Chapter 17: Brexit Friction - How Leaving the EU Made Energy Harder

The GB Model and European Integration

When I started working in energy markets, a common term in use was the GB model. This was the informal term given to the way that the EU had adopted the British privatisation model as a template for frictionless trade across European markets. At the core of the single market for energy was the notion of harmonised regulations, standardised trading mechanisms, and seamless cross-border electricity and gas flows that treated the entire continent as one integrated market.

This trajectory only gained momentum as the growth in renewables took hold in different European markets. Wind and solar are intermittent, and enabling previously siloed national electricity markets to trade the inevitable surpluses and shortages which happen over time is of clear mutual benefit. This was perhaps most obvious to Britain (and Ireland), which account for around 40% of Europe's wind resources, but which are separated by sea from the continent. However, prior to 2011, Britain's international electricity connections were limited to just two cables: the 1986 IFA cable linking England with France, and the 2001 Moyle interconnector linking Northern Ireland with Scotland.

Being within the EU single market for electricity meant that Britain could trade power with Europe almost as easily as trading within the country itself. From 2014, Britain joined a clever system called "implicit day-ahead coupling" - essentially a computer algorithm that would automatically work out the best way to buy and sell electricity across multiple countries at once, moving power to wherever it was needed most and could fetch the best price. There was no need for energy companies to separately bid for space on the cables - it all happened seamlessly behind the scenes.

The day-ahead market is by far the most important electricity trading venue - it's where the bulk of power is bought and sold for delivery the following day, and it's the most "liquid" market (meaning there are lots of buyers and sellers, making it easy to trade large volumes without moving prices dramatically). This was becoming increasingly crucial for Britain as wind power expanded, because wind generation is unpredictable and varies significantly from day to day. Having access to Europe's deep, liquid day-ahead markets meant British wind farms could easily sell their surplus power when the wind was blowing hard, and Britain could readily import power when the wind dropped.

Building cables across the seabed is significantly more expensive than over land, typically costing 3-5 times more per kilometre. Despite this cost premium, the economic benefits of cross-border electricity trading have been substantial, allowing Britain to export surplus wind power to Europe during periods of high generation and import nuclear and hydroelectric power from France and Norway during periods of low wind.

Britain's Interconnector Expansion

Following BritNed in 2011, Britain embarked on a major expansion of its interconnector network. To the continent, the Nemo cable to Belgium came online in 2019, ElecLink through the Channel Tunnel to France in 2021, IFA2 cable to France in 2021, and the North Sea Link to Norway in 2021. Britain also expanded its connections with Ireland: the Moyle interconnector linking Northern Ireland to Scotland had been operational since 2001, followed by the East-West interconnector connecting Ireland to Wales in 2012, and the Greenlink interconnector from Ireland to Wales which began operations in 2025. Several more interconnectors are planned or under construction including additional links to Denmark, Germany, and further Ireland-Britain connections.

While these interconnectors were mutually beneficial to both Britain and the continent, they were typically more valuable to Britain than to its European neighbours. Continental countries already had extensive networks of relatively cheap overland interconnectors linking them together - France could trade with Germany, Belgium, the Netherlands, Spain, and Switzerland through land-based cables. Britain, as an island nation, was far more isolated and dependent on these expensive subsea links for access to European markets.

Recognizing this asymmetry, Britain's energy regulator Ofgem had to design a special subsidy mechanism called the "cap and floor" regime to guarantee interconnector developers a minimum revenue stream. This was essential to make the expensive subsea projects financially viable. Crucially, these subsidies were predicated on the assumption that the interconnectors would have frictionless, automatic access to European electricity markets through the implicit day-ahead coupling mechanism - particularly important given Britain's rapidly expanding but intermittent wind generation that needed reliable export opportunities when production was high.

The Brexit Shock

Brexit threw this into doubt. Having access to the frictionless "implicit day-ahead coupling" required the UK to be subject to EU energy market regulations and the jurisdiction of European institutions. When Britain left the EU on 31 December 2020, it automatically lost access to this seamless trading mechanism.

From 1 January 2021, Britain's interconnectors reverted to the old system of "explicit" capacity auctions - energy companies now had to separately bid for space on the cables before they could trade electricity. This added complexity, cost, and uncertainty to cross-border trading. Instead of a single, automated process that optimized flows across multiple countries simultaneously, British traders now faced a two-step process: first win capacity in an auction, then trade electricity in separate national markets that no longer cleared together.

The impact was immediate and significant. Trading became more expensive and less efficient. The sophisticated algorithms that had automatically balanced supply and demand across borders were replaced by a more cumbersome system that required separate decisions about capacity allocation and energy trading. For Britain's wind farms, this meant losing the seamless access to European markets that had been crucial for managing the intermittency of renewable generation.

