AleaSoft Energy Forecasting, August 18, 2026. The extension of the Almaraz nuclear power plant until June 2030 reduces the electricity system’s short-term exposure to gas and to its prices. At the same time, it increases the pressure to integrate a growing renewable capacity and may raise the risk of curtailment, while it changes the assumptions used to size the future capacity market.
A decision with measurable consequences
Through Order TED/864/2026, the Ministry for the Ecological Transition and the Demographic Challenge renewed the operating licence for the two units of the Almaraz nuclear power plant, which will be able to operate until June 8, 2030, following the favourable report issued on July 16 by the Nuclear Safety Council. The new date replaces the previous schedule, which set the closure of Almaraz I on November 1, 2027 and that of Almaraz II on October 31, 2028. The extension means around 31 additional months for the first unit and 19 months for the second.
The two reactors add up to 2094 MW of gross electrical capacity. In 2025 they produced 15 369 GWh gross, equivalent to approximately 7% of Spanish electricity demand, and 14 752 GWh net: 7649 GWh at Almaraz I and 7103 GWh at Almaraz II. To estimate the amount of gas needed to replace that output, net generation is the more appropriate figure, as it represents the electricity delivered by the plant.
Maintaining this output for longer has effects on the need for gas-fired generation, on electricity market prices and on emissions, but also on the integration of renewables and on the firm capacity requirements of the system.
How much gas would be needed to replace Almaraz?
A full replacement scenario helps to size the magnitude. If the 14 752 GWh net that Almaraz produced in 2025 had to be generated entirely by combined cycle plants, assuming an efficiency of between 50% and 55%, between 27 and 30 TWh of natural gas would be needed each year.
This calculation should be understood as a theoretical reference ceiling, not as a forecast of the real increase in gas consumption after the closure. In practice, that output would be replaced by a combination of new renewable energy generation, energy storage, hydropower, interconnections, demand management and combined cycle plants.
The scale of the scenario is nevertheless significant. In 2025, gas deliveries to the Spanish power sector reached 99.7 TWh. The 27-30 TWh of the full replacement scenario would represent an increase of approximately between 27% and 30% in annual gas consumption for electricity generation.
Taking a gas price of 60 €/MWh as a reference, purchasing that volume would cost approximately between 1620 and 1800 million euros per year. The cost of CO2 emission allowances would have to be added to this. As an order-of-magnitude reference, the Centrales Nucleares Almaraz-Trillo group (CNAT) estimates that the 15 369 GWh of gross output from Almaraz in 2025 avoided 5.5 million tonnes of CO2.
From gas consumption to the electricity market price
The effect of Almaraz on prices does not depend solely on the volume of energy it produces. By remaining available, it reduces the residual demand that other technologies have to cover and, in certain hours, it limits the need to resort to combined cycle plants.
The relevance of this effect increases when gas and emission allowances trade at high prices. In the week of August 10, TTF gas futures for the FrontMonth on the ICE market stood between 58.73 €/MWh and 61.42 €/MWh, and CO2 emission allowances for December 2026 between 81.79 €/t and 82.75 €/t.
With a reference gas price of 60 €/MWh and CO2 at around 82 €/t, the cost of producing electricity in a combined cycle plant stands, depending on its efficiency, at approximately between 139 €/MWh and 153 €/MWh from fuel and emissions alone.
The comparison with the market shows the importance of that cost structure. In the week of August 10, the Spanish electricity market recorded an average price of 128.92 €/MWh. When combined cycle plants are needed and set the marginal price, gas and CO2 quotations come to have a direct influence on the clearing price in those hours.
Maintaining Almaraz therefore reduces the potential exposure of the Spanish market to episodes of high gas prices. The renewal order itself notes that the extension contributes, in the short term, to moderating the exposure of the system and of consumers to peaks coming from international natural gas markets.
