Interconnector Economics: Why Britain Pays France for Nuclear Power
Britain imported 33.4 TWh of electricity in 2024, nearly half from France's nuclear fleet. UK wholesale prices run 57% above French levels. The undersea cables are the physical infrastructure of a failed domestic energy policy.
33.4 Terawatt-Hours of Dependency
In 2024, Britain imported 33.4 terawatt-hours of electricity through undersea cables, a record high. Total imports rose 31% year-on-year to 43.7 TWh, with exports of just 10.3 TWh doing little to balance the books.
Nearly half that imported electricity came from France. France, where 67% of all generation is nuclear. France, which was a net electricity exporter 98% of the time in 2024. France, which generated 361.7 TWh from nuclear while Britain managed just 36 TWh in 2025, the lowest nuclear output in half a century.
We first examined Britain’s 40% energy import dependency. We traced the £37 billion annual bill. This article examines one specific mechanism of that dependency: the electricity interconnectors, the undersea cables through which British consumers fund French nuclear power they could be generating domestically.
The Cables: 10.3 Gigawatts Under the Sea
Britain operates ten electricity interconnectors with a combined capacity of 10.3 GW, connecting to six countries:
France (4,000 MW, 39% of total capacity):
- IFA: 2,000 MW, operational since 1986. The oldest and largest, running from Sellindge in Kent to Calais.
- IFA2: 1,000 MW, commissioned 2021. A second link from Hampshire to Normandy.
- ElecLink: 1,000 MW, commissioned 2022. Runs through the Channel Tunnel.
Norway: North Sea Link, 1,400 MW (2021). The world’s longest subsea power cable at 720 km, connecting to Norwegian hydropower.
Denmark: Viking Link, 1,400 MW (2023). Connects Lincolnshire to southern Jutland.
Belgium: Nemo Link, 1,000 MW (2019). Runs from Richborough in Kent to Zeebrugge.
Netherlands: BritNed, 1,000 MW (2011). Connects the Isle of Grain to Rotterdam.
Ireland: East-West Interconnector, 1,000 MW (2012); Greenlink, 1,000 MW (2025); plus Moyle, 500 MW (2001) to Northern Ireland.
Three of ten interconnectors connect to France. Those three account for 39% of total interconnector capacity. The government plans to expand total capacity to 11.7 GW by 2028, with further links under discussion. The direction of investment is clear: more cables, more import capacity, more dependency.
The Flows: Structurally One-Way
Interconnectors are presented as two-way infrastructure. Britain exports when it has surplus wind; it imports when demand outstrips supply. In theory, the flows balance.
They do not balance. Annual data shows a structural pattern:
| Year | Net Imports (TWh) | Share of UK Supply |
|---|---|---|
| 2021 | 46.9 | 10.4% |
| 2022 | -3.1 | 5.4% |
| 2023 | 23.9 | 12.2% |
| 2024 | 33.4 | 14.4% |
| 2025 (9 months) | 25.0 | 16.0% |
In July 2025, imports supplied 19.5% of UK electricity. Nearly one in five units consumed in Britain was generated abroad.
France dominates. In 2024, France exported 20.1 TWh to the UK, accounting for roughly 46% of all UK electricity imports. The North Sea Link to Norway contributed 9.6 TWh, Nemo Link to Belgium 4.2 TWh, and Viking Link to Denmark 3.7 TWh.
The pattern intensifies seasonally. Winter months see the highest imports, when heating demand peaks and wind generation is unreliable. Summer months, when solar and wind are stronger and demand is lower, are when Britain occasionally exports modest volumes. The structural direction is one-way: inward.
The one exception is telling. In 2022, the UK was briefly a net electricity exporter, to the tune of 3.1 TWh. Not because Britain suddenly discovered abundant domestic generation, but because France’s nuclear fleet was partially offline for corrosion repairs. EDF discovered stress corrosion cracking in reactor cooling circuits, forcing extended shutdowns across the fleet. French nuclear output dropped to its lowest level in decades. With nothing to import, the maths reversed.
The moment France fixed its reactors, the one-way flow resumed. Net imports surged to 23.9 TWh in 2023 and 33.4 TWh in 2024. The correlation is the argument: when France has nuclear power to sell, Britain buys it. When France does not, the interconnector strategy has nothing to fall back on.
The Price: A 57% Premium
The flows are driven by price. Electricity moves through interconnectors from cheaper markets to more expensive ones. Britain’s wholesale electricity prices are structurally higher than France’s, so the cables carry power eastward across the Channel for most of the year.
