The decline in European gas prices during Week 25 would, in a traditional energy pricing model, have been expected to ease pressure on Southeast European electricity markets. The TTF benchmark averaged around €41.76/MWh, falling by nearly 15% week-on-week. However, despite this bearish fuel signal, wholesale electricity prices still increased in several SEE markets, including Italy, Hungary, Croatia, Romania, and Serbia. This growing divergence has become one of the defining characteristics of current regional power trading.
The core explanation is that the gas-to-power relationship is no longer linear. While gas remains a key marginal fuel in many hours, electricity prices are increasingly shaped by a wider set of structural factors, including renewable output, hydro availability, cross-border flows, import dependence, and peak-hour balancing costs. When these physical constraints tighten, lower gas prices may limit upside pressure, but they no longer guarantee lower electricity prices.
Italy provided the clearest illustration of this shift. Gas-fired generation increased significantly as the system relied more heavily on flexible thermal plants to cover higher demand and weaker renewable and hydro conditions. As a result, Italy maintained its position as the regional price premium market, even in a lower gas price environment. The key paradox is that while fuel became cheaper, system reliance on gas-fired generation increased, reinforcing high electricity prices during scarcity hours.
A similar pattern was observed in Croatia and Hungary, where prices rose despite the softer gas environment. In both cases, regional tightness and cross-border price transmission were more influential than the underlying fuel signal. Serbia also experienced higher prices even with improved domestic hydro conditions, demonstrating that broader regional pricing dynamics can lift SEEPEX independently of local fundamentals.
For electricity buyers, this marks a significant shift in risk assumptions. Many procurement strategies still implicitly assume that falling gas prices will translate into lower electricity costs. That relationship is weakening. In today’s system, marginal prices are increasingly determined by the specific hours when flexible generation is required, particularly during evening peak demand. Even if gas is cheaper, increased reliance on it during scarcity periods can still drive electricity prices higher.
For generators, the implications are more complex. Lower gas prices can reduce fuel costs for thermal plants, but they may also compress price peaks during non-scarcity hours. The most valuable market periods are increasingly those defined by system flexibility constraints, rather than purely by fuel price levels. Revenue formation is therefore shifting toward timing, ramping ability, and availability during peak stress conditions.
For policymakers and grid operators, the message is equally clear. Expanding renewable capacity without corresponding investment in flexibility does not guarantee lower prices across all hours. While solar generation can reduce midday prices, it also increases the importance of managing steep evening ramps, which require a combination of hydro resources, storage systems, demand response, interconnectors, and dispatchable generation. Without sufficient flexibility, fuel prices will continue to play only a partial role in overall market outcomes.
In conclusion, Week 25 confirms a structural reality in SEE energy markets: gas prices may be falling, but electricity markets remain driven by physical scarcity and system flexibility constraints. The result is a more complex, more volatile, and increasingly hour-dependent pricing environment.