More nuclear also demands more flexibility to integrate renewables
The other side of the balance appears in the hours of high solar photovoltaic and wind energy production and low electricity demand. Keeping more nuclear generation available reduces the room left to integrate the rest of the output. If the system does not have sufficient storage, export capacity, grids and flexible demand, the risk of curtailment of non-dispatchable energy sources such as wind energy and solar photovoltaic may increase.
From the market point of view, the difficulty of absorbing all the available generation in certain hours increases the pressure towards zero or negative prices and accentuates the cannibalisation of the captured prices of renewable technologies. Accelerating storage and shifting consumption towards those hours makes it possible to use a larger share of renewable energy and to reduce this effect.
2030 concentrates more than 4000 MW of nuclear closures
The Almaraz extension does not, for now, change the 2035 horizon for closing the whole Spanish nuclear fleet, but it does concentrate a significant part of the replacement in 2030.
Almaraz would end its operation in June. The current schedule also places the closure of Ascó I, in October, and Cofrentes, in November, in 2030. Almaraz contributes 2094 MW and Ascó I and Cofrentes have around 1000 MW each, so more than 4000 MW of nuclear capacity would leave the system in less than six months.
This concentration makes the coming years a decisive period. The point is not to replace each nuclear megawatt with a megawatt of a particular technology, but to have a system capable of covering demand in every hour. To achieve this, the growth of solar photovoltaic and wind energy must advance alongside battery storage and pumped-storage hydropower, grid reinforcement, new interconnections and greater demand flexibility.
Almaraz changes the sizing, not the need for a capacity market
The new closure date for Almaraz changes one of the relevant assumptions for sizing the future capacity market. The analyses that justified the need for the mechanism assumed the exit of Almaraz I in 2027 and of Almaraz II in 2028, precisely in a period in which adequacy risks were identified.
Keeping approximately 2 GW of nuclear capacity until June 2030 changes that scenario and may make it necessary to update the capacity requirements before calling the first auctions. The order that authorises the extension of the operation of Almaraz to 2030 itself estimates 7% less generation from combined cycle plants compared with the PNIEC scenario, which confirms that the extension changes the firm generation requirements during those years.
Updating the sizing of the mechanism correctly is necessary, but it should not unnecessarily delay its implementation. The capacity market remains essential to give investment signals to storage, demand management and other resources that will have to provide firmness and flexibility as the nuclear phase-out advances. The Almaraz extension changes the capacity requirements over the coming years, but it does not remove the need to prepare the system for when that firm capacity is no longer available.
Long-term forecasts and storage to prepare for the replacement
In this context, AleaGreen, the AleaSoft Energy Forecasting division specialising in long-term forecasts, provides energy market price curves with horizons of up to 40 years. These forecasts make it possible to analyse nuclear closure scenarios, the evolution of renewable and storage capacity, demand, interconnections and gas and CO2 prices, and to assess their impact on future prices.
For its part, AleaStorage, the division specialising in energy storage, analyses the revenues, the profitability and the sizing of battery and hybrid system projects. The need to reduce curtailment, price volatility and the future capacity market broaden the potential sources of value of storage and reinforce its role as an element of flexibility for the system.
The investment decisions that have to be taken now will determine whether in 2030 there is sufficient integrable renewable capacity, storage and flexibility to face the concentration of nuclear closures without increasing dependence on gas.
Building the new system before retiring the previous one
The Almaraz extension does not by itself solve the challenges of the energy transition. Over the coming years it reduces the potential need for gas-fired generation and the exposure to its volatility, but it also demands better management of the coexistence between nuclear generation and a growing renewable capacity, and it makes it necessary to review the firm capacity requirements that the capacity market will have to cover.
The challenge is to use this margin to accelerate the investments that are already needed: solar photovoltaic, wind energy, batteries and pumped-storage hydropower, grids, interconnections and demand management, together with the implementation of a correctly sized capacity market.
The energy transition will be safer and more competitive if the new system is ready before a significant part of the previous one is retired. The Almaraz extension widens the margin to achieve this. That margin must now be turned into investment.
Source: AleaSoft Energy Forecasting.