging geothermal fleet, cooling resources, repowering cycles, maintenance needs and grid sensitivity. On top of that sits a more temporary layer: curtailments, plant work and contract transition noise. The positive side is that Ormat is beginning to build a new pricing lane, especially through data-center PPAs. The uncomfortable side is that this repricing path does not clean up 2026.
What Actually Drove the 2025 Damage
Management’s own bridge is useful because it shows this was not one plant blowing up. On the negative side, U.S. curtailments reduced electricity revenue by $18.6 million, mainly at McGinness Hills, Mammoth, Tungsten and Dixie Valley. Puna reduced revenue by another $13.9 million because of a temporary generation decline tied mainly to wellfield issues and lower energy rates. Stillwater removed another $3.2 million because of planned repowering work.
There were offsets. Blue Mountain, acquired in June 2025, added $6.6 million. The Beowawe repower project added $5.4 million. Dixie Valley contributed a net $8.9 million because 2024 had unscheduled maintenance. Kenya and Cove Fort added another $5.7 million. In other words, the parts of the fleet that improved still could not fully neutralize the pressure coming from the older base.
The damage did not stop at revenue. Electricity cost of revenues rose 7.9% to $496.0 million. The breakdown matters more than the total: power-plant depreciation rose by $20.0 million, property taxes rose by $8.3 million, Stillwater maintenance added $2.3 million, and Blue Mountain added another $2.0 million. That is why an $8.4 million revenue decline turned into a $44.8 million gross-profit decline. Once the fleet needs more capital support and more maintenance, a partial recovery in sold MWh does not automatically bring back the old margin.
There is a larger operating paradox here. By the filing date, Ormat said it had added 115 MW of commercial operation since the beginning of 2025 through Beowawe, Ijen, Arrowleaf, Blue Mountain and later the Hawaii solar asset acquired in January 2026. Yet the last reported full year still exited with lower electricity revenue and much lower gross profit. That does not mean the investments are failing. It means more installed MW is no longer enough on its own. What matters is the quality of the MWh, the quality of the reservoir, the access to the grid and the contract that monetizes the output.
A Bigger Fleet Is Not Necessarily a Better Fleet
Ormat’s electricity fleet is still overwhelmingly geothermal. Geothermal represents 81.3% of electricity-segment generating capacity. That is a strength because geothermal provides baseload output. It is also the core vulnerability, because this fleet lives on reservoir quality, cooling rates and well management. The 10-K does not describe a static fleet. It describes a fleet that needs ongoing intervention.
| Asset / cluster | What the filing disclosed | Why it matters |
|---|---|---|
| McGinness Hills | About 5°F cooling in the last year, plus heavy curtailments during the year because of NV Energy T-line maintenance | This is one of the fleet’s larger assets, so resource pressure and grid pressure can hit at the same time |
| Puna | Temporary generation reduction in 2025, a 63% capacity factor, and weaker energy-rate economics | This shows the problem is not only physical. Contract structure and pricing matter too |
| Brawley | A $7.2 million impairment tied to continuous losses driven mainly by wellfield issues, higher operating costs and lower electricity revenues | Once the pressure moves from operations into asset valuation, it is hard to call it simple noise |
| Salt Wells | A 10 MW plant with 1°F to 2°F annual cooling, a current PPA running to 2029, and a 5 MW upgrade expected in the second quarter of 2026 | This is the cleanest test of whether capex can translate into better future pricing rather than just more installed MW |
| Beowawe | The resource has begun to stabilize after the upgrade, and the repower already added $5.4 million to 2025 revenue | This is proof that remediation can work, but also proof that it costs time and capital |
That is why the comfortable “bad year” interpretation is too light. Some of the pressure is clearly temporary. Puna is expected to move to a new fixed-price contract later, Stillwater is in the middle of plant work, and curtailments are not necessarily permanent. But the number of places where the filing talks about cooling, mitigation, repowering or impairment means the fleet is not operating on a clean base. It is operating on a base that requires active and continuing repair.
