Europe has now lived through two energy crises in four years, and on the surface the second looks like a smaller copy of the first. In Spain, Germany and Greece, day-ahead prices rose in both, and in each case the shock followed a war that began in late February. Underneath, the two crises played out very differently across the day. In the months after the 2022 invasion of Ukraine, the cheapest hour of the average day still cost €149 ($165.6)/MWh in Spain, €193/MWh in Germany and €252/MWh in Greece. Between March and September 2026, front-month TTF averaged roughly €54/MWh, about half as much again as in the same months of 2025, which puts the fuel cost of a gas plant running at 55% efficiency near €97/MWh before carbon. Yet averaged over the 2026 window, the cheapest hour of the day fell to between €16/MWh and €25/MWh in all three markets, far below what any gas plant needed to run, while night prices rose by €36 to €51/MWh against the same dates in 2025.
That difference is consistent with the much larger solar fleet that sits between the two shocks. Average output in the peak solar hour doubled in Spain and Greece between the 2022 and 2026 windows and rose by half in Germany, and prices in the hours that output covers moved far less with fuel prices than they did four years ago. This analysis asks what that larger fleet means for energy security: how much of the day now stays clear of crisis prices, why that stops at sunset, and how far battery storage could carry it into the evening and night. To answer it, the comparison uses two event windows of identical length. The first runs for 227 days from the invasion of Ukraine on 24 February 2022 to 8 October 2022, and the second for 227 days from the start of the war with Iran on 28 February 2026 to 12 October. Both open in late February, so day N of each crisis falls in nearly the same week of the year, and each contains 21,788 quarter-hour price intervals. The same calendar dates in 2025 serve as a reference without an energy crisis.
Midday output doubled in Spain and Greece
Far more solar was running when the second shock arrived. Solar output reported to ENTSO-E over the 227-day window rose from 23.8 TWh in 2022 to 49.4 TWh in 2026 in Spain, from 48.5 TWh to 74.7 TWh in Germany and from 4.7 TWh to 10.0 TWh in Greece. In the average hour of peak output, Spanish solar delivered 21.2 GW against 10.8 GW in 2022, German solar 39.8 GW against 26.5 GW and Greek solar 5.2 GW against 2.7 GW.
Figure 1. Average solar output by local hour over the first 227 days of each crisis and the same dates in 2025. Author’s aggregation from ENTSO-E data.
That output arrives in a narrow band. In the 2026 window, 66% of Spanish solar energy and 75% of German and Greek solar energy was produced between 10:00 and 17:00. On a full-year basis, ENTSO-E solar output rose from 31.1 TWh in 2022 to 52.4 TWh in 2025 in Spain, from 55.7 TWh to 73.8 TWh in Germany and from 6.3 TWh to 11.5 TWh in Greece.
Where the shock landed
In the 2022 window, prices were high in every hour. Front-month TTF averaged roughly €155/MWh between March and September 2022, and even the cheapest hour of the average day stayed at €149/MWh or more in all three markets. In the 2026 window the same markets produced a deep midday trough, and the average day stayed below €50/MWh from 10:00 to 18:00 in Spain, from 10:00 to 17:00 in Greece and from 11:00 to 16:00 in Germany.
Figure 2. Average day-ahead price by local hour, first 227 days of each crisis and the same dates in 2025. Author’s aggregation from ENTSO-E data.
Set against 2025, Spanish prices between 10:00 and 17:00 averaged €22/MWh, about €5 above the same hours a year earlier, while evening prices between 19:00 and 23:00 were €44/MWh higher and night prices between midnight and 06:00 about €50/MWh higher. The seven midday hours make up 29% of the day but contributed 4% of the rise in Spain’s baseload price and 13% in Germany. In Greece the midday block was €4/MWh cheaper than a year earlier, while night prices rose by €46/MWh.
Figure 3. Change in average day-ahead price by local hour, 2026 crisis window minus the same dates in 2025. Author’s aggregation from ENTSO-E data.
Gas prices are consistent with this shape. Monthly TTF closes rose from about €31/MWh in February 2026 to about €84/MWh by 12 October, and even the lowest price from March onwards, around €38/MWh in April, implies a fuel cost of roughly €70/MWh for a gas plant. The cheapest hours of the average day, at €16 to €25/MWh, and the 10:00 to 17:00 averages of €22 to €45/MWh sit well below that cost, so these hours show little sign of the fuel shock. The increase appeared instead in the hours solar cannot reach, where night and evening averages of €116 to €178/MWh sit above the €97/MWh average fuel cost of a gas plant. The ENTSO-E data do not name the price-setting plant in each interval, so this reading rests on price levels and timing.
Negative prices show how far the midday has moved. The 2022 window had none in Spain or Greece and 32 hours in Germany. The 2026 window had 547 hours in Spain, 459 in Germany and 476 in Greece, and between 19% and 23% of solar output in each market was produced while prices were below zero.
