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Pablo Caballero
Aug 10, 2026
This summer, wildfires and heatwaves are affecting large areas of Europe. Beyond their well-known impacts on nature and human well-being, weather anomalies and extreme events are constantly challenging the results of regular performance reporting on PV assets around the world.
On top of that, a total solar eclipse, set to happen in just a few days, deserves attention too: totality will cross Greenland, touch a small part of Iceland, and go across the north of mainland Spain up to the Balearics.
Unusually high temperature trends are affecting several countries in Europe this summer. The effect of temperature on PV cells is well known: crystalline silicon modules lose a certain percentage of output per degree of cell temperature above 25°C. In addition to air temperature, wind speed and solar irradiance are the main factors influencing cell energy conversion efficiency.
High temperatures affect plant performance beyond cell efficiency, too. Inverters reduce their power output when internal or ambient temperatures exceed safe thresholds, a process known as thermal derating. Meanwhile, transformer and cable losses rise with heat as well.
Fig. 1. For a sample site near Soria, Spain, daily maximum air temperature at 2m reached 37.5°C at 3pm UTC on 22 July 2026, according to the ERA5 model, reaching the absolute maximum registered by the model. The three heatwaves that hit Spain during July are also noticeable in the monthly graph. According to the Spanish Meteorological Agency (AEMET), a "heatwave" is defined as an episode of at least three consecutive days in which at least 10% of the stations considered record maximum temperatures above the 95th percentile of their series of daily maximum temperatures for July and August over the reference period 1971–2000. Source: Solargis Livemaps.
July 2026 produced two of Spain's largest-ever fires: one starting 16 July near La Mierla (Guadalajara), which burned around 30,000 ha, and one starting 22 July near Burgohondo (Ávila), which spread into Madrid and Toledo and burned around 50,000 ha. A separate wildfire near Bordeaux, France, burning more than 70,000 ha, was the country's largest since 1949.
For a plant affected by the smoke, what matters is how much smoke passed overhead, even if the fire itself was far away. Smoke travels, and its effect on incident irradiance can be tracked through Aerosol Optical Depth (AOD).
This effect can be clearly seen by looking at DNIc, direct normal irradiance under clear-sky conditions (one of the standard outputs of solar irradiance models). A rise in AOD usually shows up as a drop in DNIc, even without any cloud cover.
Ash deposition adds a second effect by increasing soiling losses. PV plant on-site pyranometers are also affected by soiling, which makes it harder to identify performance drops caused by this.
Fig. 2. For the sample site near Soria, Spain, AOD at 670 nm reached more than 0.5 on the same day (22 July 2026 at 3pm UTC), according to the CAMS model. DNIc July series show a noticeable drop that day too. Although the presence of aerosols coming from Sahara deserts can be quite common in Southern Europe during summer, the AOD map for the sample site on this particular day shows a highly localized plume covering the surrounding area, very likely connected to the active wildfire in Guadalajara. Source: Solargis Livemaps.
On the evening of Wednesday, 12 August, a total eclipse will cross the Northern Hemisphere. It will be especially significant for PV plants in Spain, where the share of solar energy in the grid is high: the totality band crosses the country from Galicia to the Balearics, with totality around 20:27–20:33. This will be the first total eclipse visible from mainland Spain since 1905. Other PV plants across Europe will notice the event too, where it will appear as a partial eclipse.
During the eclipse, irradiance dips smoothly and recovers symmetrically. Its depth and shape can be computed years in advance. That said, in the case of 12 August, the energy loss at stake is relatively small, since totality will coincide with the sun being close to sunset, when output is already low. Still, it needs to be accounted for, so the dip is attributed correctly rather than mistaken for an operational issue or attributed to other resource-driven parts of the accounted loss.
Fig. 3. Areas of the Earth from which the August 12, 2026, eclipse will be visible. The light-shaded region corresponds to partial eclipse visibility, whereas the dark band indicates where the eclipse will be total (the previous sample site located in Soria and shown in this article is under this band as well). Source: Spanish Geography Institute, IGN.
Fig. 4. Reference case: GHI irradiance during 8 April 2024 North American solar total eclipse near Dallas, US. A round spot caused by the eclipse is observed on the map. When looking at GHIc monthly series, a drop of similar shape is expected on 12 August 2026, though towards sunset and with less impact on total irradiance. Source: Solargis Livemaps.
Every monthly PV performance report starts with the same comparison: measured production against expected production. When both are closely aligned, no questions are asked. But when there is a gap, there is also a "story" behind it that needs to be found.
In practice, "expected production" carries two different meanings depending on the benchmark used to set expectations.
Asset managers need to take a closer look at expected yield for the specific reported period. They need to recalculate the expected production using the actual irradiance, aerosols, temperature, and wind recorded that month. Their key question is: given what the resource actually did, is the plant performing as it should? Sometimes other questions follow: are on-site sensors tracking actual weather trends, or do they need cleaning, calibration, etc.?
Owners and investors, on the other hand, have in mind the numbers from the yield report: the long-term P50 established at financial close. Their key question is: are we on budget for the year? This also raises a further question: do we need to reevaluate our long-term expectations based on updated solar resource data?
Indeed, every regular performance report is an opportunity to update the PV plant's digital model and close the gap between design and reality. Since a useful comparison is only possible when the PV plant model reflects actual plant conditions, re-running simulations adds valuable insight for future reporting. In practice, re-simulating means updating the two main sides of PV software inputs:
Although heatwaves, wildfires, and eclipses are events of a different nature, they reach the report in the same way: each can be "the story" behind a gap between measured and expected production.
To assess their influence, gaps need to be studied by separating the resource-driven part from the grid-driven and plant-driven parts. For the events described in this article that are happening this summer in Europe, that means drawing on at least these additional references:
To cover this data need, it's important to turn to the right sources. A simulation built on the plant's own sensors is only as credible as those sensors, and it's precisely during extreme events like these that their reliability is most in question: a soiled pyranometer or a heat-stressed weather station is never a trustworthy reference on its own.
Solargis satellite-based irradiance models and reanalysis weather products solve this by construction: they come from an independent source and provide the same numbers consistently. They are continuously updated with new inputs, which makes regular reporting of key metrics possible. Although their resolution is coarser than a point sensor, they reliably capture the trend: a heatwave's daily curve, a rise and fall in AOD, or an eclipse's timing and depth.
Most PV plants are built to withstand future heatwaves, wildfires, and eclipse events. The real question is whether the reports that follow such events can tell stakeholders what actually happened, and what they should expect from now on.
