After Unit 80: Does The Gas Shift Really Lower Cost, Or Just Move The Risk Into Availability?

What This Follow-Up Is Isolating

The main article already established that the coal-to-gas shift is real. The mix moved, Unit 70 was already inside the operating base, and Unit 80 crossed from construction into licensing and commercial operation in January 2026. This continuation isolates one narrower question: does that shift truly lower the economics of generation, or does it mainly replace expensive coal risk with availability, wear, and tariff-recognition risk?

The short answer is that the fuel saving is real, but it does not close the story. On a per-kWh basis, natural gas is much cheaper than coal. At the tariff level, though, the money still has to run through cost control, recognition by the Electricity Authority, and an asymmetric availability mechanism. So the gas shift changes variable cost structure, but it does not eliminate the question of total system cost.

More than that, the decision to preserve Orot Rabin units 1-4 through December 31, 2028 makes clear that the system is still not behaving as if the coal era simply ended. Coal is no longer supposed to be a normal operating engine. It remains a limited operating insurance layer, smaller than the gas-transition investment itself, but one that exposes what gas alone has not fully solved yet: continuity and reliability under stress.

Where The Saving Already Shows Up

The cleanest evidence that the gas shift is working sits in the generation mix and in unit economics. In 2025, gas already accounted for 75.0% of the company’s generation mix, up from 64.6% in 2024. Coal dropped to 24.5%, from 34.9% a year earlier.

And this is not just a mix story. It is also a real economic shift. The average cost of generation per kWh at gas-fired plants was 13.8 agorot in 2025, versus 26.1 agorot for coal. In other words, at the variable fuel-cost level, gas remained materially cheaper than coal even after the mix moved.

The absolute cost lines support the same direction, but they need a more careful read. Coal costs fell to NIS 2.028 billion in 2025, from NIS 2.906 billion in 2024. Gas costs actually rose to NIS 3.258 billion, from NIS 3.045 billion. So the story is not “gas became cheaper and the bill fell.” The story is that the company generated much more on gas and much less on coal, and the combined fuel basket fell to NIS 5.632 billion from NIS 6.302 billion.

That distinction matters because it separates two different things. The first is a real variable-cost gain at the generation level. The second is whether that gain stays with the company, flows through to consumers, or is offset elsewhere through tariff mechanics, cost-control reviews, and availability payments. At that point the discussion is no longer about fuel versus fuel. It becomes a regulatory-economics question.

Unit 80 Is Already In, But The Tariff Story Is Not Finished

As of December 31, 2025, the company had 42 generation units, including Unit 70. Unit 80 was still outside the year-end operating base because the production license was received by Nativ HaOr on January 7, 2026, after the Electricity Authority decision on January 6, 2026, and commercial operation began upon receipt of that license.

So the 2025 results already show the gas shift, but without the full contribution of Unit 80 inside the reporting year itself. That makes 2026 a much cleaner test year: less about buildout and more about operation, availability, and recognition.

The project table explains why construction risk is mostly behind the story, but not fully out of the equation. The Orot Rabin Unit 70-80 CCGT project stood at 98% budget completion at year-end 2025, with NIS 3.913 billion already invested and only NIS 77 million left. By contrast, the coal-to-gas conversion program still had more distance to run, with NIS 1.306 billion invested and NIS 444 million still to go.

That means the Unit 80 debate is now less about whether the asset can be built and more about whether it can be recognized. The company’s filings say explicitly that recognition of the construction cost of the two Orot Rabin CCGTs will come only after cost control by the Electricity Authority. For Unit 70, an advance recognition of construction costs was already granted from the start of 2025. For Unit 80, the filings state that investment recovery and operating costs will be recognized according to costs set by the Authority after review, and that the tariff derived from those costs will be determined within tariff updates for all generation units.

This is the key turn in the follow-up. If you look only at fuel, it is easy to say that the gas shift lowers cost. If you look at the company’s revenue model, the real question becomes how the Authority will measure, recognize, and spread the investment and operating cost of the new CCGT inside the tariff base.

Even the fuel basket itself is not a free-floating margin story. The tariff mechanism says the recognized fuel basket is calculated using actual fuel quantities consumed and is recalculated retroactively. So lower variable generation cost is not just an internal operating gain. It sits inside a regulated structure. That is why the bigger question is not only how much fuel costs, but how much of that saving still shows up once the other tariff layers do their work.

