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Commercialisation des EnR hors soutien : quels enjeux ?
Historically, renewable energy capacities (wind, solar, and run-of-river hydro) have developed through support mechanisms that completely (feed-in tariff) or partially (feed-in premium) shielded them from electricity markets. In these mechanisms, renewable capacity revenues are insensitive to market movements, no matter how volatile. Renewable energy producers do not need to lock in the price of their production in the forward markets because the support mechanism fulfills that role.
However, more and more renewable production assets are now exposed to electricity markets. There are multiple reasons for this.
Older installations are seeing their feed-in tariffs, usually set for a limited duration of 15 years, come to an end. These installations then have to sell the electricity they produce on the markets for the remainder of their technical lifespan, often through an aggregator.
New capacities are also being developed based on long-term PPAs (15-30 years) or through direct sales in the markets, where the price is fixed for only a few years (a maximum of 5 years in France, which is the “horizon” of the market). These options are becoming increasingly attractive for producers, especially in a context where support mechanisms are less appealing compared to market prices and do not keep up with the rising material costs observed in 2022.
This shift away from support mechanisms impacts the responsibilities and risks producers face, as well as how the value of renewable energy assets themselves is assessed. This article explores the various issues related to marketing renewable electricity in the markets.
What is the market value of renewable energy production?
Unlike feed-in tariffs, which evolve infrequently according to regulatory formulas or tender results, electricity prices fluctuate continuously.
To understand what this changes, imagine this scenario: you have a 10 MW wind farm that will produce over the next 5 years, and you haven’t yet fixed the price of this electricity. Since you started reading this article, forward electricity prices may have dropped by 5 euros/MWh (yes, that’s possible—we are in a period of high volatility). You are going to produce something like 1058760*0.211 = 92,418 MWh over these 5 years. The 5-euro movement would thus result in approximately a €460k loss in the value of your asset (this is not entirely accurate, but we will get into the nuances shortly).
The value of renewable electricity is simply the value that a counterparty is willing to offer for a given volume and delivery period. For contracts lasting less than 5 years, this value is primarily affected by market conditions at the time of the sale. If we are not in the case of a long-term PPA, where the market does not quote prices for the portion of the contract beyond 5 years, the value of the electricity sold is simply a function of the price level at the time of the transaction (plus the guarantees of origin that may be sold with the electricity). The cost of producing the electricity matters little.
Electricity is traded in the markets in the form of blocks (i.e., a fixed capacity over a given period), but renewable capacity production has a profile that doesn’t resemble a block. The most characteristic example is solar, which produces more in the summer and less in the winter, more during the day and almost nothing at night (bell curve profile). The value of this production is therefore logically different from a capacity that produces steadily throughout all hours of the year. The sales value per MWh of renewable electricity is thus different from the average market price. What is sometimes called the “capture price” may be higher or lower than the average market price.
When an aggregator buys the production from a park that has exited the feed-in tariff system at a fixed price for a certain period, they will take into account the value of its profile using a forecast of the plant’s production (often based on the historical load curve adjusted for weather variability) multiplied by an HPFC (Hourly Price Forward Curve—we discussed this previously, read this article to learn more). With these forward prices at an hourly granularity, the aggregator can estimate the potential market value of the production and offer a price to the producer.
The capture price can vary significantly between assets, but it mostly differs between production technologies and is dynamic over time.
If we estimate the theoretical market value of French wind production (using normalized 2021 RTE production data to 1 MW) for delivery during 2023-2027, based on the EEX settlement price from May 27, 2022, we get a level of €205/MWh. This is higher than the €198/MWh of a baseload contract over the same period. Why? Well, wind production is generally higher in winter than in summer. Since prices are higher in winter (especially for 2023-2024), the value of the production is also higher.
Valeur de la production éolienne FR source plateforme NOOS
If we perform the same exercise for solar energy, the results are even more pronounced. The value of solar production is €237/MWh, as solar generates primarily during the day, when prices are high. However, this effect is partially offset by the fact that solar produces less in winter, with the Peakload price (delivery from 8 a.m. to 8 p.m.) being significantly higher as a result.
Valeur de la production solaire FR source plateforme NOOS
A small exception should be noted: in 2023-2024, at the prices on May 27, solar production generates more revenue in winter than in summer, despite significantly higher production during the summer season. This is due to extremely high winter Peakload prices (€1013/MWh for the Peakload T1 2023 contract). This is an exceptional phenomenon but interesting in terms of maintenance planning.
Valeur de la production solaire sur 2023 FR source plateforme NOOS
For run-of-river hydropower, production is higher in spring and lower in summer/fall. The value of production for the period 2023-2027 would be €201/MWh.
Valeur de la production hydro FR source plateforme NOOS
It should be noted, however, that the energy crisis has generated "abnormal" summer/winter and peak/off-peak differentials for 2023-2024, which somewhat skews the comparison exercise. If we consider 2027, where the forward price curve is less "peculiar," the value of solar and hydropower is slightly lower than baseload prices, while the value of wind is slightly higher.
