As the energy landscape evolves, Southeast Europe (SEE) is witnessing a notable shift in its power market dynamics. Despite a marked absence of new gas project announcements, the role of gas in price formation has become more pronounced than ever, raising questions about the future of energy investment and regulatory frameworks in the region.
Currently, there is a distinct lack of new combined-cycle plants being inaugurated across SEE, with major state-backed gas expansion initiatives seemingly on hold. This stagnation coincides with increased scrutiny from financing institutions under EU taxonomy regulations, which are favoring investments in renewables and alternative energy sources. Consequently, political discourse has shifted towards promoting hydrogen, storage solutions, and interconnections, casting gas in a diminished light.
However, from a market perspective, gas remains a critical player. The transition from an expansion-focused model to one centered on operational dominance highlights that gas does not need to grow to influence price settings; it only needs to be essential during periods of market stress.
In countries such as Italy, Hungary, Romania, and Bulgaria, gas plants are now functioning within a tighter operational framework. Although they operate fewer hours than they did a decade ago, those hours are crucial for defining system pricing. For instance, Italy continues to derive approximately 61.91% of its electricity generation from gas-fired sources. During peak demand or tight supply conditions, prices closely align with TTF benchmarks due to gas’s marginal pricing influence.
The January 2026 power market exemplifies this trend. While solar energy output in Hungary led to lower midday prices, evening demand spikes reverted to gas pricing mechanisms. Similarly, Romania’s hydroelectric capacity fell short during winter months, pushing prices beyond €150/MWh, primarily due to existing gas facilities stepping in to fill the gap.
This persistent dominance of gas can be attributed to the absence of an alternative flexibility layer capable of managing multi-day or multi-hour demands. Although battery storage projects like the 202 MW / 500 MWh battery at Maritsa East 3 provide essential balancing services, they cannot offer sustained support through extended cold spells or prolonged periods of low renewable output. Advances in pumped storage projects are underway but will take years to materialize fully. Demand-side flexibility also remains limited across the region.
The reluctance to announce new gas projects stems largely from regulatory economics influenced by EU climate policies and financial constraints. Investors are wary of committing capital to assets that may face regulatory challenges as decarbonization efforts intensify over the coming decades.
Despite this stagnation in new builds, many existing gas plants in SEE are either fully amortized or partially depreciated and do not require significant capital investment to continue operations. This situation creates an asymmetry where gas can maintain its dominance without needing new financing for expansion.
The tightening regulatory environment may have inadvertently solidified gas’s position in the short-to-medium term by discouraging new capacity additions while increasing reliance on existing infrastructure amid growing renewable intermittency. As stress events occur within the system, reliance on established gas facilities intensifies their marginal pricing power.
Cross-border integration further enhances this dynamic by synchronizing pricing across markets. For example, when Italian markets adjust based on LNG-linked costs, those price signals propagate into Slovenia and Croatia. Hungary’s imports reflect Central European pricing structures that extend into Serbia and Romania as well.
The increasing share of LNG—currently around 57% of European imports—is reshaping regional markets as global dynamics exert more influence over local pricing structures. Projections suggest this could rise to 75–80% by 2030, meaning that trends originating from international markets can impact SEE power prices rapidly.
An often-overlooked aspect is that natural gas plays a vital role in facilitating renewable investments themselves; solar and wind projects depend on price forecasts influenced by natural gas expectations for their economic viability. Furthermore, capacity remuneration mechanisms rely on dispatchable natural gas resources for maintaining system reliability during peak demand periods.
The current situation illustrates a paradox: while political discourse may downplay the significance of natural gas amidst a push for renewables, its economic relevance remains undeniable. Gas is operationally critical yet strategically constrained; it runs fewer hours but yields higher revenues and continues to shape market behavior significantly.
This reality is reflected in forward market behaviors where power futures embed risk premiums associated with natural gas during winter months and peak quarters. Traders hedge against renewable exposure using instruments linked to natural gas prices while storage developers account for revenues based on potential volatility scenarios tied to natural gas dynamics.
The prevailing silence regarding new gas projects should not mislead stakeholders; rather than measuring dominance through newly commissioned megawatts, it should be assessed by marginal hours cleared within power markets. Until scalable alternatives emerge capable of providing comparable levels of flexibility and endurance as natural gas currently does, it will remain central to defining price structures and maintaining system security across Southeast Europe.
