Whilst we build towards 2021 and post-Brexit energy markets, focus has been applied to how we in GB strive towards net zero ambitions with a more independent policy agenda. However, regardless of future trading arrangements, interconnectors with EU nations will continue to play a pivotal role in driving wholesale power prices and system flexibility in the future. We analyse the impact of interconnection as part of our Benchmark Power Curve, which provides wholesale power price forecasts out to 2050 through our GB and EU-wide market models. In this blog, we detail some of our latest findings from these forecasts in the context of interconnection impacts.
Here and now
Interconnectors are already a material driver in GB wholesale outcomes and price formation, with ~5GW of connections with Ireland (~1.0GW), Holland (~1.0GW), Belgium (~1.0GW) and France (~2.0GW). Further connections are on the way and Ofgem’s Cap and Floor investment regime has helped to incentivise a further 6GW between now and 2024. The projects include a 1.5GW link to Denmark (Viking), 2.5GW further to France (IFA 2 and FAB Link), 1.5GW to Norway (NS Link) and 500MW to Ireland (Greenlink). The 1.0GW Eleclink to France is also being developed separately to Cap and Floor.
We use these committed projects as a baseline in our methodology and note that in a little over three years we could see an effective doubling of current interconnector capacity. Growth could extend further, with the current National Grid Interconnector Register showing up to 16GW of interconnection could be operational by 2025 and up to 25.4GW by 2030.
For the GB market, and in our modelling, what this creates is greater exposure to European market trends notably for connecting countries such as France, Ireland, Holland, Belgium, Denmark and Norway. There are also plans for a grand 1.8GW link between Spain and GB with a “stop off” point in France in the late 2020s.
Historically, interconnector impacts have been relatively straightforward to see and analyse. GB generators have typically faced higher costs than those in mainland in Europe owing to a combination of factors including network charges to generators through Transmission Network Use of System Charges (TNUoS), a higher carbon price with the addition of the Carbon Price Support on top of the EU ETS and typically higher average gas prices, owing different gas price dynamics than much of mainland Europe. As GB generators were subject to higher costs, these were priced into wholesale power markets and consequently saw flows of cheaper power from Europe to GB in the majority of market scenarios.
So, conventional wisdom would suggest that 6GW of connections to predominantly cheaper power markets would add to this trend and, all things being equal, drive further reductions in GB wholesale prices. However, whilst we may see this trend materialise in the near term, our modelling shows a number of key drivers which could change the balance in the next decade. These are multi-layered and interlinked and include:
- Increased interconnection and network capacity between western and eastern European nations, particularly via Germany, which would allow power from countries such as France, Holland and Belgium to flow power to this region more easily
- France starting to retire 14 nuclear power stations in line with publicly stated plans from the mid-2020s
- Germany’s current plans to close hard coal and lignite stations with 12.5GW due to be decommissioned by 2022 and 25GW by 2030
- Belgium’s plans to retire its Doehl and Tihange nuclear power stations by 2025
- The Netherlands planning to retire all coal fired capacity by 2030
Capacity closures in all these markets would need to be replaced either through new generation or imports.
There are also significant changes occurring to generator costs and pricing in GB, the potential removal of Balancing Service Use of System Charges (BSUoS) charges from transmission connected generators is likely to be put forward by the 2nd BSUoS taskforce as a recommendation to Ofgem. If implemented, likely in 2022 or 2023, it would reduce large generators costs by a further ~£2.5/MWh to ~£3.5/MWh on average, which could reduce the cost of GB generation relative to European power.
Added to this is the large spectre of post-Brexit carbon pricing and the UK ETS. Whilst key details are still to be finalised, there is the potential for divergence in UK ETS and EU ETS pricing if the schemes are not linked – which is one of the options under current consideration by government. Should this occur, there is more risk during the 2020s and 2030s that prices for carbon diverge. The direction of divergence will depend on respective policies and carbon reduction targets in the UK and the EU.
The power price impact
As the generation mix used in respective European countries converges towards cheaper solar and wind in the 2020s, it is logical to suggest that wholesale power pricing will do the same. Weather-related drivers are therefore likely to become a major factor in power prices and interconnector flows, a trend observed recently with the Capacity Market Notice issued on 15 September. While later withdrawn, the notice was issued as forecast power system margin had dropped as low as 120MW for the evening peak owing to both very low wind output in GB and the day-ahead market coupling mechanism with Europe scheduling the export of interconnectors over the period, due to higher prices being observed in continental markets. Low wind and higher demand conditions were also observed in Europe and as a result caused the price differential. In response, National Grid ESO had to conduct trades to buy back on the interconnectors for periods 37 and 38, with prices hitting a high of £607/MWh as the ESO sought to bring imports into GB to cope.
Whilst this is an extreme example of the impacts of weather correlated pricing events, it does highlight how wider factors in Europe can have a material impact on GB wholesale price formation. However, there are also upsides for power prices with new interconnection capacity. Our modelling of both GB and EU markets also shows through the 2020s and 2030s that increased interconnection could provide a route for excess offshore wind power in GB to be consumed elsewhere in Europe. Offshore is set to be the key generation technology, by volume, in reaching net zero targets and GB’s comparative advantage for offshore resources is likely to mean vast build out of the technology. Increased interconnection would help facilitate this cheaper power moving to European markets and potentially limit incidences of negative pricing and network constraint payments if the power can be flowed elsewhere. Assuming we are on track to meet Net Zero targets, our modelling shows that by the 2040s strong local wind conditions and large scale offshore wind deployment could see GB become an annual net exporter of power to the continent, a real reversal of roles from what has been seen in the last decade.
Our Benchmark Power Curve (BPC) service models interconnection and wider drivers on wholesale power prices. Providing scenario assessments of power prices by capture price and technology out to 2050, the service provides a credible long-term view of power prices for investors, developers, generators and energy suppliers.
Alongside the BPC, we provide a bespoke advisory service of 1-2-1 briefings to offer guidance and bespoke support on how the latest power market developments may impact your business and the potential solutions to any risks.
We will also be hosting a FREE webinar on Thursday 14th October to explore the latest drivers of power prices and the outlook for this coming winter. Sign up is HERE.
For more information please contact James Brabben – email@example.com