In the first half of 2025, UK wholesale electricity prices averaged $115 per MWh, according to the International Energy Agency. France averaged $73 per MWh. The EU average was $90. Britain pays a 57% premium over France and 28% above the European average.
The structural reason is generation mix. France’s 56 nuclear reactors were largely built between the 1970s and 1990s. The capital costs have been paid. Operating costs are low. Nuclear has near-zero marginal fuel cost. France’s wholesale price reflects an amortised baseload fleet that generates power cheaply and reliably.
Britain’s wholesale price is set by gas. When demand exceeds renewable output, gas plants fire up, and the wholesale price tracks international gas markets. This makes UK prices volatile and structurally higher than countries with large baseload nuclear or hydro fleets. The 2024 French wholesale average was €58 per MWh. The price gap is not a market aberration. It is a permanent feature of two different energy policy choices.
This is not a temporary spike. In 2024, France’s annual wholesale average was €58 per MWh. Article 8 in this series documented the same pattern in Germany, where wholesale prices ran 48% above French levels in 2024. The countries that dismantled nuclear pay more. The countries that kept it pay less. The data is consistent across borders and across years.
For British industry, the gap translates directly into competitive disadvantage. Higher wholesale prices feed through to manufacturing costs, data centre operation, and any energy-intensive business deciding where to invest. A steel mill or server farm choosing between sites in Kent and Normandy faces a structural cost penalty for choosing Britain.
Interconnector operators profit from this spread. Under Ofgem’s Cap and Floor regime, operators earn revenue from the price differential between connected markets. The wider the gap between UK and French prices, the more profitable the cables. British consumers pay the premium; French state-owned EDF earns the export revenue. The cables themselves become more commercially attractive precisely because domestic policy has failed.
The Vulnerability: When Cables Fail
Undersea cables are single points of failure. In September 2021, a fire at the Sellindge converter station in Kent halved the capacity of the IFA interconnector from 2,000 MW to 1,000 MW. National Grid warned of “extensive work” needed to restore service. Full capacity was not restored until October 2023, two years after the fire.
The timing was brutal. The fire hit just as gas and electricity prices were spiking toward the 2021-22 energy crisis. Losing 1,000 MW of French import capacity during that winter compounded price pressure on UK consumers.
Physical vulnerability extends beyond accidents. The sabotage of the Nord Stream gas pipelines in September 2022 demonstrated that undersea energy infrastructure is a strategic target. Britain’s interconnectors run along charted seabed routes. Every cable is a known location, a fixed asset that cannot be moved or hidden.
Then there is the systemic risk. Interconnectors assume that when Britain needs to import, someone has surplus to sell. During a Dunkelflaute, a period of cold, still, overcast weather across Northern Europe, every country needs more power simultaneously. Wind output drops everywhere. Demand rises everywhere. Interconnectors become useless precisely when they are most needed, because there is no surplus anywhere in the system to import.
France’s 2022 nuclear crisis previewed this scenario from the supply side. When EDF discovered stress corrosion cracking across its reactor fleet, French nuclear output dropped to 279 TWh, the lowest in decades. France flipped from Europe’s largest electricity exporter to a net importer. The UK’s primary import source evaporated overnight. Prices spiked across the continent.
Britain’s interconnector strategy is predicated on French nuclear reliability, a reliability that Britain has no control over, no contractual guarantee for, and no fallback for when it fails. The 2022 episode lasted months. A longer disruption, whether from maintenance, policy change, or France prioritising domestic supply during a cold snap, would leave the UK scrambling for alternatives that do not currently exist.
This is the fundamental asymmetry: France can choose to stop exporting. Britain cannot choose to stop needing imports.
The Irony: Paying for What We Dismantled
Britain once generated 100 TWh per year from nuclear power. That was the late 1990s. By 2024, UK nuclear output had fallen to approximately 41 TWh. By 2025, it dropped to 36 TWh, the lowest level in half a century, generating just 11% of UK electricity.
Over the same period, France maintained and expanded its fleet. French nuclear generation recovered from a low of 279 TWh in 2022 (the corrosion crisis) to 361.7 TWh in 2024 and 373 TWh in 2025. France now generates ten times more nuclear electricity than Britain and has commissioned Flamanville 3 to bring its fleet to 63 GW.
The lost 64 TWh of British nuclear output, the gap between 100 TWh and 36 TWh, is remarkably close to the 43.7 TWh Britain imported via interconnectors in 2024. The electricity Britain stopped generating domestically is roughly the electricity it now buys from abroad.