Solar’s revenue fell on two counts
Capture prices in the 2026 window are 74% lower than in 2022 in Spain, 76% lower in Germany and 83% lower in Greece, and capture rates are between 36 and 48 percentage points lower. Both the level and the shape of prices changed. Splitting the fall in the capture price between the two on a logarithmic basis, the lower baseload accounts for 55% of the decline in Spain, 62% in Germany and 57% in Greece, and the weaker relative value of the solar profile accounts for the rest.
Figure 4. Solar capture price and capture rate over the matched 227-day windows and the 2025 reference. Author’s aggregation from ENTSO-E data.
The 2025 reference shows that most of the relative decline was already in place before the new crisis. Over the same dates last year, solar’s capture rate was already 52% in Spain, 47% in Germany and 52% in Greece. Against that reference, the 2026 window was 5.6 points lower in Spain and 9.4 points lower in Greece, and 2.7 points higher in Germany. On a full-year basis the decline is steady: Spain’s capture rate fell from 90% in 2022 to 55% in 2025, Germany’s from 94% to 51% and Greece’s from 94% to 58%.
Another way to read the result is to ask how much of each euro added to the baseload price reached solar. Between the 2025 reference and the 2026 window, Spanish solar captured 37 cents of each extra euro and German solar 57 cents. Greek solar captured almost nothing over the full window: its capture price from March to June fell from €49/MWh to €33/MWh, in months with 285 negative-price hours against 12 a year earlier, which offset its summer gains. Monthly baseload prices stayed more than 10% above their 2025 levels in every month from May in Germany, July in Spain and August in Greece, while gas climbed from a monthly average of about €46/MWh in June to about €74/MWh in September. From July to 12 October, the costliest stretch of the window, solar captured 41 cents of each extra euro in Spain, 45 in Germany and 32 in Greece. Germany is the exception in the matched comparison. Its capture rate rose slightly against 2025 even though solar output in the window grew by 18%, and its negative-price hours fell from 548 to 459.
Is the second crisis simply milder?
In September, Spain’s day-ahead market averaged €143/MWh, slightly above the €141/MWh of September 2022, yet Spanish solar earned €66/MWh against €116/MWh four years earlier, and its capture rate fell from 82% to 46%. The obvious objection is that the second crisis is simply milder, and it is fair as far as it goes: TTF averaged roughly €54/MWh between March and September 2026 against roughly €155/MWh in the same months of 2022, baseload prices in the three markets are less than half their 2022 levels, and a smaller fuel shock leaves a smaller premium to spread across the day. The September comparison, however, holds the baseload almost constant and still shows solar earning 43% less than four years ago. With the baseload almost equal, the difference shows up in the shape of the day.
Figure 5. Spain, monthly baseload and solar capture price, January 2022 to 12 October 2026. Author’s aggregation from ENTSO-E data.
Moving noon into the night
The same shape that cuts solar’s capture rate creates the trade for storage. On the average day of the 2026 window, a battery charging in Spain’s two cheapest consecutive hours would have paid about €16/MWh and one discharging in the two dearest would have sold at about €147/MWh, a spread of €131/MWh against €88/MWh over the same dates in 2025. In Germany the spread widened from €123/MWh to €161/MWh, while in Greece, where evening prices were already high in 2025, it moved from €150/MWh to €157/MWh.
Figure 6. Spread between the two dearest and the two cheapest consecutive hours of the average day, by window. Illustrative, before losses. Author’s aggregation from ENTSO-E data.
The volume waiting to be moved is large. Across the three markets, solar output produced while prices were negative in the 2026 window averaged about 128 GWh a day. Every megawatt-hour shifted from those hours into the evening would work on both sides of the problem: it would add demand in hours when prices are below zero, which would support the capture price, and it would add supply in the night and evening hours where the 2026 price rise was concentrated. The spreads above come from averaged profiles rather than a dispatch model, so they leave out round-trip losses and day-to-day variation, and each new battery narrows the spread the next one earns.
What it means
For the energy trilemma, the data point the same way. In the hours solar covers, prices stayed far below the rest of the day through this gas shock, which serves decarbonisation and part of affordability. Extending that to the whole day, and reducing exposure to the next gas shock, would mean carrying part of that midday energy into the evening and the night, the hours where prices tracked the gas shock, and solar paired with storage is a direct way to do it. Contracts and support schemes that value the profile a plant delivers rather than its raw output, and grid connections shared between solar and batteries, could push investment that way.
Four years ago, solar hedged its owner against a crisis that reached every hour of the day. In 2026 the hours the fleet covers stayed largely insulated from the gas shock, a protection the baseload average hides because it blends noon with midnight. The next step is to carry that protection past sunset.
Author: Safa Sen, Market Engagement Lead For CWE at WSP.
WSP Group unites engineering, advisory and science-based expertise to shape communities to advance humanity. From local beginnings to a globe-spanning presence today, it operates in over 50 countries and provides solutions and delivers innovative projects across sectors: Transport & Infrastructure, Property & Buildings, Earth & Environment, Water, Power & Energy and Mining & Metals.
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