The Risk Moves From Coal Into Availability

The less intuitive part of the story is that the gas shift does not erase risk. It changes its shape. The company states explicitly that its units increasingly operate as residual units in the system, meaning they close the gap between demand and generation at any given moment. As renewables and private generation keep gaining share, the number of starts and stops for the company’s units can rise.

That is where the problem begins. The company warns that this operating pattern can increase failure rates, raise maintenance burden, hurt performance, and make it harder to meet normative availability targets. This is not a side note. It is the core risk once the fuel-mix story is largely won.

The regulatory mechanism makes that sharper. Under the 2022-2027 generation tariff base, gas-fired CCGTs and open-cycle gas turbines are subject to an availability-payment mechanism. If actual availability falls below recognized availability, the company absorbs an expense equal to 100% of the gap. If performance is better than recognized availability, the reward is much smaller, around 20% of the gap. Put simply, the downside is much stronger than the upside.

That means the gas shift is not judged only on thermal efficiency. It is judged on whether the new fleet and the converted fleet can survive harder cycling patterns without creating wear that eats into tariff recognition. The company also says that open issues with the Electricity Authority remain around the way normative availability is determined, and elsewhere in the filing it says it is working to ensure that the measurement mechanism accounts for unit wear.

There is another layer of uncertainty here. For the coal units that are being converted to gas, unavailability benchmarks have not yet been set because Unit 1 at Rotenberg serves as the pilot, and the Authority wants at least a year of operating and performance data after the first conversion is completed. So even after policy support for the gas conversion exists, the rules that translate that conversion into a fully settled tariff outcome are still not closed.

Why Preserving Orot Rabin 1-4 Actually Strengthens The Point

Anyone reading only the gas-transition headline could assume coal was simply pushed out. The late-2025 and early-2026 decisions show a more complicated reality. Orot Rabin units 1-4 are not staying in normal operation, but they are not disappearing either. They are being kept in “warm preservation” through December 31, 2028.

The framework says units 3-4 entered preservation from the ministerial decision in November 2025, while units 1-2 enter preservation from the commercial operation date of Unit 80, meaning January 2026. During the preservation period, operation is permitted only under instructions from the higher designated energy authority, and each unit is limited to an average of 500 operating hours per year. The company must also report quarterly on performance and on compliance with the preservation framework.

The economic meaning is clear: coal remains in the attic, not on the generation floor. If units 1-4 were remaining part of the normal production plan, one could argue the gas shift was not real. That is not what the filings say. What they say is that these units are being kept as an emergency reliability hedge under an exceptional and limited operating regime.

Still, the very existence of that hedge means the system is not ready to build its entire reliability model on gas alone. That fits with the company’s broader statement that it has chosen to preserve dual-fuel capability in its steam units so they can still generate electricity in case of gas shortage or supply disruption.

This is also where cost proportion matters. The Orot Rabin 1-4 preservation project is estimated at NIS 110 million, of which NIS 97 million had already been invested by the end of 2025, leaving NIS 13 million still to go. That is small relative to the NIS 3.990 billion Unit 70-80 CCGT project and the NIS 1.750 billion coal-unit gas-conversion project. So preservation is not a strategic reversal. It is a relatively small insurance layer, meant to bridge the system until the new fleet and the converted fleet prove that they can deliver comparable reliability without coal crutches.

Conclusion

The shift to gas really does lower variable fuel cost. That is not a mood. It is a number: 13.8 agorot per kWh for gas versus 26.1 agorot for coal, with gas already reaching 75% of the generation mix in 2025. But that shift does not eliminate cost. It pushes cost into other layers: recovery of Unit 80 investment, cost-control review, the availability test, and preservation of a coal back-up layer through the end of 2028.

The thesis now: the gas shift creates a real improvement in generation economics, but whether that becomes a cleaner economic outcome depends not only on fuel price. It depends on the company’s ability to meet the availability mechanism and secure full, orderly tariff recognition for the new and converted fleet.

What changed versus the first read: through the end of 2025, it was easy to tell the story through the fuel mix. After January 7, 2026, the story moves into a different phase. Unit 80 is no longer a project. It is a regulated and operational asset that now has to prove availability, enter the tariff base, and turn coal preservation into temporary insurance rather than a recurring habit.