The energy landscape in South-East Europe is at a critical juncture as it heads into 2026. Despite an increasing focus on renewable energy sources and advanced battery technology, the role of gas in power price formation remains significant and structurally embedded. Market dynamics indicate that gas will continue to play a crucial role, particularly during peak demand periods, thereby shaping electricity pricing strategies across the region.
As the region prepares for the next two years, it is essential to consider existing infrastructure and realistic deliverables by the end of 2027. While there is a push for expanding battery storage capabilities, most of the newly commissioned capacity is designed for short-duration output. Hydropower continues to be vulnerable to weather fluctuations, while nuclear energy remains largely inflexible. Although solar energy installations are on the rise, they predominantly generate power during midday hours. Wind energy growth also faces challenges due to its dependence on weather forecasts and seasonal variations. In this context, gas infrastructure is sufficiently developed to address any foreseeable stress scenarios without necessitating additional capacity.
Understanding gas marginality requires a focus on timing rather than mere utilization volume. In 2026-2027, while gas may not dominate average generation statistics, it will significantly influence critical hours—such as winter evenings and periods of low wind or hydro availability—where its flexibility becomes indispensable. Under typical conditions, gas is expected to set prices in approximately 20-30% of hours across South-East Europe; however, this share could surge to 40-60% during times of stress. This shift reflects a temporal compression rather than a decline in gas’s marginality.
The expansion of solar energy further illustrates this point. New solar capacity across Hungary, Romania, Bulgaria, Serbia, and Greece has led to suppressed midday prices, with some markets even experiencing negative pricing during high-irradiance periods. However, this does not diminish the importance of gas; instead, it shifts scarcity into evening ramp hours and winter peaks when gas generation becomes critical.
Wind and hydropower present conditional alternatives but do not provide a definitive escape from reliance on gas in the near term. Wind energy can reduce gas dispatch during favorable conditions; yet forecast uncertainties remain a challenge. Similarly, hydropower can suppress gas marginality when reservoirs are full but does not eliminate the risks associated with gas dependency. The potential for abrupt price adjustments arises when water inflows decrease or reservoir levels drop.
Battery storage systems are rapidly deployed but currently offer limited discharge durations—typically only 2-3 hours. These systems enhance operational efficiency and help manage peaks but cannot sustain operations through extended cold spells or prolonged low-wind events. Consequently, batteries optimize gas usage rather than replace it entirely.
The key variables influencing gas marginality over the next two years include LNG exposure and storage levels. Currently accounting for around 57% of EU gas imports, LNG dynamics increasingly dictate pricing in South-East Europe through interconnected markets in Italy and Central Europe. The state of storage entering winter has emerged as a pivotal factor; well-filled storage can stabilize prices while tight storage conditions may lead to sharp price spikes under moderate weather stress.
The forward markets reflect these realities clearly: winter and peak contracts for 2026-2027 continue to incorporate explicit risk premiums associated with gas reliance. Although summer baseload prices may flatten due to solar pressure, elevated peak premiums indicate ongoing exposure to gas risks rather than any anticipated reduction in dependency.
A substantial change would be required to materially weaken the current structural role of gas by 2027—such as large-scale deployment of multi-day storage solutions or significant advancements in demand-side flexibility—none of which appear feasible within the next two years.
The outlook for 2026-2027 indicates that while instances of gas usage may become less frequent, they will be more concentrated during critical periods when demand surges. The challenge ahead lies not in transitioning away from gas but rather in managing associated risks within an evolving system increasingly influenced by renewables and short-duration storage technologies.
In conclusion, power market participants should prepare for continued reliance on gas as a defining factor in South-East European electricity pricing amid ongoing transitions toward renewable sources.
