Across South-East Europe, the debate around gas has shifted faster than the system itself. Policy language increasingly treats gas as a transitional relic, while investment headlines focus on renewables, batteries, and grids. Yet market behaviour entering 2026 tells a far more conservative story. Gas marginality is not fading in the near term. It is consolidating, compressing into fewer hours, but becoming more decisive precisely when the system is under pressure. For 2026–2027, gas remains structurally embedded in price formation, not because of new construction, but because no alternative is capable of replacing its role under real operating conditions.
The starting point for the next two years is not theoretical. It is shaped by what is already built, what is already connected, and what is realistically deliverable before the end of 2027. Battery pipelines are expanding, but almost all commissioned capacity remains short-duration. Hydropower output remains exposed to weather volatility. Nuclear output remains inflexible. Solar additions are accelerating, but overwhelmingly skewed toward midday production. Wind is growing, but remains forecast-dependent and seasonally uneven. Against this backdrop, gas infrastructure is already sufficient to meet every foreseeable stress scenario without the need for additional capacity. The system does not require more gas plants for gas to remain marginal. It only requires moments of scarcity, and those moments remain unavoidable.
Gas marginality in the near term is often misunderstood as a function of utilisation volume. In reality, it is a function of timing. In 2026–2027, gas will not dominate average generation statistics, but it will continue to dominate the hours that matter most: winter evenings, cold spells, low-wind regimes, hydro drawdown periods, and LNG-driven price shocks. Under normal conditions, gas will continue to set prices in roughly 20–30% of hours across the region. During stress, that share expands rapidly toward 40–60%, even in systems with high renewable penetration. This is not marginality decay. It is temporal compression, with gas influence retreating from surplus hours and intensifying in scarcity hours that anchor forward curves, peak contracts, and system risk.
Solar expansion illustrates this compression clearly. Across Hungary, Romania, Bulgaria, Serbia, and Greece, new solar capacity is reshaping intraday price profiles. Midday prices are increasingly suppressed and, in some markets, intermittently negative during high-irradiance periods. Yet this does not weaken gas marginality. It relocates it. Scarcity shifts into evening ramp hours, early morning blocks, and winter peaks, precisely the intervals where gas flexibility is indispensable. Solar does not remove gas from the system. It sharpens the convexity of prices and increases the economic importance of the hours when gas is required. Gas runs less often, but when it runs, it matters more.
Wind and hydro offer conditional relief, but neither provides structural escape from gas in the near term. Wind additions across Greece and parts of Romania reduce gas dispatch during favourable regimes, but forecast uncertainty and calm periods remain unavoidable. Gas remains the fallback technology whenever wind fails to deliver at scale. Hydropower, meanwhile, remains the most powerful short-term suppressor of gas marginality when reservoirs are full, as demonstrated in Serbia and Greece in early 2026. Yet hydro does not eliminate gas risk. It masks it. Once inflows weaken or reservoirs are drawn down, repricing is abrupt and severe. In the 2026–2027 horizon, hydro introduces false decoupling signals rather than durable structural change.
Battery storage, despite rapid deployment, does not alter this balance. Even the largest commissioned systems in the region provide only 2–3 hours of full-power discharge. These assets improve intraday efficiency, smooth ramps, and shave peaks, but they do not provide endurance. They cannot cover multi-day cold spells, prolonged low-wind periods, or late-winter storage depletion scenarios. In practical terms, batteries in 2026–2027 optimise gas usage rather than replace it. They delay gas dispatch by hours, not days, and in doing so often increase the price impact of the hours when gas ultimately clears the market.
The decisive variables shaping gas marginality over the next two years lie upstream, in LNG exposure and storage balance. LNG now accounts for approximately 57% of EU gas imports, and South-East Europe is increasingly exposed indirectly through Italy, Greece, and Central European hubs. Gas pricing in the region is no longer driven primarily by domestic fundamentals, but by global LNG dynamics, shipping availability, Asian demand pull, and expectations around storage refill. Storage levels entering winter have become the critical shock absorber. In a well-filled storage scenario, gas prices stabilise and marginality appears manageable. In a tight storage scenario, even moderate weather stress can trigger disproportionate power price responses. Gas marginality in the near term is therefore binary, not gradual.
Forward markets confirm this reality with little ambiguity. Across South-East European hubs, winter and peak contracts for 2026–2027 continue to price explicit gas risk premia. Summer baseload flattens under solar pressure, but peak premiums remain elevated. If gas marginality were genuinely decaying in the near term, it would first appear through compression of peak forwards. That signal is not present. Markets are not pricing a near-term escape from gas. They are pricing continued exposure.
What would need to change to materially weaken gas marginality by the end of 2027 is equally clear, and equally unrealistic. Multi-day storage would need to be commissioned at scale. Demand-side flexibility would need to achieve real price elasticity. Major new hydro capacity would need to enter service. Or LNG markets would need to enter a sustained oversupply phase that structurally suppresses gas prices. None of these conditions are locked in at sufficient scale within the next two years.
The conclusion for 2026–2027 is therefore not ambiguous. Gas marginality remains structurally intact. It will be less frequent, more concentrated, more volatile, and more decisive during stress. The near-term challenge for power markets is not managing a transition away from gas, but managing gas risk more intelligently within a system increasingly shaped by renewables and short-duration storage. Any pricing, trading, or investment strategy that assumes early marginality decay risks mispricing peak exposure.
Gas will not disappear from South-East European power price formation in 2026–2027. It will define it when the system is tested.
Elevated by virtu.energy
