In Week 42, TTF futures rose 11.6% week on week to an average of €86.54/MWh, adding pressure to power-generation costs across Southeast Europe as winter approached with a relatively limited gas-storage buffer. European hub gas prices remained above €84/MWh throughout the week and ended Friday at €87.55/MWh.
The one-month forward contract was trading at about €88.40/MWh as the week closed. For power markets, the key effect is the higher cost of running gas-fired generators: dearer fuel raises the marginal cost of combined-cycle plants and can push up wholesale electricity prices beyond countries that rely heavily on gas generation.
Storage levels add to market sensitivity
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 there will be a physical supply shortage, but it leaves Europe with a smaller operational buffer and makes prices more sensitive to disruptions in pipeline or LNG supplies.
Southeast Europe remains dependent on pipeline imports and LNG, so competition with Asian buyers can quickly affect European hub prices. The region’s gas plants also frequently provide flexibility when wind, solar and hydropower output changes.
Gas generation diverges across the region
Week 42 electricity data showed that the relationship between gas and power is not straightforward. 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.
At elevated gas prices, some generators cut output as they become less competitive. Others keep operating when local electricity prices, grid requirements or export opportunities make generation commercially viable.
Fuel costs shape dispatch and investment choices
For Southeast European electricity traders, TTF remains one of the most important external indicators to track through winter. If gas prices stay near €90/MWh, gas-fired generation could remain expensive at the margin even during periods of strong renewable output, increasing the value of coal, hydro, nuclear and renewable generation with lower short-run marginal costs.
Those alternatives also carry constraints: greater coal dispatch raises carbon exposure, hydro availability depends on water conditions, and renewable output remains weather-dependent. Nuclear generation is relatively inflexible and concentrated geographically, while gas continues to provide part of the region’s flexible insurance mechanism even when that insurance is costly.
Battery storage becomes more valuable when it can displace gas generation during high-price peaks, and demand response becomes more attractive to industrial consumers. Long-term renewable PPAs can shield 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 main risk is not only 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
