How market and technology differences shape outcomes, from Spanish Solar to Finnish wind.
In our previous piece, we discussed the issue of negative prices and how market participants typically handle this risk in PPAs. In this article, we aim to highlight how different markets and technologies are impacted, while also offering a glimpse into how the future could look.
The way negative prices are experienced vary significantly across markets and technologies, with players in each region responding according to local conditions:
- Spain: Throughout 2024, Spain has seen its first instances of negative prices, with a total of 224 negative-price hours recorded so far. Low demand and record-high renewable generation on the Iberian Peninsula in the first 8 months of the year have contributed to this. In Spain, currently negative price risk is typically taken by the producer. This of course affects project bankability, but the consensus (until now) among Spanish market actors including banks and market advisors is that negative prices will be limited, so this risk is so far accepted in project finance schemes.
Pexapark analysis of exchange and ENTSO-E data showed a typical solar asset in the Spanish market would have seen 15% of its production from January to end of August this year fall into zero-priced hours, with another 10% of production falling into negative territory. This means that a total of 25% of this year’s as-produced PPA generation could be at loss for producers, depending on the negative price clauses set in their PPAs.
- Germany: In Germany, negative price risk sat firmly with the buyer until 1-1.5 years ago. However, with negative-price hours in H1 2024 already surpassing last year’s record, and Germany becoming more of a buyer’s market, the negative price risk is now being shifted toward the seller, with buyers wanting to offload some or all of this risk. Although German PPAs that fully cover the negative price risk are still being signed, a risk-sharing approach has become increasingly common.
In the first 8 months of this year, up to 23% of the production of a typical German solar asset fell into negative or zero-price hours in Germany, according to Pexapark figures. The bulk of these were negative-price hours, with zero-priced hours making up 2% only.
- Finland: The Nordic market retains its top spot in Europe as the country with the greatest number of negative hours, so far, 520 negative prices were recorded in 2024 (versus 201 in 2023 year to date). Although negative-price hours are common in the market, with around 16% of production of a typical Finnish onshore wind park falling into negative or zero-priced hours this year, the prices themselves don’t drop significantly. During 2024-to date, negative-price hours averaged around -1.98 EUR/MWh, meaning that merchant assets can still have a positive revenue from the sale of GoOs during these hours. This provides the opportunity for corporates that hold greater value for “green” electricity to delay curtailment until the negative GoO price is reached.
- Italy: To date, there have been no negative prices in the Italian market, but sellers and utilities active across borders are bringing these discussions into Italian PPAs.
Outlook for the Future
Market participants generally agree that the risk of negative prices will likely get worse before it improves. As renewable energy capacity grows, especially in markets with limited grid flexibility, oversupply during low-demand periods will increase, causing more frequent negative-price events. At the same time, most EU support schemes are tightening rules around negative-price hours. For example, Germany’s proposed EEG reforms from 1 January 2025 will prevent new assets from receiving compensation during these hours. However, with many legacy assets still under the old rules, the full impact may take time to materialize.
Opinions vary on how serious the situation could become, with market participants holding different views on the future of negative prices. While improvements in grid infrastructure, storage, and market reforms like flexible tariffs are expected to help, these changes will take time to implement. In the meantime, PPA participants must manage the risks of negative prices and find fair ways to allocate risks that support continued investment in renewables.
What constitutes a fair allocation and what is considered ‘standard’ will become clearer in the coming months as lenders, sellers, and buyers work to find agreeable solutions. For physical PPAs claiming additionality, the lack of financial compensation during negative-price hours could weaken the investment case for renewables, going against the corporate’s original intent. A fair approach might involve partial or full compensation when the asset is curtailed, ensuring it doesn’t exacerbate the situation.
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