Current View of the Spanish Market
As renewable energy overtakes fossil fuels in EU generation, more hours of negative prices will be expected, eroding the economics of standalone solar projects. The frequency of negative prices is expected to increase as weather-dependent renewables grow.
Spain, with its high solar deployment (50.2 TWh, roughly 18.4% of the country’s electricity generation), has seen an increase in negative prices, resulting in revenue losses for Solar Power Producers and requiring them to curtail production during those periods. Further, the scale of new solar deployment has affected the duck curve, widening the average spread between low and high spot prices and decreasing solar capture prices [1].
According to Red Electricia [2] (Spain’s grid operator) the installed solar capacity has experienced a substantial uplift. From 2022 to 2025, capacity increased by roughly 130%, with an annual growth rate of 25-40% as shown in the Yearly Installed Capacity (Figure 1) [3].
Figure 1: Yearly Installed Capacity for Spain [GW]
As a result, Spain has become a system heavily driven by solar generation. This trend is visible in the diurnal day-ahead profiles across the years.
Normalizing prices by each year’s maximum spot price highlights the midday depression driven by the solar generation.
In 2022, the difference between the lowest and highest prices was approximately 40%; in 2023, 2024, and 2025, respectively, it increased to around 50%, 60%, & 80%.
Figure 2: Normalized Diurnal Day Ahead Spot Price Profiles Across Years
For solar producers, this widening price spread directly erodes capture prices, as prices decline more sharply with peak generation hours. Over the past three years, solar capture prices have fallen sharply from 157 €/MWh to just 38 €/MWh. Over the same period, the gap between the average spot price and the solar capture increased from approximately 10 €/MWh in 2021 to 30 €/MWh in 2025.
Notably, 2025 recorded the lowest solar capture price, despite the average day-ahead price remaining broadly in line with 2024. This indicates further deterioration in prices during high solar production hours, consistent with the normalized spot price profiles shown in Figure 2.
Figure 3: Historical Average Spot Price and Solar Capture Price
Solar downward pressure on prices
The decrease in capture price is linked to increased Solar PV penetration in Spain, according to Red Eléctrica. Solar production grew from around 8% (2021) of total energy generated to 17% (2024). Furthermore, during peak summer months in 2024 solar PV consistently produced between 19%-25% of Spain’s electricity [4].
The downward pressure from solar increased the number of hours during which prices are below or equal to zero [5].
Negative price hours were absent in 2022 and 2023 but rose to approximately 260 hours in 2024, equivalent to 3% of the year. In parallel, zero-price hours increased from 25 in 2022 to 756 in 2024, highlighting a structural shift toward lower spot prices during high-renewable periods.
Comparing 2024 and 2025, the market dynamics intensified further: the share of hours with negative prices doubled from around 3% to 6% of the year, while zero-price hours declined from approximately 8% to 4%, indicating that prices increasingly moved from near-zero levels into negative territory.
Figure 4: Yearly Frequency of Zero and Negative Prices
Negative price patterns
Spot prices below 0 €/MWh are predominantly observed during periods of high solar generation combined with relatively low system demand. From the perspective of solar PV producers, curtailment in both 2024 and 2025 was heavily concentrated in the April to June period. These months are characterized by high solar irradiance, moderate wind, lower demand, elevated hydro reservoir levels following winter rainfall, and limited capacity for exporting to France.
On a monthly basis, generation during negative hours increased from 2024 to 2025. For example, March rose from 0% to 17%, April from 35% to 40%, and November from 0% to 3%. July was the only exception, where negative hours declined from 10% to 4%, reflecting higher seasonal demand and improving system absorption during peak summer months.
Figure 5: Impact of Negative Prices on Monthly Solar Output 2024
Figure 6: Impact of Negative Prices on Monthly Solar Output 2025
There is a significant increase in generation at negative hours in May 2025 compared to May 2024, with approximately 70% of the monthly generation falling into this category. Solar overcapacity does not tell the full story. The increase from 9% to 70% is due to additional factors, including high hydro reservoirs resulting from exceptional rainfall in early 2025. With reservoirs at high capacity, hydro generators pushed the day-ahead market with low bids to avoid spillovers, trying to prioritize dispatch, highlighting a seasonal weather pattern component to the increase in negative prices in 2025 [6].
Examining the diurnal profile in May 2024, the impact is evident in solar production hours. Notably, generation at negative prices increased between 9:00 and 15:00, peaking around 12:00-14:00, during which 20-25% of generation occurred under this price condition. Even though the average spot price during these hours remains above zero, it is important to note that the generation is exposed to zero or negative prices.
Figure 7: Average Diurnal Profile Spot Price and
Solar Generation During Negative Price Hours (May 2024)
Compared to May 2025, an increase is observed. During midday hours, around 10:00 to 14:00, the generation under these conditions rises to approximately 100%, while between 9:00 and 15:00 the percentage remains at or above 70%. Furthermore, there is a significant change in spot price. From 9:00 to 15:00 the average spot price is consistently negative, reinforcing the increase in generation at negative hours.
