TTF futures extended their rally in Week 42, adding upward pressure to Southeast European electricity markets as winter approached. The increase came as European gas storage offered relatively limited seasonal comfort. Higher gas prices can raise the cost of electricity generation across the region.
TTF futures averaged €86.54/MWh, an 11.6% rise from the previous week, and closed Friday at €87.55/MWh. The benchmark stayed above €84/MWh throughout the week. At the close, the one-month forward contract was trading at about €88.40/MWh.
Gas prices and winter supply buffers
European gas inventories were at relatively low seasonal levels, with storage expected to enter November at around 75-78%, roughly 10 percentage points below the five-year average. This does not necessarily mean a physical supply shortage. It does, however, leave Europe with a smaller operational buffer and greater sensitivity to disruptions in pipeline or liquefied natural gas (LNG) supply.
The region remains dependent on pipeline imports and LNG, so competition with Asian buyers can quickly feed through to European hub prices. For electricity markets, the key effect is the implied cost of running gas-fired generators. Higher fuel costs raise the marginal cost of combined-cycle gas plants and can push wholesale electricity prices higher even in countries that rely less directly on gas-fired generation.
This link is especially important in Southeast Europe, where gas plants often provide flexibility when wind, solar and hydro output changes. Week 42 electricity data showed that the relationship between gas and power is not uniform across the region. Regional gas-fired electricity output fell 7.43%, while Greece increased gas generation by 26.56% and Croatia recorded a strong rise in thermal production entirely from gas.
Different generation responses and market exposure
At high gas prices, some generators cut output because they become less competitive. Others continue operating when local electricity prices, grid requirements or export opportunities make production commercially viable. The contrasting Week 42 figures reflect these different conditions.
For Southeast European electricity traders, TTF remains one of the most important external indicators to monitor through winter. If gas prices remain near €90/MWh, gas-fired generation could continue to set an expensive marginal electricity cost even during periods of strong renewable output. That would increase the value of coal, hydro, nuclear and renewable generation with lower short-run marginal costs.
Other constraints remain relevant. Higher coal dispatch increases carbon exposure, while hydro availability depends on water conditions and renewable generation remains weather-dependent. Nuclear production is relatively inflexible and geographically concentrated. Gas therefore continues to provide part of the region’s flexible insurance mechanism, even when that insurance is expensive.
Investment and consumer responses
The investment implications include greater value for battery storage when it can displace gas generation during high-price peaks. Demand response also becomes more attractive to industrial consumers. Long-term renewable power purchase agreements (PPAs) can protect buyers from fossil-fuel price volatility, although they still need solutions for hours when contracted renewable generation is unavailable.
Europe’s gas market and Southeast Europe’s power market are therefore likely to remain closely linked during winter. The principal risk is no longer simply whether Europe has enough gas, but whether the cost of securing it becomes high enough to reshape generation dispatch and electricity prices across the Balkans.
Courtesy of Virtu.Energy. Further coverage of European gas-market prices.