Natural gas still supplies ~40% of industrial heat in Europe, where heat accounts for roughly two thirds of the sector’s energy consumption. Until 2022, nothing pushed industrials to electrify this use: gas was cheap, EU ETS carbon was low, and power markets were barely volatile.
That environment has since reversed structurally:
- industrial gas now trades around €30-60/MWh, up from €15-25/MWh before 2022;
- EU ETS carbon prices have roughly doubled, to €50-100/tCO2;
- growing renewable penetration is multiplying the hours of low, and sometimes negative, power prices.
The result: on price arbitrage alone, an electric boiler (e-boiler) can already outcompete gas for up to around 2,000 hours per year in several Western European markets.
Mature technologies, complementing gas rather than replacing it
E-boilers now match gas boilers on CAPEX and conversion efficiency, with fast ramp-up capability that lets them follow power-market signals without disrupting industrial processes. In most cases, they don’t replace existing gas assets but complement them, in hybrid configurations that preserve operational resilience while exposing part of consumption to low electricity prices.
Paired with thermal energy storage (TES/ETES) – whose CAPEX remains well below electrochemical batteries – these solutions shift heat produced during low-price hours to baseload demand, increase decarbonisation impact, and strengthen protection against gas price stress episodes. In favourable hybrid configurations, they deliver CO2 savings of 20-40% and payback under 5 years, a timeline that can shorten further when the e-boiler also captures flexibility value (aFRR, mFRR, intraday).
Four cumulative conditions make, or break, a project
- Available grid connection capacity, a baseline condition to limit reinforcement costs and delays.
- Genuine exposure to the carbon price, via the EU ETS or a sufficiently ambitious internal carbon price.
- Low electricity taxes and grid fees relative to gas: in Western Europe, and in France in particular, electricity can be taxed more heavily than gas outside specific regimes, which erodes e-boiler competitiveness unless the site benefits from reduced rates for electro-intensive profiles.
- Baseload heat demand, particularly outside the winter season, to maximise exposure to low-price hours.
These criteria drive sharp geographic differentiation. Gas+CO2/electricity spreads make France or Spain structurally more attractive than Germany, where the marginal power price is more often set by carbon-intensive assets. Electricity taxation also remains highly heterogeneous across the EU28, and can alone flip a project’s economics from one country to another. The most attractive sites combine significant electricity consumption (>~10 GWh/year) with a connection to the transmission grid or high-voltage network, which brings lower grid fees.
Beyond individual business cases, these assets deliver system-level value: absorbing renewable surpluses, reducing curtailment, supporting less negative prices during oversupply, and strengthening balancing markets. As curtailment keeps rising across Europe, e-boilers and TES should gain further relevance – provided taxation and grid tariffs align with the system value they deliver.
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