Salt Wells Proves Repricing Power, But Not for 2026
This is the genuinely constructive part of the story. In January 2026, Ormat signed a 20-year PPA with Switch for about 13 MW from the Salt Wells geothermal plant. This is Ormat’s first direct PPA with a data-center operator. There is also an option to add an approximately 7 MW solar PV facility that would serve the auxiliary power needs of the geothermal plant. That detail matters. The solar option is not a simple extra 7 MW of clean incremental cash flow. It is part of the site’s broader contract economics.
What matters even more is timing. Deliveries under the Switch PPA are scheduled to begin in the first quarter of 2030, after a major Salt Wells upgrade that is expected to be completed in the second quarter of 2026. In the operating-fleet table, Ormat also shows that Salt Wells’ current PPA with NV Energy runs to 2029. So Salt Wells does not “fix” 2026. It creates a future rollover path where an older contract can be replaced with a more attractive one tied to a different customer set.
That is the real dividing line between temporary and structural. If the erosion were purely temporary, the right answer would simply be that Salt Wells is being upgraded and the plant will recover. But the Switch agreement says something deeper: the fleet needs better pricing to justify its economics. Management also said it sees potential future recontracting of more than 100 MW of the existing fleet under this framework. That is a very important signal. It suggests Ormat is starting to revalue baseload geothermal power in a market shaped by AI and data-center demand. It also implies that older contracts are no longer the full expression of asset value.
The other side of that point is that the improvement sits well ahead in time. It does not underwrite the next year. Until those contract resets arrive, Ormat still has to manage a fleet with cooling, curtailments, upgrades and a higher depreciation base. So Salt Wells is evidence of future value, not evidence that the electricity reset is already over.
Puna belongs in the same category. Market-price exposure is still relatively limited because the majority of Ormat’s long-term PPAs have fixed or escalating prices, but one 25 MW PPA at Puna remains more exposed. The filing says a new PPA for Puna with fixed prices, increased capacity and an extension to 2052 was approved in 2024 and is expected to be in effect in early 2027. So here too there is a repair path, but not an immediate one.
Why Skepticism Is Still Reasonable
Ormat’s electricity economics do not depend only on reservoir physics. They also depend on who pays for the power. On concentration alone, SCPPA represented 17.8% of 2025 revenue, NV Energy 13.8% and KPLC 11.9%. Ormat also says these large customers are tied to multiple material geothermal facilities, so any operating or commercial issue there hits harder than a simple percentage might suggest.
The more sensitive point is collections. At year-end 2025, KPLC had $29.5 million of overdue receivables, of which $21.1 million was collected in January and February 2026. ENEE in Honduras had $20.3 million overdue, of which only $1.0 million was collected in those two months. The filing also says KPLC recently requested more favorable rates under its existing PPAs. That does not mean the cash is uncollectible. It does mean the segment still carries commercial and collection risk, not just engineering risk.
That matters even more because the international operations of the electricity segment accounted for 20% of total company revenue in 2025, but 39% of gross profit and 49% of net income. So any serious read of electricity-segment quality has to include customer quality and collection behavior, not just plant performance. This is no longer only a plant question. It is a system-quality question.
Bottom Line
I do not think 2025 proves that Ormat’s electricity segment is structurally broken beyond repair. The filing contains real evidence that upgrades can work, Beowawe is the clearest example, and that repricing opportunities are opening for baseload geothermal capacity, Salt Wells with Switch is the key example. But it is also too easy now to dismiss the weakness as a temporary mishap.
The cleaner interpretation is this: the electricity segment has entered a reset year. The pressure today is not one event but a combination of curtailments, wellfield issues, heavier depreciation, maintenance and a contract base that is partly still priced for the old world. What supports the thesis is that visible repair paths already exist. What is still missing is proof that those paths are showing up in reported economics rather than only in project milestones and press releases.
Over the next two to four quarters, the market needs to see four things: curtailments normalize, Salt Wells completes its upgrade on time, Puna stays on track for its new PPA in early 2027, and receivable collection does not slide into a deeper round of commercial concessions. If that happens, 2025 can look like a bridge year. If it does not, the case for “temporary” gets much weaker.
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