Decoding Curtailment Clauses in PPAs
Negative pricing is on the rise
Historically when counterparties discussed the “curtailment” clause in PPAs they were thinking about involuntary, grid curtailment, which happened when there were outages or constraints on the grid. It has fast risen up the chain of priority topics in a PPA negotiation due to (a) a more constrained grid pretty much everywhere; and (b) the rise of zero or negative priced hours (on the Day Ahead Market), being the market-driven or voluntary leg of curtailment. This means that without any protection, the generator will either be forced to curtail without compensation and / or may be required to pay to generate.
In this post I set out what curtailment and negative pricing is and how to address it in PPAs now that it has become a key commercial topic, impacting the profitability of a transaction.
What is curtailment?
Curtailment occurs when a renewable energy project, such as a wind or solar plant, is forced to reduce or stop electricity generation due to grid constraints, oversupply, or negative pricing. In the context of a PPA, curtailment risk affects both the seller and buyer, as it can impact revenue certainty, contractual obligations, and the overall economics of the deal.
Curtailment will typically occur in grids that have higher penetration of renewable energy, because when the weather conditions align all renewable energy plants will generate simultaneously, causing physical constraints on the grid, particularly in congested areas (known as nodes). This phenomenon is exacerbated where specific areas host a disproportionate number of wind / solar farms, such as Scotland, West Texas and Central-Western Spain (for solar). In such cases there are delays in expanding the transmission network.
In terms of figures to demonstrate the severity of the issue:
in Germany curtailment of renewable energy plants nearly doubled between 2022 and 2023 to 10.5 TWh and in 2024, Germany experienced 457 hours of negative wholesale electricity prices (just over 5% of all hours), an increase from 301 hours in 2023;
in GB, negative prices were first recorded in 2022, with 19 hours, increasing dramatically to 139 in 2024; and
Spain recorded its first negative day-ahead prices as recently as April 2024, with 247 negative-price hours occurring subsequently that year while zero-priced hours have also a significant increase, rising from 122 instances in 2023 to nearly 530 in 2024.
Italy remains an outlier among its peers, as it is much more gas reliant and has lower GWs of installed wind and solar power, meaning that such events have not yet happened there.
How curtailment impacts PPAs
Let’s distinguish between physical and financial PPAs. Physical (or balancing) PPAs or better known as Route to Market Agreements (RtMAs), will typically pass through revenue to the generator on a Pay as Produced basis. This means that when there are curtailments, the RtMA will not guarantee any revenue to the generator. That said, where there are involuntary curtailments due to grid outages and constraints depending on the market rules, the generators may receive compensation from grid operators. This does not apply to negative pricing.
In financial PPAs there is no single position, and it’s up to the parties to determine how curtailment and negative pricing is regulated. Historically, parties focused only on involuntary grid curtailments, with negative pricing either being unregulated or added into the PPA without much thought.
Curtailment and Negative Price Clauses in PPAs: Risk Allocation and Key Negotiation Points
Curtailment
In Pay as Produced fixed price PPAs, common in GB and France, curtailment risks were borne by the buyer as in such PPAs there was no volume guarantee. In the event of negative prices (which were not at the forefront of the parties’ minds) the seller would continue receiving the fixed price.
In pure financial PPAs, it’s almost always the case that there is an availability guarantee or a volume guarantee. With both types of guarantee, it will typically be negotiated what is included in the formula, with the excluded hours / time being a topic of contention. Here is where the buyer will want to limit the types of curtailments to be excluded whereas the seller will want the opposite. A balanced position is including outages within the Seller’s control and excluding grid outages caused or directed by the TSO. Another approach is to be more generous with the definition of what’s excluded but subject to a reasonable cap on hours.
Negative Prices
There are three main options, it’s a seller risk so the seller can decide to stop generating during periods of negative prices; it’s a buyer risk so the fixed price is paid against the actual (i.e. negative floating price); or a hybrid solution, most commonly the zero floor price, is agreed.
Taking each of these in turn and assuming a vanilla fixed for floating swap (we’ll do a post on different pricing structures in fPPAs soon), a seller risk could have worked in the past or still works in markets where zero and negative prices are not a major feature. As a generator I’d be uncomfortable agreeing this position under a long term fPPA as it leaves you significantly exposed were negative pricing hours to unforeseeably rise (beyond what’s in your financial model). The second option is too seller friendly as it would mean that if the floating price was -10 the buyer would have to pay an additional 10 to the Seller over and above the fixed priced. I cannot see a well advised buyer agreeing to it, at least under a long term PPA.
The third option (zero floor price) is probably the most prevalent approach at the moment, as is also evidenced by the position adopted in the ISDA’s new fPPA template confirmation (available here). This is agreeing a floor price, probably at 0. When prices hit negative, the settlement converts that negative number into 0 (or another number agreed on) so that the Seller will receive only the fixed price. There are other hybrid approaches for risk sharing, such as agreeing caps on the number of negative price periods a Buyer will pay the fixed price.
It’s worth mentioning that the approach may also depend on the type of offtaker, utility / trader v corporate. Utilities are better placed to manage negative price risks and may absorb it, in exchange for a lower fixed price. Corporates will not want to be paying for negative prices and a hybrid solution to risk sharing (such as the 0 floor price) is more common now.
Conclusion
This problem is not going away anytime soon. In fact, together with lower capture prices for wind and solar, curtailment and negative prices will cause serious headaches to operators of renewables in Europe. The only light on the horizon comes from the large pipeline of storage which seems to be growing in most European markets. New mechanisms in Italy, Spain, Greece and other markets should act as a catalyst. Increased storage capacity enables renewables to shift generation to higher-priced periods, reducing the frequency of negative pricing events.