Aside from the shape of the profile, the value of renewable energy production is affected by several risk factors. During this period of extreme volatility, these risks significantly reduce the value of the capture price.
The first of these is volume risk. Renewable energy production is inherently variable; depending on weather conditions and availability, the production of a capacity will fluctuate, and its volume can only be accurately predicted over a very short horizon. This horizon is typically only a few hours in advance, whereas to secure its price/revenue, a production volume must be sold years in advance. An aggregator offering a fixed "as-produced" price based on a forward price X will, at the time of delivery, need to buy or sell missing or additional volumes at a price Y (generally in the day-ahead or intraday market when production forecasting becomes more accurate). If the difference between prices X and Y is unfavorable, the aggregator will incur a loss. The existence of volume risk is not dramatic in itself, as after all, the aggregator can also profit if the difference between X and Y is advantageous for them.
However, the issue is that the expectation of volume risk is not necessarily zero. In other words, there may be a correlation between production fluctuations and prices, leading the aggregator to lose more often than they gain. For example, consider a wind farm that produces more than usual at 2 PM today. It is likely not the only one in this situation; indeed, it is probably the entirety of French wind production that will be particularly high at that hour. This additional supply will mechanically lower the price in the spot market (the supply and demand mechanism), thereby reducing the revenue of our wind farm. This negative correlation between volume and price is often referred to by the barbaric term "cannibalization." The more a production technology develops, the more it will impact the market price, and thus the more significant this risk will be. As its penetration into the electrical system increases, the same renewable technology, whose production from different capacities is geographically correlated, will "eat" its own revenues.
One must also consider the cost of the imbalance, which refers to the cost of the difference in volume between the actual forecast at the day-ahead (spot) or intraday market deadline and the actual production. The price of positive imbalances is, on average, lower than the spot price, while the price of negative imbalances is, on average, higher than the spot price. Therefore, forecasting errors are penalized by the grid operator (RTE). Since, regardless of performance, a renewable production forecasting model will always have a non-zero error, there is a cost of imbalances that must be taken into account.
Finally, factors that are not unique to renewables but to the markets can also potentially reduce the price in an aggregator's offer. This is the case with the liquidity of certain delivery periods; as the deadline for transactions moves further from A+1, they become more complicated and costly to execute. The validity period of offers is also a cost factor: the longer the price remains valid, the more risk the aggregator will incorporate into their offer that the price will decline.
Aggregators incorporate these risks into their pricing in the form of risk premiums. They can also, and this is increasingly common, let the producer bear some of these risks by, for example, including volume constraints in their contract.
What challenges do producers face?
Producers operating assets that market their electricity on the markets must therefore ask themselves questions and make decisions of a completely new nature.
Should I set the sale price of my electricity on the futures market or let my production be sold on the spot at a price that will only be known the day before? If I set the price in advance, when is the best time to do so? For what delivery period? What constraints and risks are associated with this pricing?
Monitoring the futures market and implementing a risk management strategy is therefore necessary for producers to protect the value of their assets. Given the extreme volatility of electricity prices, setting a price at the wrong time for several years can lead to significant potential losses. If the producer goes through an aggregator, they should prioritize contracts that allow for price setting at multiple different times to smooth out their selling price and better exploit potential pricing opportunities.
New assets financed by entering into a CPPA (Corporate Power Purchase Agreement) over a duration of 15 years have somewhat different issues. Setting the price of the CPPA is primarily a matter of negotiation, as defining a value for electricity over such a long period is challenging. For deadlines where a market price is quoted, that price will implicitly be used. For subsequent deadlines, a compromise must be found between the full cost of production and everyone's outlook on long-term price trends. However, it is not simple to "speak the same language," and quantitative elements are useful.
What tools are available for producers?
These new challenges lead to a need for new tools for producers. Firstly, it becomes important for producers to track the evolution of the value of their assets based on market prices. This allows them to make investment decisions and, in some cases, to account for the asset (if it has no fixed price and is sold at spot, it is necessary to calculate its "fair value," at least over the period quoted by the market), optimally schedule maintenance periods, or compare the price offered by an aggregator with an internal evaluation.
When concluding a CPPA over a long period, being able to value the part where the price is quoted in the market and simulate scenarios for the non-quoted period is a useful support in negotiations.
It is also necessary to have tools capable of providing decision support for setting the sale price of their production based on market price trends and their risk preferences. Continuously tracking market prices is difficult and not very efficient for a small renewable producer; therefore, using a solution that can automatically monitor market trends and produce recommendations/alerts is necessary.
To establish a budget and optimize cash flow, a producer must also be able to estimate the fixed or potential revenue (if all or part of the production is sold at spot) of their assets over a certain period, as well as calculate their Mark-to-Market (the difference between the fixed price and the current market price). As more and more renewable assets sell their electricity without support and as sales contracts become more complex, having robust tools and clear data will become increasingly valuable for producers.
Augmented Energy offers a suite of innovative solutions for the valuation, optimization, and risk management of renewable assets in the market.
For more information or any further questions, please contact us at the following email address : sales@augmented.energy