Figure 8: Average Diurnal Profile Spot Price and
Solar Generation During Negative Price Hours (May 2025)
Comparing the spot prices, the change is significant; midday prices fell into negative territory and nighttime prices between 00:00-06:00 declined by roughly 20 €/MWh in 2025 compared to 2024. Overall, the average spot price decreased throughout most hours, with expectation of the evening at 19:00 where the average price remained around 60 €/MWh.
Figure 9: Occurrence of Negative Price – 0 Prices Not Included [€/MWh]
The trend of lower average prices is also visible when grouping the negative prices.
In 2024, the lowest price was -2 €/MWh, whereas in 2025 it dropped to -15 €/MWh. The frequency increased as well, 152 hours fell between -2 to -15 €/MWh in 2025, compared to 7 hours in 2024, highlighting the rise in negative prices.
A notable case is the blackout in Spain on 28 April 2025, which affected energy prices in May as well. Following this event, the activation of combined-cycle plants increased to stabilize the system, and hydro production rose compared to 2024.
Despite wind and solar output being lower in 2025 compared to 2024 it is important to note that the renewable curtailment in May increased from 1.51% to 2.06%, while demand stayed at similar levels, only increasing by 0.36% in comparison to 2024 [7]. This case highlights the complex interaction between renewable generation and system stability requirements, which influenced both market dispatch and price formation. Solar, wind, and hydro power lower prices during high-renewable hours, while the combined cycle keeps prices high outside those hours. These dynamics likely contributed to increased curtailment and deeper negative price scenarios in May 2025.
Figure 10: Energy Generation in Spain for 2024 and 2025
Negative price patterns
Currently, in Spain, negative price risk is typically borne by the producer. A typical solar asset in the Spanish market would have seen 17% of its production in 2024 fall to zero, with another 7% fall into negative territory. These numbers have only increased in 2025 to 9% of production in zero-price hours and 17% in negative hours. Producers can mitigate these effects through economic curtailment, where it is more beneficial to curtail generation than sell to the spot market.
Comparing cumulative annual solar revenue across years shows a clear downward trend since 2023 [8].
Figure 11: Cumulative Merchant Revenue for Standalone Solar (2023-2025)
Solar merchant revenue in Spain has approximately halved over the three-year period due to the cannibalization of solar, decreasing the capture rate. An interesting pattern is observed between April and June (1), with merchant revenue showing a marginal increase. In 2024, the cumulative merchant revenue increased by 23.37% over these months, whereas in 2025 the increase was 7.34%. In terms of annual merchant revenue this period contributed to 4.15% in 2024 and 2.7% in 2025. This is mainly driven by lower spot prices and the higher occurrence of zero and negative prices.
Economic curtailment power is a palliative solution; a more reliable solution would be hybridization, where a battery can shift energy from low-priced or negative-priced hours into more valuable periods. Therefore, a battery could help hedge some of the losses.
The battery operation can be illustrated with two examples: one for zero and one for negative price hours. The first example showcases how the hybrid system would affect the utilization of solar generation at a zero-price case:
Figure 12: Hybrid System Operation at Zero Price
- The battery charges during low price and discharges at 06:00, during a price peak, before solar production becomes active.
- During solar peak hours, the battery absorbs solar generation that would otherwise have been sold at 0 €/MWh, while any residual solar still flows to the grid if the battery is full [9].
- Battery discharges during the evening, peak capturing a difference of between 70-130 €/MWh. In this example, solar energy priced at 0 €/MWh was shifted to higher-priced hours, thereby increasing revenue.
For a different operational day, additional uplift potential is unlocked during periods of negative prices through the hybrid setup.
Figure 13: Hybrid System Operation at Negative Prices
- Solar is either curtailed or used for charging the battery, as observed at 11:00, and between 14:00 and 16:00. Unlike the zero-price case, the battery is also charged from the grid during 12:00-13:00, even though solar generation is available. This happens because the magnitude of the negative price is sufficient to make grid charging profitable.
- As before the battery shifts the solar energy to more expensive improving revenue.
While these simplified examples illustrate how battery integration can mitigate revenue losses from zero and negative prices at the operational level, they do not quantify the materiality of this benefit to the overall business case. One way to assess the economic significance of hybridization under actual market conditions is to compare merchant revenues using a model-based approach.
Analyzing the one-year merchant revenue Net Present Value (NPV) of a standalone solar versus a hybrid (PV + BESS) configuration, using observed price dynamics from 2024 and 2025, can help quantify the benefits of adding BESS.
These effects become clearer when calculating the one-year merchant revenue NPV[10] for the 2024 and 2025 scenarios (excluding CAPEX, OPEX, and DEVEX for both solar and battery).
Figure 14: One-Year Revenue NPV
For standalone solar, merchant revenue in 2025 is 12.75% lower than in 2024, reflecting the continued deterioration of capture prices under higher solar penetration and increased negative price occurrences.
