Gas’s return to marginal pricing reshapes Southeastern Europe’s power market

For much of the past decade, Southeastern Europe has tried to frame itself as gradually moving beyond gas dependency. Coal dominated in parts of the Western Balkans, hydropower helped stabilize balancing, and renewables increasingly shaped long-term policy narratives—while gas was often treated as politically sensitive and strategically vulnerable after Europe’s post-2022 supply crisis.

But the first half of May 2026 offered a different picture: gas has returned to the center of regional electricity pricing, not because demand surged, but because other generation sources weakened at exactly the wrong time for system flexibility.

May’s supply mix pushed gas back into balancing

Across the broader HU+SEE system, gas-fired generation increased by about 362 MW during the observed period even as total regional electricity demand declined by roughly 1,018 MW. At the same time, nuclear output fell sharply by 1,686 MW, coal generation declined by 260 MW, and hydro output weakened by another 357 MW.

This combination forced gas back into a marginal balancing role precisely as renewable volatility intensified across the region and thermal reliability declined. The market response was immediate: Romania’s OPCOM jumped to €115.88/MWh, Hungary’s HUPX reached €108.62/MWh, Bulgaria’s IBEX climbed to €104.98/MWh, Croatia’s CROPEX averaged €105.77/MWh, and Serbia’s SEEPEX moved above €101/MWh.

Prices rose despite weaker consumption and improving temperatures—an outcome that matters for investors because it signals a shift away from demand-driven pricing toward marginal generation scarcity. In that setting, gas remains one of the most capable technologies for filling shortfalls quickly enough to influence hourly outcomes.

Renewables are expanding—but they increase the need for flexibility

The return of gas marginality does not imply an abandonment of decarbonization goals. Instead, it reflects how intermittent renewables can raise short-term balancing requirements when storage and grid flexibility are not yet fully mature.

The article points to rapid solar and wind expansion across Bulgaria, Greece, Romania, Serbia and North Macedonia. Yet renewable generation alone cannot reliably stabilize hourly balancing dynamics—especially during evening ramps, low-wind periods or seasonal hydro fluctuations.

At the same time, coal fleets are facing growing operational stress. Across Bosnia and Herzegovina, Montenegro and Serbia, aging coal infrastructure is increasingly described as encountering instability and maintenance challenges alongside financing pressure and environmental constraints. RiTE Ugljevik spent months offline before returning in early May; RiTE Gacko reported sharply deteriorating profitability; Montenegro’s Pljevlja operations also showed worsening financial performance.

Nuclear availability also weakened during the period: Bulgaria’s Kozloduy Unit 5 entered maintenance while Romania’s Cernavoda Unit 2 remained affected by extended technical issues.

With baseload systems under strain and renewable variability rising, flexible gas becomes a scalable balancing mechanism—able to ramp quickly relative to coal and hydro constraints tied to hydrology. The piece also notes that gas can provide extended-duration balancing compared with current storage duration limitations.

Gas infrastructure now has a second purpose

This development changes how regional gas infrastructure is likely to be valued. For several years, projects such as Alexandroupolis LNG terminal, the Vertical Gas Corridor and expanded interconnections across Greece, Bulgaria, Serbia and North Macedonia were discussed mainly through diversification away from Russian supplies.

That diversification rationale remains relevant—but the article adds a second strategic role: supporting operational stability in electricity systems with higher renewable penetration.

The timing is particularly sensitive because SEE electricity markets are moving into a structurally more volatile phase. Solar growth continues accelerating across the region; Bulgaria is emerging as a storage-and-solar hub; Greece faces curtailment pressure and midday oversupply; Romania expands renewables while dealing with grid bottlenecks; Serbia is moving toward larger-scale solar deployment alongside wind growth. The result is a system where daytime oversupply increasingly coexists with evening scarcity—conditions under which fast-ramping capacity can become decisive.

LNG uncertainty meets rising short-term dependence

The article highlights an important tension for policymakers: physical gas flows may be declining even as prices stay elevated due to global LNG market volatility tied to geopolitical disruptions in Middle Eastern supply chains and tighter competition for cargoes.

It notes that TurkStream deliveries to Europe fell again in April on both a month-on-month and year-on-year basis. Yet despite lower flows into Europe, regional prices remained high because global LNG markets continued experiencing geopolitical volatility.

For SEE governments and utilities this creates a paradox—more flexibility is needed at precisely the moment long-term procurement becomes more geopolitically and financially uncertain. That tension is shaping investment decisions across multiple fronts: renewable expansion; battery storage deployment; gas interconnection development; LNG access diversification; coal phase-down strategies; grid modernization; and balancing infrastructure investment.

Implications for trading—and project finance

The shift also affects how power trading behavior may evolve. Historically, SEE traders focused heavily on hydro conditions, coal availability and seasonal demand swings. Going forward, the piece argues that correlations between gas hubs—alongside LNG flows—and regional power exchanges are strengthening again as spreads between fuel markets increasingly influence electricity pricing behavior.

During the period referenced in the article, CEGH gas prices averaged approximately €46.64/MWh while Greek gas prices remained near €45.22/MWh. Carbon prices were described as slightly weaker at around €74.96/t; however, fuel-plus-carbon economics still supported elevated thermal marginal pricing.

This reinforces what the article frames as one of Europe’s transition contradictions: renewables can reduce long-term fossil dependency while simultaneously increasing short-term balancing reliance on gas until large-scale storage deployment, transmission reinforcement and flexibility infrastructure fully mature.

For financing decisions, that dynamic could raise utilization assumptions for flexible assets such as combined-cycle plants configured for ramping needs or peakers able to participate in balancing markets—and for hybrid approaches combining gas with renewables. At the same time, it cautions that pure baseload exposure remains risky under decarbonization pressure and potential carbon price escalation.

A flexibility-led strategy looks more resilient

The article extends its conclusions beyond fuel type toward system design: countries that combine flexible gas access with renewable generation capacity, battery storage capability, cross-border interconnections and complementary hydropower balancing—along with industrial demand response—are positioned to achieve stronger pricing stability and energy security than systems overly dependent on any single source.

It identifies Greece as increasingly positioned as a regional hub within this evolving structure due to its LNG infrastructure profile, interconnection investments and expanding renewable base. Bulgaria is described as strengthening its role through storage deployment and transmission positioning. Serbia’s importance is expected to grow due to its central geography linking Central Europe with the Balkans—and future corridor expansions.

Ultimately, the piece argues that reliable flexible energy supply affects more than electricity markets: industrial competitiveness—including data center development—hydrogen projects and aluminum processing economics can depend on stability rather than purely low-cost generation alone.

The first half of May 2026 demonstrated how quickly these realities are already reshaping Southeastern European electricity markets—bringing gas back not as a dominant long-term fuel narrative on its own terms but as a stabilizing mechanism underpinning a transition toward far more renewable-heavy power systems.