Volatility - a new normal in day-ahead markets
Day-ahead markets are the backbone of electricity trading. In this post, we look at the increasing volatility in these markets. We discuss it through the concept of residual load with a back-to-the-enveloppe calculation for 2030 and we highlight a few consequences.
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It is just the beginning for solar and wind
The EU Commission has just recently revised upwards its target for 2030 by agreeing on the following targets:
The agreement raises the EU's binding renewable target for 2030 to a minimum of 42.5%, up from the current 32% target and almost doubling the existing share of renewable energy in the EU. Negotiators also agreed that the EU would aim to reach 45% of renewables by 2030.
This target is set to be achieved by, amongst other elements, a massive expansion of wind and solar: from a current 255 GW and 209 GW of wind and solar respectively to 510 GW and 592 GW by 2030, according to the REPowerEU plan. As a point of comparison, the total demand in the EU in 2022 was 2809 TWh, or 321 GW on average. Even though electricity demand is likely to increase with the electrification of other sectors, it is worth mentioning that the installed capacity of both wind and solar will soon surpass the average load at the EU level.
This surge of solar and wind energy is not only in Europe but it is worldwide. In 2022, for the first time, wind and solar combined generated more than nuclear.
Balancing Supply and Demand
The Economist published a series of articles recently on the power grid with one of them titled It is harder for new electric grids to balance supply and demand. It is becoming evident that the task to match supply and demand will be increasingly harder with the penetration of intermittent renewable energy such as wind and solar.
Today the nuclear fleet is being shut down and there is more wind and solar on the grid than coal. This means one day may be very unlike the next. In 2021, at 11am on a sunny, windy day in July, the German grid got 72% of its electricity from wind and solar. One month earlier, at 2am on a still night in June, less than 1% of electricity was flowing from the same sources.
In 2021, installed PV and wind were respectively at 64 GW and 58 GW. The four German Transmission System Operators have recently envisaged that Germany in 2037 would have around 210 GW of wind (onshore and offshore) and 345 GW of PV. Storage would entail 90 GW of batteries, together with 25 million electric vehicles. The electricity surplus on a sunny, windy day would be phenomenal, even considering the storage and demand-side response, including the 40 GW of electrolyzers foreseen by 2037.
It is difficult to forecast the future long-term prices of energy, many factors could play a major role. Nevertheless, what is certain is that flexibility would be increasingly rewarded. Different forms of rewards would be present depending on the time horizon:
Hourly. Balancing markets would become increasingly interesting, pushing the demand for grid batteries.
Daily. Market prices in the day-ahead auctions would be marked by strong volatility.
Long-term or interseasonal timeframe. As depicted in the last figure of this post1, hydrogen can play a leading role for such long-term storage.
Let’s dive into the second one. The other ones would be for future posts.
The volatility and the residual load
Let’s look at different EU countries with various exposure to renewable penetration. Hereunder is a graph of prices in Portugal (yellow), Bulgaria (green), and Poland (grey). Portugal, as part of the Iberian peninsula, is currently much more affected by price fluctuation2. These three countries are currently experiencing different stages of volatility in their day-ahead markets.
The concept of the residual load is useful to understand volatility. The residual load is the load minus the wind and solar generation. It is basically the load that should be met by all generation assets besides wind and solar.
In the graph below, the generation from solar and wind are displayed, as well as the load and the residual load. Spain has 29 GW of onshore wind and 18.5 GW of solar. The load in the middle of the day for that particular week (mid-April) is 25 GW. The residual load is therefore highly impacted.
Such a low level of residual load has a direct impact on the prices. Hereunder we have the scatter plot for the prices in Germany compared to the residual load. We observe a clear link between the residual load and the day-ahead prices, with prices going to zero when the residual load is low.
Day-ahead prices are sometimes even negative, especially when some inflexible assets are present.
Negative prices are a price signal on the power wholesale market that occurs when a high inflexible power generation meets low demand. Inflexible power sources can’t be shut down and restarted in a quick and cost-efficient manner. Renewables do count in, as they are dependent on external factors (wind, sun). From EPEX website.
