Gas risk remains embedded as renewables reshape daily profiles
While policy debate across South-East Europe increasingly frames gas as a transitional fuel, trading behaviour entering 2026 suggests a more persistent role in price formation. The key issue for developers and grid planners is not whether gas runs frequently on average, but whether it sets prices during scarcity intervals that anchor forward curves and system risk. In the 2026–2027 horizon, gas is expected to remain structurally embedded without relying on new gas plant construction, because no near-term alternative can replicate gas flexibility under real operating conditions.
For project execution teams, this distinction matters for how grid constraints, dispatch strategies, and market revenue assumptions are stress-tested. Renewables build-outs may change intraday shapes, but they do not remove the operational moments when dispatchable capacity is required. That reality is likely to influence how utilities structure offtake terms, how industrial buyers underwrite demand response, and how investors model downside scenarios for merchant exposure.
Scarcity timing drives marginality: fewer hours, higher impact
Gas marginality in the near term is described as a timing phenomenon rather than a utilisation-volume story. Across the region, gas is expected to set prices in roughly 20–30% of hours under normal conditions. During stress periods, that share is projected to expand rapidly toward 40–60%, even where renewable penetration is high.
Operationally, this implies that system adequacy planning cannot rely solely on average generation mixes or annual energy shares. Instead, it must focus on winter evenings, cold spells, low-wind regimes, hydro drawdown periods, and LNG-driven price shocks—intervals where scarcity pricing can reassert itself quickly. For transmission operators and balancing authorities, the planning challenge becomes managing volatility and ramping requirements when gas becomes the marginal reference again.
Solar growth suppresses midday prices but shifts scarcity into ramps
New solar capacity across Hungary, Romania, Bulgaria, Serbia and Greece is reshaping intraday price patterns. Midday prices are increasingly suppressed and in some markets can turn intermittently negative during high-irradiance periods. However, the analysis indicates this does not weaken gas marginality; it relocates it to different hours of the day.
As solar output concentrates around midday production windows, scarcity is expected to shift into evening ramp hours, early morning blocks and winter peaks—precisely when flexible generation and fast balancing response are most valuable. For BESS developers and EPC preparation teams, this reinforces the need to align battery dispatch studies with ramp-rate stress cases rather than only energy arbitrage profiles. It also affects curtailment assumptions and grid reinforcement priorities where solar-driven congestion may interact with evening demand peaks.
Wind and hydropower provide conditional relief without structural decoupling
Wind additions across Greece and parts of Romania are expected to reduce gas dispatch during favourable regimes. Yet forecast uncertainty and calm periods remain unavoidable, leaving gas as the fallback technology when wind fails to deliver at scale. In parallel, hydropower continues to act as a powerful short-term suppressor of gas marginality when reservoirs are full.
The same assessment stresses that hydropower does not eliminate gas risk; it can mask it. Once inflows weaken or reservoirs are drawn down, repricing can be abrupt and severe. For utilities planning generation portfolios and grid modernization roadmaps, this means hydro variability should be incorporated into reliability studies as a source of “false decoupling” rather than treated as a durable substitute for flexibility.
BESS deployments improve intraday efficiency but do not replace endurance
Battery storage expansion is underway across the region’s pipeline landscape, but commissioned systems are characterised as short-duration assets. Even the largest commissioned systems provide only 2–3 hours of full-power discharge. While batteries can improve intraday efficiency by smoothing ramps and shaving peaks, they do not provide endurance for multi-day cold spells or prolonged low-wind periods.
In practical terms for 2026–2027 planning cycles, batteries are positioned to optimise gas usage rather than replace it. They delay gas dispatch by hours rather than days, which can increase the price impact of the later hours when gas ultimately clears the market. This has direct implications for procurement frameworks: developers preparing EPC scopes and commissioning plans may need to demonstrate performance under multi-day stress assumptions even if commercial operation targets shorter cycling regimes.
LNG exposure and storage balance set the near-term direction
The analysis places decisive drivers upstream in LNG exposure and storage balance rather than in domestic generation build rates. LNG accounts for approximately 57% of EU gas imports, while South-East Europe faces indirect exposure through Italy, Greece and Central European hubs. Gas pricing in the region is therefore linked to global LNG dynamics including shipping availability, Asian demand pull and expectations around storage refill.
Storage levels entering winter are described as a 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. For investors underwriting risk premia in power markets—and for system planners setting reserve margins—this makes winter readiness a central input to CAPEX planning for grids and flexibility resources.
Forward contracts keep pricing explicit gas risk through 2026–2027
Forward markets are cited as confirming continued exposure rather than early marginality decay. Across South-East European hubs, winter and peak contracts for 2026–2027 continue to price explicit gas risk premia. Summer baseload contracts flatten under solar pressure, but peak premiums remain elevated.
If marginality were genuinely decaying near term, the signal would be expected first through compression of peak forwards; that pattern is described as absent. For developers preparing bankable revenue models—whether for wind repowering studies, solar expansion phases or BESS merchant strategies—this suggests that peak exposure remains a core variable that must be reflected in contracting structures and operational readiness plans.
What would have to change by end-2027—and why it is unlikely at scale
The assessment identifies several conditions that would need to materialise to materially weaken gas marginality by end-2027: multi-day storage commissioned at scale; demand-side flexibility delivering real price elasticity; major new hydro capacity entering service; or an extended LNG oversupply phase structurally suppressing gas prices. None of these are described as locked in at sufficient scale within the next two years.
This framing has practical consequences for engineering studies and procurement sequencing. Grid modernization programmes that assume rapid structural decoupling from gas may face misalignment between design basis assumptions and actual scarcity-hour behaviour. Likewise EPC preparation for BESS or renewable projects may need updated system studies that incorporate timing-driven scarcity rather than relying on average load factors alone.
Implications for utilities, contractors and industrial stakeholders
For 2026–2027 the conclusion is that gas marginality remains structurally intact while becoming less frequent yet more concentrated during stress events. The near-term challenge for power markets is therefore not managing an exit from gas but managing gas risk more intelligently within systems increasingly shaped by renewables and short-duration storage.
Beyond generation investment planning, this points to broader industry implications: transmission operators will need robust congestion and balancing strategies around winter peaks; developers should align feasibility studies with scarcity-hour timing; contractors preparing EPC scopes should validate performance under ramping and multi-day stress scenarios where relevant; and investors should treat peak exposure as persistent when structuring contracts through 2026–2027.