South-East Europe’s accelerating wind and solar build-out is changing how power systems swing through the day, but it is not breaking the pricing link to fossil fuel economics. Market clearing outcomes still reflect thermal generation’s role in setting marginal prices, meaning gas and EU ETS carbon costs continue to travel through into electricity benchmarks even as renewable output rises. For developers and grid planners, that matters because revenue expectations, dispatch assumptions, and risk models remain anchored to fuel-and-carbon dynamics.
Renewables drive timing shifts, thermal units set the price floor
Early April 2026 data shows day-ahead prices across the region trading in a relatively tight band of €84–91/MWh despite swings in renewable output and cross-border flows. The pattern points to a system where renewables influence volatility and intraday timing, while thermal assets still define the price floor. In practical terms for project development, this reinforces that intermittent generation can alter operational stress on balancing resources without fully decoupling market prices from conventional marginal costs.
As renewable penetration increases, negative pricing events become more frequent, but the clearing mechanism remains dependent on which technology is marginal at each moment. That keeps thermal generation central to both dispatch planning and market settlement, even when renewables offer near-zero marginal cost electricity. For operators of wind and solar portfolios, capture-price risk therefore rises alongside volatility rather than disappearing.
Gas economics remain central during evening peaks
Gas continues to act as the primary marginal fuel across much of the region, particularly during evening peak hours and periods when renewable output is low. With benchmark gas prices around €52/MWh, combined-cycle gas turbine generation costs can be estimated by applying plant efficiency assumptions of 50–55%, producing a fuel component of roughly €95–105/MWh for electricity output. This fuel baseline becomes the starting point for additional cost layers that determine whether gas is dispatched as the marginal technology.
The operational relevance for system planners is that peak-demand scheduling and reserve requirements are still likely to pull gas into the merit order when wind and solar output cannot cover load. That linkage affects how developers structure offtake strategies, how utilities plan balancing-market participation, and how investors evaluate merchant exposure versus contracted revenue.
EU ETS carbon pricing adds a second cost driver
Under the EU Emissions Trading System, EUA prices in the range of €70–75 per tonne add material costs to thermal generation. For gas-fired units, that translates into approximately €25–35/MWh depending on emissions intensity. Coal-fired generation faces an even larger carbon component, with carbon costs reaching €60–80/MWh due to higher emissions factors.
When fuel and carbon are combined, full cost conditions place gas-fired generation in the €120–140/MWh range. Actual market prices are often lower because of partial load operation, contract structures, and periods when lower-cost generation—particularly coal and hydro—can set clearing prices. Still, the underlying relationship between electricity benchmarks and fuel/carbon economics remains visible most clearly during peak demand hours when gas is required to balance the system.
Coal-lignite markets keep merit-order sensitivity alive
Coal remains significant in price formation in countries with domestic lignite resources such as Serbia and Bulgaria. Even with higher carbon costs, coal’s lower fuel cost can make it competitive with gas under certain conditions, creating a layered merit order where coal and gas compete depending on demand levels, renewable output, and relative fuel prices. This dual-fuel interaction means that changes in EUA pricing can shift which thermal technology is marginal.
As EUA prices rise, coal’s cost advantage diminishes gradually, shifting the merit order toward gas. The transition is uneven across the region due to differences in plant efficiency, fuel supply arrangements, and regulatory frameworks. For developers planning wind, solar, or battery energy storage (BESS) projects intended to support peak shaving or capacity value claims, these regional differences affect how often thermal units remain price-setting under high-carbon scenarios.
Implications for BESS planning and grid modernization readiness
The persistence of thermal marginal pricing has direct consequences for renewable economics: even though wind and solar generate at near-zero marginal cost, their revenues are determined by market clearing prices set by thermal units. That creates an implicit subsidy effect when fossil-linked prices are elevated. However, rising renewable penetration also reduces capture prices as negative pricing becomes more common, tightening the link between revenue performance and operational strategy.
For BESS developers and EPC teams preparing studies for interconnection and dispatch integration, this environment increases the importance of technical project planning around price-shaping rather than assuming full decoupling from thermal costs. Large-scale storage capable of shifting renewable output across time can begin displacing thermal units in the merit order as capacity grows, reducing how strongly gas and carbon costs influence price formation. In parallel, demand-side flexibility—through electrification of heating, transport, and industry combined with smart demand management—can reduce reliance on thermal balancing during high-price periods.
Forward markets signal continued thermal-and-carbon linkage
Power forward contracts for calendar year 2026 are trading around €113–114/MWh. The level reflects expectations of continued reliance on thermal generation alongside sustained carbon pricing assumptions embedded in market models. For investors underwriting CAPEX planning and financing structures—particularly where merchant exposure is part of the capital stack—these forward signals reinforce that risk assessment must treat fuel supply shocks and EUA movements as core drivers rather than secondary variables.
Volatility remains high because gas prices respond to global factors including LNG supply conditions, geopolitical developments, and weather patterns. Carbon prices are shaped by EU policy signals, market expectations, and macroeconomic conditions. Changes in either variable can quickly transmit into electricity pricing outcomes across SEE systems.
Cross-border integration amplifies price transmission effects
This volatility matters beyond national borders because SEE markets are increasingly integrated with Central and Western Europe. Price movements can propagate rapidly across regions: gas price shocks can lift electricity prices simultaneously across multiple markets while EUA increases affect all EU-linked systems together. For transmission infrastructure planners assessing grid modernization priorities—such as reinforcement for cross-border flows—this interconnectedness raises the operational stakes for congestion management studies.
The same linkage also affects industrial competitiveness since electricity costs influence energy-intensive industries exposed to international competition. Mechanisms such as the Carbon Border Adjustment Mechanism (CBAM) further reinforce alignment between power-sector charges and carbon policy because imported goods face carbon-related charges. That creates pressure on policymakers to balance decarbonisation objectives with affordability concerns through compensation schemes for affected industries alongside investment support for low-carbon generation and flexibility.
What this means for engineering studies through operations
Near to medium term system operation is likely to remain hybrid: renewables expand quickly while pricing mechanisms remain rooted in fossil-linked marginality until alternative marginal technologies scale sufficiently. The pace depends on investment speed not only in storage capacity but also in grid infrastructure reinforcement and demand-side solutions supported by evolving policy frameworks. For engineering studies that feed into permitting strategies and procurement packages—especially EPC preparation—assumptions about dispatch frequency of thermal assets should remain central rather than treated as transitional noise.
For developers, contractors, utilities, operators, and investors active across wind development pipelines, solar build-outs, BESS integration programs, transmission upgrades, and related technical study workstreams (including feasibility modeling for interconnection), the key takeaway is structural: until flexibility displaces thermal marginal units at scale, gas and EU ETS carbon will continue to drive SEE electricity price levels even as renewable-driven volatility grows.
Broader industry implication: project value will increasingly hinge on exposure management to fuel-and-carbon-linked price formation—supported by hedging design choices—and on engineering readiness for storage-enabled shifting plus grid modernization that can handle cross-border volatility without undermining operational reliability.