In North-West Europe, the electrification of end uses and the shift from dispatchable thermal generation to intermittent renewables are reducing the electricity system’s resilience to winter cold spells. With historical overcapacity fading (e.g., in France), ENTSO-E shows that Belgium and France already faced supply shortage risks last winter. According to RTE, a 2012-type cold spell would almost certainly have caused Loss of Load in France by 2022–2023.
To assess the system’s vulnerability in 2030, we define three demand scenarios with varying levels of electrification and compare them to TYNDP-like supply assumptions to evaluate potential supply-demand gaps and associated costs.
By 2030, the risk of supply-demand imbalances during cold-temperature peak hours increases significantly. Cold spells similar to those of 1985, 1997 or 2012 could generate up to ~30 bn EUR of economic cost (~0.4% of regional GDP), driven by the loss of up to 0.4% of annual electricity consumption and 35–70 GW of interruptions during 100–250 hours, affecting large industrial consumers and potentially commercial and residential users.
These outcomes are largely driven by the growing role of heat pumps, whose performance drops sharply at low temperatures. Real-life COP is lower than certification values, and the future mix of heat pump technologies adds uncertainty, as does their flexibility potential. Beyond a certain penetration threshold, each additional air-to-air heat pump could generate ~2,000 EUR of extra societal cost during cold spells. Hybrid heat pumps, with limited peak demand impact, offer a valuable alternative.
In comparison, each additional EV contributes ~300 EUR of additional cost during cold spells.
Other factors, such as low nuclear availability or reduced hydro output, could further widen the supply-demand gap and increase Energy Not Served.
The emerging adequacy risk represents a major challenge for the European energy transition. If rising electricity demand is not matched with new supply and flexibility assets, decarbonization could become more costly than anticipated. Countries must carefully manage system evolution—especially considering the rapid deployment of heat pumps.
Potential solutions include:
- Supply side: increasing dispatchable capacity, likely thermal.
- Demand side: reducing peak demand via a better mix of heating technologies (e.g., fewer resistance heaters, more hybrid heat pumps).
Decarbonization will require balancing:
- the cost of Energy Not Served,
- the cost of supply and demand-side equipment (heat pumps, gas turbines, hybrid systems),
- and the cost of low-carbon fuels (e.g., green gas).
Because adding peaker capacity or replacing heating equipment takes time, 2030 outcomes will depend on decisions taken in the early 2020s.
By 2050, unless long-duration solutions such as hydrogen storage are deployed at scale, the challenge is likely to intensify as electrification and intermittent renewables continue to grow.
