This year a combination of wind and sun meant that there were consecutive days when wholesale power prices were negative in several energy markets.
This has been seen in the past, but for shorter periods. In Europe the Internal Energy Market (IEM), which is a ‘frictionless’ network that allows power to be sold across the bloc, has the effect of smoothing out variations in prices, because oversupply in one region allows for power to be sold directly to another region where there is undersupply. This year the negative price phenomenon was more widespread, with record low prices in the Nordic region at the same time because of high water levels in its hydropower system. In April to June, according to market intelligence company EnAppSys, the frequency of negative pricing meant that the average system price was the lowest since the first quarter of 2021 – including a period in May when system prices dropped as low as -£155.20/MWh (EUR180.14/MWh).
This is not a bug in a low-carbon electricity system, but a feature. The low running costs of wind and solar mean customers benefit if maximum use is made of the power they generate on favourable days.
However, the system is not fully able to accommodate such large volumes of low carbon power yet. The IEM has the market mechanisms that allow power to be shared, but the transmission network often reaches its limits when sending that power on to areas of higher demand.
Until more, bigger, cables are installed, some areas find themselves discarding power. It is a regular occurrence in Great Britain, where large-scale generation from windy areas in northern Scotland and the North Sea cannot be exported over the existing, relatively low capacity, links between Scotland and the major demand areas in England and Wales (or across high voltage interconnections with Europe). Wind farm operators with contracts for difference (CfDs – the British mechanism for providing stable prices) are not paid when the wholesale price is negative, giving them an incentive to shut down temporarily. If nuclear experience is anything to go by, wind farms could use this kind of unplanned outage for maintenance. But for offshore wind at least, there is a bottleneck that makes reacting in that way more difficult: the outage also has to coincide with a ‘weather window’ that allows access (and of course by their nature such periods will be on windy days) and both staff and vessels must be available.
In the long term, if there are lots of periods of negative prices, the CfD mechanism will either be agreed at higher prices to cover costs for shorter periods or the market will have to find another source of value for power generated at times of oversupply. This spring, Swedish wind farms also stopped generating during negative price periods, the operators said.
This oversupply is the strong argument for hydrogen and the reason wind and solar companies are investigating electrolysis and long-term storage. It is also the reason why energy system operators and retailers are moving to customer-side options, passing on negative prices to business or domestic customers and asking them to soak up excess power by charging EVs or otherwise turning up demand at zero cost or even credits.
Nuclear in a new market
What do these market dynamics, with regular oversupply, mean for nuclear?
Nuclear’s large volume and always-on nature has always been as much of a management challenge as a benefit. It is predictable, but has always run the risk of tipping the system into oversupply at times (such as overnight) when demand is low. That is one reason it has offered good prices for industrial customers who have a consistently high load to meet.
This is also one reason why nuclear is unlikely to be immediately affected by short-term negative prices. Long term contracts are typically based on seasonal prices years ahead and there are always customers who will value long- term predictable prices. The reference price for the CfD for the UK’s Hinkley Point C power plant is already pegged as a seasonal price (unlike renewables CfDs, which are affected by near-term prices).
However, two aspects of the changing power market will add more pressure on nuclear operators.
Fixed price arrangements and CfDs for nuclear only work if the power plant operator can find a customer for its power. The long-term stability of prices achieved with nuclear was attractive to large users and still is. But electricity supply is changing. Some customers will also have other power sources available, such as rooftop PV. They will need to buy less power and when they do buy it will be on a variable basis to balance the variable supply from their other sources.
Second, more frequent periods of negative pricing on spot markets – and the absence from those markets of customers who prefer to take an active approach to power management –will eventually feed through to depress the price achieved on long-term contracts.
Furthermore, nuclear will have to react to a less predictable power market: power usage curves are currently fairly predictable in broad terms, with low overnight demand and a typical early evening peak. That will change though: if there is high penetration of rooftop solar PV, for example, demand will be at minimum in the middle of the day (this is already common in some areas). And, if there is relatively low wind power production but electric vehicles are charging, demand may be high overnight.
It might be considered that the gas generation sector has already found itself faced with a similar market pressure. Over the last few years large gas-fired power stations have had very low load factors – down from the 60-70% range
to more like 20-30%. Even for efficient plant with the high flexibility needed to respond to volatile prices, that may not be enough to make a return on investment. In the UK market that has driven closure of gas turbines in the 300 MW range (although several remain) in favour of fleets of small gas engines, with multiple units as small as 2 MW. The gas fleet loses economies of size and efficiency, but is more responsive to peaks and has much lower installation costs (using container sized units that could even be moved to a new site if required).
If this sounds like an argument for small modular reactors (SMRs), that may be the case – but much faster deployment will be needed if SMRs are to take that part of the market. Construction for a gas engine array is around 18 months, which means low risk. In the UK, for example, developers do not have to incur build costs until they have underwritten the project with a contract in the Capacity Market, whose auctions are held four years before the delivery year.
Larger reactors above 300 MW would seem to be targetting the market segment that has recently proved so difficult for gas turbines.
All these changes favour cheap, flexible plant. That is not nuclear’s strength, which redoubles the importance of co-locating with large-scale storage or hydrogen production to provide the flexibility not available from the plant itself.
Nuclear retains one advantage that could boost its revenue, and that is its ability to help keep the grid within its frequency and voltage limits. This ‘inertia’ is typically provided by large rotating machinery and where in the past it was a service automatically provided by fossil generators, now it may be contracted by the system operator as a remunerated ancillary service. Revenues are high enough for it to prompt investment in stand- alone facilities such as flywheels or static VAR devices that provide this service. These are the types of revenue opportunity that nuclear must take be ready to advantage of in the future and they should be built in to SMR designs from the start.