This was precisely the kind of friction that the cap and floor subsidies had never been designed to handle - the entire regulatory framework had assumed continued participation in EU market mechanisms that Brexit had now made impossible.

It's worth noting that this outcome wasn't inevitable. During the Brexit negotiations, there were options for a "softer Brexit" that could have maintained Britain's participation in EU energy market regulations while leaving other areas of EU law and regulation. Countries like Norway participate in parts of the EU's internal energy market without full EU membership. However, the UK government chose a harder Brexit approach that prioritized regulatory sovereignty across all sectors over maintaining sectoral integration in areas like energy where the benefits of continued cooperation were particularly clear. This political choice meant that billions of pounds of interconnector infrastructure, subsidized by British consumers through the cap and floor regime, would now operate under less efficient trading arrangements than originally envisaged.

The Financial Fallout

Despite the complexities introduced by Brexit, the volume of electricity traded between Great Britain and continental Europe has continued to grow significantly. In 2020, electricity imports via interconnectors were approximately 22,391 GWh, supplying about 6.6% of the UK's gross electricity supply. By 2023, this figure had increased to 33,212 GWh, with interconnectors supplying around 10.4% of the UK's electricity.

The UK's interconnector capacity has expanded significantly, reaching 8.4 GW by January 2023. This growth is driven by increased interconnector capacity and the integration of renewable energy, particularly wind power. Much of this growth can be attributed to interconnector projects that were planned or agreed upon before the Brexit vote in 2016 and the hard Brexit agreement in 2020. These projects were part of long-term strategies to enhance energy security and integrate renewable energy sources, particularly wind power, into the UK's energy mix. As a result, the physical infrastructure and capacity expansions continued to progress despite the political and regulatory uncertainties introduced by Brexit.

However, the financial implications for British taxpayers were significant. The cap and floor regime guarantees interconnector developers a minimum revenue - the "floor" - if their trading revenues fall below a certain threshold. By making cross-border electricity trading more expensive and cumbersome, Brexit would likely reduce both the frequency and efficiency of trading on these cables. Less frequent trading means lower revenues for interconnector owners, increasing the probability that their earnings would fall below the guaranteed floor levels. When this happens, British consumers are contractually obligated to top up the difference through higher energy bills. The irony was stark: Brexit had reduced the commercial value of infrastructure that British taxpayers were legally bound to subsidize, potentially making those subsidies more expensive precisely because the infrastructure had become less useful to the British energy system.

These financial burdens are in addition to the higher electricity costs and loss of export revenues that have resulted from the increased friction in trade. The combined effect is a lose-lose situation for the UK energy sector: higher costs for consumers and taxpayers, reduced competitiveness for British energy exports, and diminished returns on significant infrastructure investments. This underscores the complex and far-reaching economic consequences of Brexit on Britain's energy landscape.

In recent times, there have been renewed hopes for better harmonization between Britain and the EU in the energy sector. As the realities of Brexit's impact on energy trade become clearer, there is growing recognition of the mutual benefits that closer regulatory alignment could bring. Discussions have emerged around the possibility of Britain moving closer to the EU's regulatory orbit, particularly in areas like energy market integration and renewable energy cooperation. Such alignment could help reduce trade friction, enhance energy security, and support the transition to a low-carbon economy. While political challenges remain, the potential economic and environmental benefits provide a compelling case for exploring pathways to closer cooperation.

There is also a very compelling case for developing a shared offshore grid in the North Sea, connecting the UK with other countries that have major offshore wind installations. Such a grid could optimize the distribution of renewable energy across borders, balancing supply and demand more effectively and reducing the need for backup fossil fuel generation. By pooling resources and infrastructure, participating countries could achieve greater energy security, lower costs, and accelerate the transition to a low-carbon energy system. The North Sea's vast wind resources present a unique opportunity for regional cooperation, and a shared grid could serve as a model for future collaborative energy projects.

Carbon Market Divergence

Another significant development was the decoupling of the UK from the EU carbon market. Prior to Brexit, the UK was part of the EU Emissions Trading System (EU ETS), which is a cornerstone of the EU's policy to combat climate change by reducing greenhouse gas emissions. The EU ETS works on the 'cap and trade' principle, setting a cap on the total amount of certain greenhouse gases that can be emitted by installations covered by the system. After Brexit, the UK established its own UK Emissions Trading Scheme (UK ETS) in 2021, which is similar in design but operates independently of the EU ETS.

This decoupling has implications for both markets. For the UK, it means having the flexibility to set its own carbon pricing and emissions targets, potentially allowing for more ambitious climate policies. However, it also means losing the benefits of a larger, more liquid market that can provide more stable carbon pricing and greater opportunities for trading. For the EU, the loss of the UK as a participant in the EU ETS reduces the overall size and liquidity of the market, which could impact the effectiveness of the system in driving down emissions across Europe. The decoupling highlights the broader theme of Brexit: the trade-off between regulatory independence and the benefits of integrated markets.

