On 1 January 2021, the UK left the European Union (EU) and as such is no longer part of the Internal Energy Market (IEM).
While the UK and the EU agreed a post-Brexit Free Trade Agreement (FTA) on 24 December, outlining how energy markets, interconnectors and regulation will be affected, the arrangements will take some time to develop and as such GB’s internal and cross-border trading has temporarily been decoupled from European markets.
This is expected to result in less efficient trades, interconnector flows and divergent electricity prices between power exchanges. Since the start of the year, we have seen some of these impacts, with day-ahead wholesale prices decoupling not only from European markets, but also from each other across platforms.
Once upon a time: Market Coupling
Prior to 1 January 2021, when the UK was part of the IEM, the GB electricity market was “coupled” with various European markets. The aim of market coupling is to ensure electricity flows as efficiently as possible between participating markets to maximise the economic welfare of all players.
A coordinated day-ahead price setting and cross-zonal capacity allocation algorithm—known as EUPHEMIA—is used to ensure the efficient dispatch and flow of electricity between markets, whilst respecting available real-world interconnector capacities and constraints. As part of market coupling, interconnector capacity is allocated ‘implicitly’ together with the electricity sold in spot markets, rather than sold separately in ‘explicit’ auctions, resulting in efficient flows between markets.
The new reality: De-coupled market
Since 1 January 2021, and while the arrangements outlined in the FTA are not in place, the UK has now de-coupled from European markets. This means that each relevant power exchange—which for GB includes N2EX and EPEX platforms—will have to run and calculate their own day-ahead auction results independently of any cross-border capacity allocation process and of each other.
As the N2EX and EPEX exchange platforms have de-coupled, their separate and distinct order books, volumes and liquidity characteristics have created divergence in outturn prices. This effectively means that there are now two marginal generators on the system setting different prices, rather than just one marginal generator and one price.
Figure 1 shows the volumes traded across both exchanges, as well as the cleared prices, on the hourly day-ahead auctions in the week commencing 3 January. Nordpool’s N2EX platform has seen the greater volume of trades, with roughly double that of EPEX day-ahead auctions. More interestingly, we have indeed seen prices diverge between the two exchanges.
On average, in the week, N2EX prices averaged £0.37/MWh above EPEX prices. However, this was mainly due to several exceptional price events where N2EX prices exceeded EPEX prices by notable amounts. On 6 January between 5pm and 6pm there was a price differential of £262.59/MWh. In contrast, 68% of all hours in the week saw EPEX prices outturn above N2EX prices. At this stage it is difficult to know if the lack of coupling resulted in higher overall prices last week for consumers or not—arguably the £1,000.04/MWh bid would have remained the price setting plant in a coupled auction, but alternatively cheaper options may have been available elsewhere with implicit trading provisions.
These differences have caused challenges for market participants, with considerable price differences already being observed in some hours. We will be expanding upon this piece, exploring some of the impacts on market participants and government’s outlined plans for future arrangements, in the publication of our next Energy Spectrum on 18 January.
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