IEEFA: Europe’s electricity prices are still tied to gas, making geopolitics a structural vulnerability

Even without any physical disruption to supply, the risk premium embedded in gas markets can move power prices significantly.

During recent periods of geopolitical tension, increases in gas prices on the Title Transfer Facility (TTF) – the European benchmark gas trading hub – have translated into sharp spikes in day-ahead electricity prices in Italy and Germany. This reflects how frequently gas sets the marginal price in these markets, amplifying the transmission of gas price shocks into power prices. In contrast, the impact has been much more limited in France and Iberia.

Diverging prices are not a temporary distortion. They reflect the core design of European electricity markets, where marginal pricing determines prices. The system is well established, harmonised across the EU and fundamentally efficient: generation is dispatched in order of increasing marginal cost, and the last unit required to meet demand sets the market price.

In recent months, this mechanism has been visible in real time. TTF front-month gas prices have fluctuated from around €20 - 30/MWh to peaks above €60 - 70/MWh during periods of geopolitical tension. This has led to day-ahead electricity prices exceeding €120 - 150/MWh in markets such as Italy and Germany, while remaining closer to €60 - 80/MWh in France over the same period.

Gas does not dominate volumes, but it still drives prices

Gas accounts for roughly 18 - 20% of total electricity generation across the EU, down from around 25% before the 2022 energy crisis. In terms of electricity production, gas dependence has declined; in price formation, it has not.

Under the merit order system, low marginal cost generation such as nuclear, hydro, wind and solar is dispatched first. Gas-fired plants, with higher marginal costs driven by fuel and carbon prices, lie at the top of the stack and are called upon when demand exceeds the availability of cheaper generation or when system flexibility is required.

In most EU markets, gas typically sets the marginal price for only a few hundred to 1500 h/y. These hours, however, tend to coincide with periods of high demand or low renewables output – and therefore with the highest prices. As a result, gas plants have a disproportionate influence on annual average electricity prices.

The link between gas and power prices varies sharply across Europe

There is a much stronger correlation between gas and electricity prices in Italy and Germany than in France or Iberia.

In 2024, wholesale electricity prices in France and Spain were generally in the €55 - 70/MWh range. In Germany and the Netherlands, prices were higher and more volatile, typically €75 - 95/MWh. In Italy, prices consistently reached €90 - 110/MWh.

These differences arise despite strong physical interconnection between markets. They are driven primarily by differences in generation mix and, more importantly, by how frequently gas sets the marginal price.

Gas sets the price relatively infrequently in France, where nuclear power dominates the generation mix. Spain and Portugal, where renewables now account for more than half of annual generation, also limit the role of gas to shorter periods.

By contrast, gas remains central to the system in Italy, where it accounts for close to half of generation and sets the marginal price for a much larger share of hours. In Germany, despite significant renewables capacity, gas and coal play a balancing role, particularly during periods of low wind and solar output.

The issue is not market design but structural reliance on gas The EU has significantly reduced its dependence on Russian pipeline gas. Russia accounted for around 12% of EU gas imports in 2025, down from 45% in 2021. This has been replaced largely by LNG, which now accounts for around 48% of EU gas imports.

Diversifying gas suppliers has not reduced exposure to gas price volatility. European gas prices are now more closely linked to global LNG markets, which are influenced by demand in Asia, supply risks in the Middle East and global infrastructure constraints.

Increasing renewables capacity alone will not resolve the issue. Grid congestion is already limiting renewables output in several markets. IEEFA estimates that Italy curtails 2 - 4 TWh of renewables annually. In Germany, redispatch and curtailment costs have exceeded €3 billion/y in recent years, peaking above €4 billion in 2022, according to the country’s Federal Network Agency. Both countries continue to rely on gas for peak demand, balancing and, in some cases, mid-load generation.

This is not a failure of market design, but is instead caused by the structural reliance on gas for electricity generation. The merit order system functions as intended and remains the most efficient way to dispatch generation and signal power shortages. It is well understood and harmonised across Europe. Redesigning it would not address the underlying issue.

While gas-fired plants set the marginal price only during a limited share of hours each year, their influence on prices means that gas market movements continue to shape annual average electricity prices. This is a nuance that is often incorrectly depicted, including in political dialogue.

Reducing this dependence requires more renewables and addressing system constraints through grid expansion, improved flexibility (demand-side management, battery storage and pumped storage hydro) and a lower role for gas in both peak and off-peak periods.

Until that happens, European electricity prices will remain structurally linked to gas, embedding exposure to geopolitical risk and price shocks at the core of the EU’s energy system.

Read the article online at: https://www.oilfieldtechnology.com/special-reports/20042026/ieefa-europes-electricity-prices-are-still-tied-to-gas-making-geopolitics-a-structural-vulnerability/