The weekly data produced an important apparent contradiction: European gas prices eased slightly, yet SEE power prices rose sharply. TTF futures averaged €41.31/MWh, down 1.1% week on week, while electricity prices across most SEE markets moved materially higher. Hungary, Romania, Italy, Croatia, Serbia and Bulgaria all traded above €100/MWh on weekly average, despite the modest decline in gas.
This is the new summer paradox for the region. Gas prices remain important, but they are not the only driver of power price spikes. During Week 26, the dominant force was demand. Regional electricity consumption rose by 12.7% to 18.41 TWh, while hydro weakened and renewable support was uneven. Even without a gas rally, the system needed more gas-fired and coal-fired generation, and that additional dispatch lifted the electricity clearing price.
The gas market itself was not soft enough to provide real relief. TTF traded in a relatively narrow range, peaking at €42.16/MWh on 23 June, easing to €40.50/MWh on 25 June, and then recovering. The one-month forward TTF contract was reported at €44.08/MWh as the weekly data closed. That is not a low fuel-cost environment for power generation. Gas-fired units remained expensive enough to set a high marginal price when called during peak demand.
The result was a power market where gas mattered more through dispatch volume than through weekly price direction. A small decline in the gas benchmark does little for power prices if the system calls significantly more gas plants into operation. This was visible in regional thermal generation, where gas-fired output rose 25.5%. Italy alone increased gas-fired generation by 47.5%, showing how demand can overwhelm modest fuel-price relief.
For SEE traders, this creates a more nuanced risk model. It is no longer sufficient to look at whether TTF is up or down on the week. The relevant question is how many hours gas-fired generation is marginal, and how much demand must be served during those hours. A stable or slightly lower gas price can still produce higher electricity prices if cooling demand expands and non-thermal supply is limited.
For industrial buyers, the week showed that gas hedging and power hedging are linked but not interchangeable. A buyer exposed to electricity prices cannot assume that lower gas automatically reduces procurement risk. The dispatch stack, hourly demand profile and local import constraints decide the final cost.
Week 26 did not show gas-market panic. It showed power-market tightness under a still-expensive gas floor.
Elevated by Virtu.Energy