Introducing a hybrid configuration improves revenues in both years. The uplift is particularly pronounced in 2025. Relative to the 2024 standalone baseline, merchant revenue increases by approximately 85% in 2025, compared to 66% for the 2024 hybrid case.
The stronger revenue performance observed in 2025 is primarily driven by a substantially wider spot price spread, which more than doubled compared to 2024 despite similar average spot prices.
In the hybrid system, increased spread enhances arbitrage opportunities and amplifies the value of shifting energy from low- or negative-priced periods into higher-priced hours.
Figure 15: Average of Daily Spread for 2024 and 2025
While the average spread is higher in 2025, this does not necessarily imply consistently large price differentials throughout the month. A high average price spread can happen inconsistently throughout the month, with a large spread skewing the monthly average. Nevertheless, the substantially higher average spread in 2025 implies stronger arbitrage potential than in 2024, suggesting structurally high market volatility.
While these dynamics highlight increased revenue potential driven by higher spread and volatility, they should not be interpreted in isolation. It is important not to conclude that hybrid systems are inherently superior in all cases. A full investment case must be considered, accounting for development, capital, and operational expenditures, tariff structures, the optimal sizing ratio between solar and battery, and other project-specific considerations.
Predicting both the frequency and magnitude of negative price events remains uncertain due to regulatory changes and variability in weather patterns. To evaluate this uncertainty, a sensitivity analysis can be conducted, introducing two additional scenarios relative to the 2025 baseline case (Scenario A).
Scenario B: Increases the share of negative prices from 6% to 10% with the same patterns as previously observed for specific months and inside the hours of 10:00 – 17:00.
Scenario C: Increase the magnitude of negative prices by a factor of 2 from Scenario B, e.g., lowering the minimum price from -15 to -30 €/MWh.
Figure 16: Impact of Changes in Negative Prices on Merchant Revenue
Introducing the hybrid solar and battery system roughly doubles the merchant revenue across all analyzed scenarios, resulting in an uplift of approximately 113% relative to the standalone baseline.
The annual performance of the stand-alone system remains largely unchanged. Increasing the frequency of negative prices has only a minor downside of -0.41%, as prices simply shift from positive or zero to negative territory. In Scenario C, a higher price magnitude does not materially affect the merchant NPV as the same curtailment volume occurs as in Scenario B.
The results above demonstrate how negative prices and widening prices structurally alter the revenue dynamics of solar assets, and how hybridization can partly offset these effects. However, the objective of this analysis is not to present a full investment-grade business case, but to illustrate the mechanisms through which market behavior translates into economic outcomes.
It is also relevant to note that other countries, such as Germany, apply regulatory mechanisms such as paragraph 51 of the EEG 2023[11] which suspend feed-in payments during negative price periods. This affects the revenue structures of renewable assets and highlights that governments may apply different regulatory frameworks to mitigate the negative price impact.
Conclusion
Spain has experienced rapid solar capacity expansion between 2022 and 2025, leading to increased price cannibalization, a steeper duck curve, and a growing incidence of zero and negative spot prices. These dynamics have materially reduced solar capture prices and increased solar curtailment, particularly during high-irradiance months.
The analysis illustrates that hybridization with battery storage can significantly improve merchant revenues by shifting energy from low- and negative-priced periods into higher-value hours, particularly in an environment of a widening energy price spread, as seen in 2025. Under the modeled assumptions, the value of flexibility increases as volatility rises, even as average spot prices remain broadly stable.
It is important to emphasize that this study is not intended as a full investment case. Key elements such as forward price curves, PPA structures, regulatory frameworks, ancillary service revenues, and optimal PV-to-BESS sizing have been deliberately excluded to maintain focus on first-order market effects. These factors, together with uncertainty in weather patterns and regulatory evolution, can materially influence project economics over the asset lifetime.
The results highlight that capturing value in solar-heavy markets increasingly depends on flexibility, timing, and market exposure. Translating these dynamics into an investment-grade business case, however, required modeling beyond historical spot prices alone.
At Blue Power Partners, we build on analyses such as this by integrating forward-market scenarios, contracting strategies, and operational constraints, enabling project-specific assessments of hybrid configurations under real-world conditions.
Peter Preuss Justesen
Quantitative Analyst
T: +45 31439875
E: ppj@bluepp.dk
[1] https://www.sistemaelectrico-ree.es/en/spanish-electricity-system/generation/total-electricity-generation
[2] https://www.ree.es/en/datos/generation/installed-capacity
[3] Others:Fuel + Gas, Hyroeolian, Renewable waste and Non-renewable waste.
[4] Solar PV takes the lead in Spain’s installed power capacity | Red Eléctrica
[5] Zero prices are counted as day ahead prices below 0.5 €/MWh
[6] Negative power prices in Iberia return after seasonal pause – Timera Energy
[8] Solar production is based on average generation from 2020-2023
[9] Depending on tariff structures
[10] NPV Revenue: (Spot Price * (Solar + BESS Discharge)) – ((Spot price + Tariff) * Bess Charge)
