By Jordy Benooit
Europe’s decarbonisation strategy increasingly depends on electrification. Transport, heating and cooling, and industry must switch from fossil to electric power, while the energy grids must be fitted to absorb rapidly growing volumes of wind, solar and other low-carbon generation. Focussing on localised energy production and storage alone will not be sufficient. Electricity must be able to flow efficiently across a continental market, under a coherent carbon price.
The post-Brexit separation of the United Kingdom (UK) and European Union (EU) Emissions Trading Schemes (ETS) has therefore become a material weakness. Both schemes cover power generation and use a declining emissions cap to favour low carbon investment. But their allowances are not interchangeable, and their prices can diverge. Generators connected through the same regional power network can consequently face different carbon costs, to the detriment of efficient energy flows. I would argue that, if Europe is to electrify efficiently, electricity must be able to move across the UK–EU energy markets without regulatory fragmentation.
Carbon-Price Divergence and Border Friction
Electricity trade does not stop because the markets are separated. However, flows can reflect the regulatory differences—such as carbon prices—rather than the underlying efficiency or carbon intensity. When two markets apply different carbon prices, fossil-fuel generators in the lower-priced market may gain a cost advantage and export more electricity to the higher-priced market, potentially displacing generation there. In doing so, emissions may shift from the higher to the lower-priced market rather than decline overall, resulting in carbon leakage.
The EU Carbon Border Adjustment Mechanism (CBAM) adds another layer of complexity. Electricity is covered by EU CBAM, and imports from the UK are not currently exempt—excluding Northern Ireland under the EU–UK Withdrawal Agreement’s protocol on Ireland/Northern Ireland. Electricity is particularly difficult to assess at a border. The grid provides an energy mix, in which electrons can generally not be traced to a specific source. EU rules therefore calculate the embedded emissions of imported electricity through a default emissions factor. British wind or nuclear electricity exported through a mixed grid, unless satisfying stringent traceability conditions, may be assessed using a broader default factor rather than its actual near-zero emissions value. Low-carbon electricity could therefore face administrative or carbon costs that do not reflect the generation method.
The EU and Great Britain (GB) positions are also asymmetric. The UK CBAM scheduled for 2027 does not include electricity. EU electricity entering GB will not face a British border adjustment on its carbon cost. Electricity moving from GB into the EU, by contrast, does fall within EU CBAM and is subjected to adjustment. This, together with the default emissions factor, can make GB’s low-carbon electricity less competitive relative to EU produced electricity, potentially even in both directions.
Fragmented Markets Raise the Cost of Electrification
The EU Agency for the Cooperation of Energy Regulators (ACER) has concluded that integrated day-ahead trading lowers electricity costs, limits price volatility and facilitates renewable growth by allowing countries to draw on their neighbours’ generation, storage and demand-side flexibility. ACER has also warned that national and cross-border grids must accommodate sharply rising renewable supply and electricity consumption as heating and transport electrify. Unfortunately, post-Brexit, GB also left the EU’s day-ahead market-coupling system, meaning EU–UK electricity and interconnector capacity are no longer optimised through the same pan-European process.
The combined regulatory and administrative burdens risk making renewable integration more expensive. Where cross-border trading is harder, surplus clean electricity is more likely to be curtailed. More national back-up capacity may be needed where balancing resources cannot be shared efficiently. Consumers ultimately bear these costs, but it matters beyond the power sector. Electrifying transport, heating and cooling, and industry depends on guaranteeing a steady and competitively priced supply of electricity. When fragmented markets increase the cost of integrating renewable generation, they also weaken the economic case for replacing fossil fuels.
The EEA Model for Carbon-Market Integration
Norway, Iceland and Liechtenstein provide a contrasting model. Although they are not EU members, they participate in the EU ETS through the European Economic Area (EEA). Their power generators therefore operate within the same allowance market and face the same carbon price as EU generators. Norway is even working towards introducing EU CBAM from 2027, meaning electricity trade between the EU and Norway can proceed without repeated carbon charges, while the border mechanism is directed principally at imports from outside the EEA.
This demonstrates that EU membership is not a prerequisite for carbon-market integration. It does, however, require common rules, a shared allowance market and institutional cooperation. The UK remains the major neighbouring European energy market operating a separate ETS, despite its extensive grid interconnection and central role in North Seas offshore wind.
A Route to Renewed Energy-Market Integration
There is now a route out of this fragmentation. The EU and UK have begun negotiations to link their emissions trading systems. Their agreed framework expressly includes electricity generation and is intended to create the conditions for mutual exemptions from their respective CBAMs. In parallel, the two sides are also negotiating possible UK participation in the EU internal energy market. The Council says this would require alignment of relevant rules, improved efficiency of electricity trading, and the facilitation of investment in infrastructure and renewable generation.
These negotiations are in principle separate, but economically complementary. Integration of the energy markets without carbon price alignment would leave competing generators facing different carbon signals. ETS linkage without more efficient power trading would leave much of the value of grid interconnection unrealised. Neither agreement has been fully outlined and difficult questions remain concerning dynamic alignment, governance, and financial contributions. Nevertheless, their direction is significant and part of a broader, pragmatic realignment of EU–UK relations. It is not a reversal of Brexit, but a political reaffirmation that certain systems function more effectively at continental scale.
Europe cannot electrify efficiently while treating an interconnected electricity network as a collection of isolated carbon markets. Linking the UK and EU ETS, removing unnecessary carbon–border friction, and reintegrating electricity trading would create a larger market for clean power and strengthen the economic case for offshore wind, storage, grid interconnectors, and flexible demand.
The cables already connect Britain to Europe; now we reconnect the rules that determine how the electricity flows.
About the author
Jordy Benooit holds a B.Sc in Political Science and M.Sc in EU-Studies from Ghent University, and a Postgraduate specialisation in EU Policy Making from the BSoG. He is active in EU Public Affairs, while pursuing an LL.M. International and European Law. Most importantly, he is the proud godfather of two wonderful boys.
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