Australia is showing the way
Some parts of Australia have been leading in terms of solar and wind penetration. From the recent Quarterly Energy Dynamics, we observe clearly the volatility in action: for the region South Australia (SA), the average price at 1 PM was negative while it was above 100 AUD/MWh at 6 PM.
From the same report:
Compared to Q1 2022, average operational demand was 324 MW lower (Section 1.1.2). Most of the decrease was observed during daylight hours (Figure 4) driven by a substantial increase in distributed PV. The reduced day time operational demand has meant that lower price offers more frequently set the price, particularly in South Australia and Victoria which experienced negative prices 27% and 24% of the time respectively (see Section 1.2.3).
In the regions where prices are on average negative or very low when the sun is shining, the captured value of solar energy would be low as well. In such a context, the metric LCOE is absolutely not sufficient to assess the economics of solar compared to other technologies.
What will be the residual demand in 2030?
At the EU level, in a relatively good week for renewables and with low demand such as one in mid-April, we observe that the residual load is always above 100 GW. Nevertheless, we also have above 60 GW of nuclear and around 20 GW of run-of-river hydropower, which could be considered inflexible assets3.
Remarkably, we observe that wind is benefiting from some spatial complementary (the wind is generally always blowing somewhere in Europe) but of course, such complementary seems more limited for solar.
Let’s now imagine the situation in 2030: solar will almost triple (from 209 GW to 592 GW) and wind will double (255 GW to 510 GW). By 2030, the EU would have around 1100 GW of wind and solar. Let’s consider the average load of 321 GW in 2022, as well as a potential for 100 GW for new loads (electric cars, heat pumps, electrical storage, etc.). With such numbers, a combined capacity factor of 38% would be enough to crash the residual demand to zero, leading to negative prices most probably as the EU will still have a large fleet of inflexible power plants such as nuclear power (92 GW installed at the end of 2022) and run-of-river hydropower.
Some additional remarks:
What about demand-side response and storage? It is already included as we suggest an increased demand. Of course, we might have greater installed power for storage and demand flexibility but their real use is decreasing fast if the oversupply lasts several hours in a row.
What about interconnections? In the calculation, we are assuming Europe is a copper plate. With the surge of renewable capacity, it is evident that congestion will increase leading to regions with higher volatility.
The increased volatility will have a broad range of consequences. Some will help alleviating the problem, even though it is unclear what will be the extent of their impact4. Here are a few of them:
Storage for energy arbitrage5 will become increasingly attractive. Pumped hydro is particularly well-placed (see the graph below, EA for Energy Arbitrage is in blue, for Pumped Hydro). Batteries are not performing well for that matter.
Demand-side response will also become increagly important. There are already various companies working on developing solutions to displace demand in order to flatten the residual demand.
Together with demand-side response, dynamic tariffs will become the norm. Indeed, fixed tariffs do not incentivize people to consume when power is cheaper. In Nordic countries such as Norway, it is already a reality. Network tariffs might also need to become dynamic in the future, or to be switched to capacity-based only and not energy-based.
Similarly to network tariffs, additional fees that are sometimes part of the electricity bill, such as contribution to support renewables, should not be a fixed price per kWh consumed. Indeed, anything that is added as a fixed rate in EUR/kWh on top of the electricity cost would have a detrimental effect to the flexibility of the load.
The volatility in the market caused by the surge of renewables is going to increase year after year and it will impose us to rethink many aspects of the power sector. Interesting times ahead !
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ST is for seasonal storage. Hydrogen, in green, seems to be particularly well-positioned.
The Iberian peninsula has a relatively high share of renewables compared to other countries and it is less interconnected.
French nuclear power is not completely inflexible as it can produce in load-following mode.
Demand-side response (including dynamic tariff) and storage would be competitive if the market volatility is sufficient. Therefore, they need a certain level of volatility (difficult to say what could be the market equilibrium).
Energy arbitrage is the use of a storage to displace a few hours worth of energy within the same day, typically to displace excess generation during the day to teh evening when the demand is peaking.