This article first appeared in Utility Week
Imports from the Continent have long been a staple feature of UK energy supply, but over the past few weeks there has been a dramatic shift in energy flow across the French interconnector. In October, exports have been running at an average 0.2 GW per day, compared to imports of 1.3 GW in the same month last year. In total, October has seen 19 days of net energy export compared to a previous maximum of two days since 2014.
Given relatively low capacity margins, this raises questions about whether our dependence on the interconnector represents a threat, particularly with Brexit imminent. Conversely, could the prospect of energy exports to the Continent actually help approvals for power plant in the UK and provide a potential market?
The primary cause of the change is outages in the French nuclear fleet. In June, the French Nuclear Safety Authority (ASN) raised potential safety issues at 13 reactors, which were subsequently closed for repairs. This closed 13GW of capacity, accounting for 12% of total installed capacity in France. Further shutdowns have been required and despite some returns, 11% of total installed French electricity capacity is still offline.
Does this represent a threat, or is there sufficient capacity to absorb the shortages?
In terms of price, the change in flows has resulted in a significant rise in GB market prices. On 24 and 25 October, day ahead prices were above £70/MWh. This is the first time there have been consecutive days above £70/MWh since March 2013. Hourly prices have also seen a level of volatility far greater than in recent years. Since 1 September hourly prices have exceeded £180/MWh on 17 occasions whereas in the previous year, that level was only reached twice. As we go into the winter, it looks increasingly likely that market prices will be quite unlike those seen in recent times.
In terms of capacity, National Grid’s Winter Outlook projects a capacity margin of 6.6%. However, this assumes 2.5GW imports and includes 3.5GW of supplemental balancing reserve (SBR). If we cannot rely on the imports from France, then the margin without the SBR is -3.1%. The impact of tight margins has already been seen in that National Grid issued their first ever Capacity Market Notice (CMN) on 31 October less than one month after the commencement of the Electricity Capacity Market. The SBR in turn could have an effect on price. There is some ambiguity around market rules but in theory, if the SBR capacity is utilised, the imbalance price will be set at £3000/MWh. This price ceiling could well filter into day ahead pricing as participants aim to avoid substantive imbalance cost during hours of supply shortage.
It is possible that this will prove to have been a ‘one-off’ incident. However, the outages do highlight the potentially ongoing challenge France faces from its mature facilities and delays with new build. This then raises the question of what will happen after Brexit if we see similar shortages. If the UK does not remain part of the Integrated Energy Market (IEM), it is not clear what the supply priorities would be and whether the UK could depend on energy through the interconnector.
Alongside these potential threats to supply are possible opportunities. Is there an opportunity for UK generation? Do these issues, aligned to a low value of sterling, provide export opportunities?
For the owners of generation assets which sell their power into the wholesale market, the recent high market prices and volatility represent an opportunity for highly profitable generation. Base load plant is able to command a significant profit and peaking plants which are not usually required to generate have been called into action.
Relatively stable prices in recent years, with few high priced periods, has led to a degree of pessimism amongst investors regarding the profitability of wholesale generation in GB. While the recent market prices are due to a temporary series of events, they do demonstrate the vulnerability of the GB market and the opportunity for wholesale generators.
In terms of export, much has been made generally of the potential benefits of a lower GBP. Could this, aligned to continental issues, generate more substantive energy export opportunities? For energy it is not that simple. This is a classic Brexit issue that although our exports are theoretically aided by a weak GBP, the import commodity costs may nullify this benefit.
The Purchasing Manager’s Index this month reported that import price rises are ‘leading to one of the steepest rises in purchasing costs in the near 25-year survey history.’ This also applies to energy. The power we export may come predominantly from coal or gas – both are primarily priced in USD. With the decline of the North Sea, we are now a net gas importer and need to buy at this dollar rate. These fuels are also subject to the carbon price under the EU Emissions Trading Scheme, priced in Euros, so again the raw input cost is increased by a weaker pound.
In addition, the UK’s historically low capacity margin means prices are typically higher than those in the EU. This situation could be further exacerbated if the UK ends up outside the IEM and tariffs are applied to power exports.
This is a complex picture but the French outages provide an interesting case for what the threats and opportunities of our interconnected power network may be in a post-Brexit world.
Ted Hopcroft and Duncan Steen are energy experts at PA Consulting