The energy market in Southeast Europe (SEE) is currently navigating a paradoxical phase where the visibility of gas projects has diminished significantly, yet the influence of gas on price formation has never been stronger. As of early 2026, the absence of new combined-cycle plants and state-backed gas expansion initiatives reflects a broader narrative shift towards renewables and alternative energy sources. However, this transition does not diminish the operational importance of gas in the region’s power markets.
In countries like Italy, Hungary, Romania, and Bulgaria, gas-fired plants are operating within a narrower but more critical marginal window. Although these facilities are running fewer hours compared to a decade ago, their operational time is pivotal for determining system pricing. For instance, in Italy, approximately 61.91% of electricity generation is still dependent on gas, with marginal pricing closely tracking TTF benchmarks during peak demand periods.
The dynamics of the January 2026 market exemplify this trend. In Hungary, solar energy saturation led to lower midday prices; however, evening peaks reverted to gas pricing. Similarly, in Romania, hydroelectric output failures resulted in prices exceeding €150/MWh, highlighting how existing gas capacity plays a crucial role in filling flexibility gaps rather than relying on new infrastructure.
The ongoing reliance on gas can be attributed to the lack of developed alternatives capable of providing multi-day flexibility. Current battery storage projects, such as the 202 MW / 500 MWh battery at Maritsa East 3, offer essential balancing services but fall short during extended periods of low renewable output or severe weather conditions. While pumped storage initiatives are progressing, their timelines extend years into the future, leaving demand-side flexibility limited.
The regulatory landscape complicates the introduction of new gas projects. EU climate policies and financing constraints have created a cautious environment for investors, who are wary of committing capital to assets that may face increasing regulatory pressures over time. This hesitation has led to a significant reduction in new gas capacity announcements across SEE.
Despite the stagnation in new developments, existing gas plants remain economically viable due to their amortized status and fuel-driven cost structures. This creates a structural advantage for gas as it does not require fresh financing to maintain its dominance in marginal pricing. In fact, the tightening regulatory environment may have inadvertently bolstered gas’s position in the short to medium term by limiting new capacity additions while increasing reliance on existing infrastructure during periods of high demand.
Cross-border integration further amplifies this trend. Interconnectors facilitate synchronized pricing across markets; for example, Italian pricing influenced by LNG-linked costs extends into Slovenia and Croatia. As Hungary imports Central European pricing models and transmits them into Serbia and Romania, the development of new 400 kV corridors is expected to enhance this interconnectedness.
The rise of LNG imports has also transformed market dynamics. Currently, approximately 57% of European gas imports come from LNG sources, with projections suggesting this could rise to 75–80% by 2030. Such dependence exposes SEE markets to global fluctuations—whether due to weather events or demand shifts in Asia—demonstrating that gas dominance is increasingly a global phenomenon rather than merely regional.
Moreover, gas plays an essential role in supporting renewable investments. Solar and wind projects are often evaluated against forward curves shaped by expectations around gas prices. Storage arbitrage relies heavily on spreads driven by gas dynamics, while capacity remuneration mechanisms necessitate dispatchable gas resources to ensure adequacy during peak demand periods.
While it is clear that gas faces long-term challenges from evolving policy trajectories—including hydrogen blending and carbon capture technologies—the current landscape underscores its critical role within the energy transition framework. Gas remains operationally vital even as its growth narrative fades.
This complex interplay reveals that while political discourse may downplay gas’s significance in favor of renewables, its economic centrality cannot be overlooked. Gas continues to dictate revenue streams despite operating fewer hours than before and remains essential for maintaining system security and price stability across SEE power markets.
As traders embed risk premiums related to gas into power futures for winter months and peak quarters, it becomes evident that market behavior reflects an ongoing reliance on gas—even without new plant constructions. The silence surrounding new gas projects may be misleading; instead of measuring dominance by newly commissioned megawatts, it is essential to consider how marginal hours cleared continue to affirm gas’s pivotal role until scalable alternatives emerge.
