More interconnectors, intermittent renewables, rising prices, COVID-19 and Brexit all mean this could be a turbulent energy winter ahead warns Jean-Paul Harreman.
This winter, central and western European (CWE) power markets face more uncertainties than usual. There are many factors impacting on these markets and this will make for an interesting winter ahead.
Due to high interconnectivity, every country will be impacting their neighbours in different ways: nuclear generation availability in France; new offshore wind capacity in the Netherlands and Belgium; new interconnectors commissioning; a potential second COVID-19 wave, Nordic hydro power and Brexit will all contribute to a perfect storm, making this winter more interesting than usual in the CWE region.
The annual uncertainty about nuclear power plant availability started early this year.
France had to switch off some of its nuclear power during the low demand period caused by COVID-19. The maintenance that was needed was delayed due to social distancing requirements while doubts about availability during winter pushed up French forward prices and had a knock-on effect in adjacent markets. or Belgium, around 4500MW (75%) of nuclear power is scheduled to be offline at some point during the next six months. It is unknown if the maintenance periods will be impacted in the same way as in France.
The increase in prices in France – due to the doubts about nuclear availability – had an effect on its interconnector flows over the summer at the macro level and more power flowed from the UK to continental Europe than usual.
As well as the high prices in France, low demand and high renewables in the UK had an impact on this shift. National Grid also had to reverse the flow on the interconnectors to export excess power and manage the British island system for inertia.
This was done via counter-trading with parties on the continent and by reversing the flows that otherwise generally go from the continent to Britain. This resulted in National Grid spending more than £300 million extra on balancing than last year in the same period (as measured by the increased cost of overall balancing services).
The activity intraday on these interconnectors impacted markets in France, Belgium and the Netherlands and this is expected to continue heading into the winter period. As renewable subsidy schemes work differently in the UK, the impact on negative pricing has been considerable, which again is a factor that might affect markets this winter.
Over the next few months, IFA2 (1GW) between France and the UK will be commissioning and ALEGrO (1GW) between Belgium and Germany will go live, as well as new interconnectors between France and Belgium.
The arrival of new interconnectors means that Britain and the countries in CWE are going to be influencing each other more and more, meaning that market participants will need to increasingly start understanding a larger more interconnected system, rather than a more simple, isolated single market. The impact of any issues during the commissioning of these interconnectors should also not be discounted, as failures on new interconnectors are common. These could potentially lead to unexpected price excursions upwards and downwards as the TSO reacts to losing a GW of demand all at once.
In the Netherlands, new offshore wind capacity is coming online in the autumn (700-1400MW). Along with the transport issues that have been causing volatility in the Netherlands over the years, this adds another layer of complexity.
HIGHER BALANCING COSTS AND CUSTOMER PAYMENT DIFFICULTIES COULD LEAD TO SOME ENERGY SUPPLIERS FAILING
The Dutch market can be complicated by transparency issues as far as live renewables data is concerned, so market parties can often be in the dark as to what is going to be happening in the market, particularly the reasonably small 500MW balancing market.
Belgium has also seen new wind farms, with three new offshore wind farms going live during 2020; these will affect markets now that windy weather has started to arrive.
Weekends may see very low downward flexibility in the low countries due to this growth in wind generation.
It is uncertain how quickly the rate of energy consumption will recover. A potential second wave of infections looms over the markets as bankruptcies and an economic downturn start to have a negative effect on electricity demand.
Higher balancing costs and customer payment difficulties could lead to some energy suppliers failing. Most energy regulators in Europe are aware of these systemic problems and have taken action to push certain costs into the future or be more tolerant of suppliers that are struggling.
During the first wave of infections and lockdowns, we have seen very low output for coal and lignite plants in Germany. If demand should drop again, this will push many conventional power stations out-of-merit for prolonged periods, especially during high wind periods and weekends.
Coal and lignite generation might run at minimum output for significant periods as a complete shutdown bears the risk of start up failure risks and a loss of spinning reserve in the market for the system operator to use to manage short-term frequency requirements.
These sorts of issues could create new and previously unseen challenges for market operators who may not be able to use the normal market playbooks in such unusual times.
With conventional power stations running at low levels, their ability to provide flexibility diminishes significantly. With low demand and high renewables, the intermittency of renewables – if uncorrected – could wreak havoc on the balancing markets, the scarce flexibility being priced at a premium.
This in combination with low baseload prices due to high renewables forecasts, is a recipe for high prices in ancillary services and balancing markets. This will provide opportunities for those who truly understand cross-border influences or have flexible assets at their disposal, such as efficient combined cycle gas turbine plants or peakers.
It has been very wet and lower demand means that as we approach the end of the summer the reservoirs in the Nordics are full. With prices in Norway and Sweden at super low levels, a wet autumn has the potential to wash low power prices through markets connected to Norway and Sweden.
Interconnectors from these markets have been built over recent years and as the Nordics build wind the flexibility of its hydro resources has allowed these countries to export their water power into CWE. If we have a wet autumn, then the Nordics will be flowing power baseload into the continent at super low prices for an extended period of time.
On 1 January 2021, the UK will exit the transition period after Brexit and Britain will leave the European Internal Energy Market. This means that the day-ahead market coupling that has been active will, as it stands, disappear.
Parties will have to start trading over the interconnectors themselves as explicit auctions force them to better understand the fundamentals of the UK and EU markets.
In total, 5GW of interconnectors will be auctioned in this way: 3GW from France, 1GW from the Netherlands and 1GW from Belgium. Market participants will have to adjust to the new rules (explicit auctions, instead of market coupling) and learn how to get the best value from their capacity purchases at the day ahead and actively trade on each side of the interconnector.
This way of trading is less efficient and will have an effect on Britain and the two smaller Belgian and Dutch power markets as the size of the interconnectors has a big impact.
Sub-optimal dispatch decisions by the traded market could result in more interventions by the TSOs to prevent large interconnector swings, providing further commercial opportunities for participants.
In summary, this winter is more uncertain than any before, driven by the unexpected effects of the coronavirus on all markets, extra renewables causing higher swings in price as offshore wind is built out, commissioning new interconnectors between markets, too much water in the Nordics putting a dampener on the baseload market and Brexit creating new market arrangements for moving power across the interconnectors to and from GB.
More now than ever, electricity market participants need to know their own market but also how their adjacent markets and beyond react to the weather, market rules and capacity constraints on the interconnections between markets. This winter will be testing for the CWE region and will create many case studies for the energy transition.
About the author
Jean-Paul Harreman is director of energy market data at EnAppSys BV, a provider of data, consultancy and information services to companies in the energy and power generation markets.