The cumulative cost is substantial. If Britain has imported an average of 25 TWh per year over the past decade (a conservative estimate given the rising trend), and the wholesale price differential between UK and French electricity averages even $30/MWh, the premium paid for imports over domestic nuclear generation runs into billions. Hinkley Point C, at an estimated £33 billion for 3.2 GW of capacity generating roughly 25 TWh per year, looks expensive as a single project. Spread across a 60-year operating life, it looks considerably cheaper than indefinite import dependency at a 57% price premium.
Both countries faced the same question in the 1970s oil crisis: how to secure domestic electricity supply. France chose nuclear, building 58 reactors in 20 years under the Messmer Plan. Britain chose gas from the North Sea, cheap and abundant at the time, then allowed its nuclear fleet to age without replacement. Fifty years later, France generates ten times more nuclear electricity than Britain, exports it across the Channel at a profit, and Britain pays a 57% wholesale premium for the privilege.
The interconnectors did not cause this dependency. They are the infrastructure that makes it visible. Every cable laid across the seabed, every converter station in Kent, is a physical admission that Britain’s domestic generation is insufficient for its own needs. The cables are not the problem. The half-century of policy choices that made them necessary is the problem.
What Interconnectors Actually Do Well
Honesty requires acknowledging what interconnectors genuinely provide.
Market efficiency is real. When the UK has surplus wind generation, it exports. When France has surplus nuclear overnight, it exports. This mutual exchange reduces total system cost for both sides. In 2024, UK exports reached 10.3 TWh, a meaningful contribution to European grid balancing.
Renewable integration depends on interconnectors. As Britain’s wind capacity grows, interconnectors allow surplus generation to find a market rather than being curtailed. They also provide backup during calm periods, smoothing the intermittency that is inherent to wind and solar.
Emergency backup has genuine value. During equipment failures or unexpected demand spikes, interconnectors provide immediate access to generation that would take hours to bring online domestically.
No country achieves complete energy autarky, and none should aspire to it. International electricity trade is normal, rational, and beneficial.
The distinction is between interconnectors as grid tools and interconnectors as substitutes for domestic generation. A country that trades electricity across balanced interconnectors is well-managed. A country that consistently imports 14-16% of its supply through cables it has no control over is dependent. Britain is the second kind.
What Would Actually Help
The answer is not fewer interconnectors. It is more domestic baseload generation. Specifically:
Accelerate Sizewell C and the small modular reactor programme. Every gigawatt of domestic nuclear capacity reduces structural import dependency and insulates wholesale prices from international gas markets.
Reclassify interconnector imports in official energy security accounting. The current framework treats interconnectors as equivalent to domestic generation. They are not. They are supply lines that can be cut, congested, or redirected.
Publish transparent dependency metrics. The public deserves an annual accounting of how much electricity Britain imports, from whom, at what cost, and what domestic capacity would be needed to replace it.
Maintain interconnectors as grid tools for managing variability, emergency response, and export of surplus generation. They are good tools. They are not a substitute for building power stations.
Data Sources
Government and regulatory:
- Statutory Security of Supply Report 2025, DESNZ/Ofgem
- Energy Trends: UK Electricity (Section 5), DESNZ, updated April 2026
- Energy Trends March 2026 (PDF), DESNZ
France:
- RTE Annual Electricity Review 2024: Key Findings (PDF), RTE France
- France’s Electricity Mix Reaches 95% Low-Carbon, NucNet, May 2026
International:
- Electricity Mid-Year Update 2025: Wholesale Prices, International Energy Agency
- France Nuclear Recovery, US Energy Information Administration
- Electricity Price Statistics, Eurostat
Analysis:
- UK More Reliant on Electricity Imports Than Ever Before, Nuclear Industry Association, October 2025
- UK Renewables Record Year in 2025, Carbon Brief, January 2026
Incident reporting:
- IFA Cable Fire, The Guardian, October 2021
- IFA Back at Full Capacity, Energy Voice
Who Has Incentives?
Every source cited above has institutional interests. DESNZ supports current government energy policy. The Nuclear Industry Association advocates for nuclear investment. RTE France benefits from presenting interconnection as partnership rather than dependency. The IEA has shifted toward renewable advocacy under current leadership. Carbon Brief is climate-focused. We have used each source for its raw data and cross-referenced where figures overlap. Interpretations and policy recommendations are theirs, not ours.