While the UK ETS provides flexibility, it also poses significant risks. One major concern is the potential for a carbon border adjustment mechanism (CBAM) to be imposed by the EU on UK goods. If the UK maintains lower carbon prices than the EU, it could lead to competitive imbalances, where UK industries benefit from lower costs at the expense of higher emissions. To prevent carbon leakage and ensure a level playing field, the EU has proposed a CBAM that would impose tariffs on imports from countries with less stringent carbon pricing. This could affect a wide range of UK exports, increasing costs for British businesses and potentially leading to trade disputes. The risk of a CBAM underscores the challenges of maintaining regulatory independence while ensuring compatibility with major trading partners.

Since Brexit, the UK's carbon prices have consistently been lower than those in the EU. In 2023, UK carbon prices were approximately 28% lower than those in the EU, with the UK price at £35 per tonne of CO₂ equivalent. By 2025, UK carbon prices were around £45 per tonne, compared to the EU's €73 (approximately £62) per tonne.

This disparity has significant economic implications. The lower carbon prices have led to revenue shortfalls, with the UK raising over £1 billion less over a six-month period in 2023 compared to 2022 levels. If this trend continues, the Treasury could lose up to £3 billion annually. Additionally, the EU's CBAM, set to be fully implemented in 2026, could impose up to £800 million in additional costs on UK exporters by 2030.

To address these challenges, there have been discussions about linking the UK ETS with the EU ETS. Such a linkage could harmonize carbon prices, prevent competitive distortions, and reduce costs for both UK and EU consumers. In May 2025, the UK and EU agreed to work towards linking their respective Emissions Trading Systems.

For British exporters, facing a CBAM on exports to the EU in addition to higher energy costs than many EU countries would be an extra trade barrier they would prefer to avoid. The combination of these factors could make UK goods less competitive in European markets, potentially leading to reduced market share and profitability for British businesses. This highlights the importance of addressing carbon pricing disparities and energy cost challenges to maintain the competitiveness of UK exports in the EU.

Carbon Price Impacts on Electricity Costs

Carbon prices play a crucial role in determining the cost of gas-fired electricity generation. In both Britain and Belgium/Netherlands/Ireland, gas power stations can be identical in almost every respect—similar efficiencies, fuel costs, and technologies—except for the carbon price. This single difference can have a profound impact on the competitiveness of electricity generation. A lower carbon price in the UK can make its gas-fired electricity cheaper to produce, giving it a competitive edge in the market. Conversely, a higher carbon price in the EU can make electricity from similar stations more expensive, affecting where power is generated and traded. This highlights the critical role of carbon pricing in shaping energy markets and influencing cross-border electricity flows.

An artificially low carbon price in the UK can lead to unintended consequences. By making gas-fired electricity generation cheaper in the UK, it can shift emissions from gas power stations to Britain, as power generation becomes more economically attractive domestically. However, when this electricity is exported to the continent, it incurs higher transmission losses, reducing overall efficiency. This not only undermines the environmental benefits of lower carbon pricing but also highlights the complexity of balancing economic and environmental objectives in cross-border energy trade. It can also drive up the cost of electricity relative to gas within the UK, which hinders the incentive for decarbonisation.

Solutions and Pathways Forward

To address the challenges outlined in this chapter, closer harmonization with the EU on carbon prices and electricity trading presents a clear and viable solution. Even without a comprehensive re-entry into the EU single market, aligning the UK's carbon pricing with the EU ETS could mitigate the risk of the Eu's CBAM and enhance the competitiveness of UK exports. Harmonizing carbon prices would also help stabilize the market, reduce revenue shortfalls, and prevent competitive imbalances.

In terms of electricity trading, re-establishing closer ties with the EU's energy market mechanisms could reduce trade friction, improve efficiency, and lower costs for consumers. This could involve negotiating agreements that allow for more seamless cross-border electricity flows and participation in EU market coupling initiatives. Such steps would not only enhance energy security but also support the transition to a low-carbon economy by facilitating the integration of renewable energy sources.

Ultimately, these solutions highlight the importance of strategic cooperation and alignment with the EU to address the economic and environmental challenges posed by Brexit. By pursuing closer harmonization, the UK can leverage the benefits of integrated markets while maintaining its regulatory independence.

Recent developments have shown positive signs in this direction, suggesting that there is room for optimism. Both the UK and the EU have expressed interest in exploring pathways for closer cooperation on energy issues. Discussions about linking the UK ETS with the EU ETS and re-establishing energy market connections indicate a willingness to find common ground. These positive noises suggest that, despite the challenges of the past few years, there is potential for a more collaborative and integrated approach to energy policy moving forward. By building on these positive developments, the UK and the EU can work together to address shared challenges and seize opportunities for mutual benefit.