European gas prices continued to climb in Week 42, adding to upward pressure on Southeast European electricity markets as the region approached winter with comparatively low seasonal gas-storage levels. Higher benchmark prices increased the cost of gas-fired generation and reinforced the exposure of regional power markets to developments in the European gas market.
The Dutch TTF benchmark averaged €86.54/MWh, representing an 11.6% increase from the previous week, and closed Friday at €87.55/MWh. Prices remained above €84/MWh throughout the week, while the one-month forward contract stood at approximately €88.40/MWh at the end of the period.
The increase is significant for electricity markets because gas prices directly influence the operating costs of gas-fired power plants. When fuel becomes more expensive, combined-cycle gas plants generally require higher electricity prices to remain competitive. These costs can influence wholesale prices beyond countries that rely most heavily on gas-fired generation, particularly in interconnected markets where gas-fired plants help determine the marginal price of electricity.
This relationship is especially important in Southeast Europe, where gas-fired generation provides flexibility when wind, solar and hydropower output fluctuates. Higher fuel costs can therefore affect regional electricity prices even when gas generation accounts for only part of the overall generation mix.
European gas storage also remained an important market consideration. Inventories were expected to enter November at approximately 75–78% of capacity, around 10 percentage points below the five-year average. Although these levels do not necessarily indicate an imminent physical supply shortage, they leave Europe with a smaller seasonal buffer and increase market sensitivity to potential disruptions in pipeline deliveries or liquefied natural gas (LNG) supplies.
Europe’s continued reliance on imported pipeline gas and LNG also exposes its market to international competition for available cargoes. Changes in Asian demand, supply disruptions and competition for flexible LNG shipments can influence European hub prices, adding another source of uncertainty as winter demand increases.
Week 42 electricity-generation data highlighted the increasingly complex relationship between gas prices and power production. Regional gas-fired electricity generation declined by 7.43%, even as Greece increased its gas-fired output by 26.56%. Croatia also recorded a substantial increase in thermal generation, driven entirely by gas-fired production.
These contrasting trends reflect differences in national market conditions. Higher fuel prices can make gas-fired generation less competitive in some markets, prompting generators to reduce output. In others, strong electricity prices, export opportunities or system-balancing requirements can justify continued or increased gas-fired production despite elevated fuel costs.
For electricity traders and utilities, the TTF benchmark therefore remains a critical indicator to monitor throughout the winter season. Sustained gas prices near €90/MWh could keep gas-fired electricity relatively expensive, particularly during periods of high demand or limited renewable availability. However, the actual impact on wholesale electricity prices will depend on hourly market conditions, competing generation costs and cross-border transmission constraints.
Elevated gas prices can improve the relative competitiveness of generation sources with lower short-run marginal costs, including renewables, hydropower and nuclear power where available. Yet these alternatives face their own limitations. Greater coal generation can increase exposure to carbon costs, hydropower depends on reservoir levels and inflows, and wind and solar production remain weather-dependent. Nuclear generation also varies in availability and flexibility across markets.
Gas consequently retains an important role in power-system flexibility and security of supply, even when its fuel costs are high. Its ability to respond to changes in demand and renewable production can be particularly valuable during periods when lower-cost generation is insufficient to meet electricity requirements.
The changing economics also strengthen the case for investment in battery storage and demand-side flexibility. Batteries can shift electricity from lower-priced periods into expensive peak hours, potentially reducing the need for gas-fired generation when wholesale prices are high. Industrial demand response can help consumers limit exposure by adjusting consumption during periods of elevated electricity costs.
Long-term renewable power purchase agreements (PPAs) can also help businesses manage exposure to fossil-fuel price volatility. However, contracted renewable volumes do not necessarily match consumption in every hour, meaning buyers may still require balancing arrangements, storage or supplementary market purchases when renewable production is insufficient.
For investors, the interaction between gas and electricity markets highlights the importance of assessing generation assets within the wider energy system. Renewable projects may benefit from higher wholesale prices during periods of tight supply, but their revenues remain dependent on production timing, market exposure and the availability of transmission and storage infrastructure.
Southeast European electricity markets are therefore likely to remain closely linked to European gas-price movements through the winter. The key issue is not solely whether Europe can secure sufficient physical gas supplies, but also how expensive that supply becomes and how those costs influence generation decisions and wholesale electricity prices across the Balkans.
Courtesy of Virtu.Energy
