As wind and solar expand across South East Europe, developers are increasingly planning projects around a market reality that does not fully reward low marginal-cost generation. In the SEE power market, price signals remain closely linked to dispatchable thermal units even as renewables—hydro, solar and wind—take a larger share of output. This mismatch is shaping how utilities, industrial off-takers and investors evaluate revenue stability, grid needs and the timing of flexibility investments.
Renewables rise, but marginal pricing stays thermal
Renewable generation now accounts for close to 45% of output on peak days, with hydro and solar leading and wind contributing to the mix. Despite that structural shift, marginal price formation continues to be anchored in coal and gas units across most trading hours. The implication for project planning is straightforward: higher renewable penetration alone has not yet changed the system’s “last unit” pricing logic.
Early April 2026 data shows day-ahead prices clustered within a relatively narrow band of €84–91/MWh across key markets. Hungary (HUPX) cleared at €91.29/MWh, Serbia (SEEPEX) at €90.42/MWh, Romania (OPCOM) at €87.93/MWh, and Bulgaria (IBEX) at €84.58/MWh. These levels do not track renewable operating costs at the margin; instead they reflect the cost of meeting demand when variable generation cannot fully cover it.
Why variable output still forces dispatchable balancing
Solar output exceeding 3.9 GW is concentrated in daylight and cannot be dispatched on demand. Wind contributes roughly 1.9 GW but remains variable and often weakly correlated with demand peaks. Hydropower can provide flexibility, but reservoir management and hydrological conditions constrain how consistently it can be used to cover all hours.
Because these renewable sources cannot reliably meet demand across every time block, dispatchable thermal capacity continues to operate as the balancing backbone. On the observed day, coal generation was approximately 4,843 MW and gas contributed around 2,502 MW, together representing more than a quarter of total output. More importantly for market design and contracting strategies, these units are positioned to set prices during tighter supply conditions.
Fuel and carbon economics drive the clearing price
The cost stack behind thermal marginal pricing links electricity prices to fuel markets and carbon costs. Gas benchmarks are around €52/MWh, and with typical plant efficiencies of 50–55%, implied fuel cost before carbon sits in the €95–105/MWh range under full load assumptions. Adding CO₂ costs—currently about €70–75 per tonne—translates to roughly €25–35/MWh depending on emissions intensity, pushing marginal gas costs into a €120–140/MWh band.
Actual day-ahead prices can still come in below these theoretical levels due to operational realities such as long-term fuel contracts or efficiency differences across gas units. Coal plants can also undercut gas in parts of the merit order when coal prices fall; API2 benchmarks have declined by about 5%. In countries with substantial coal capacity such as Serbia and Bulgaria—where domestic lignite supports lower-cost supply—this effect becomes more pronounced for dispatch planning.
Merit order layering shapes intraday risk for projects
The interaction between coal and gas produces a layered price structure rather than a single “renewables-led” outcome. When demand is moderate and renewable output is high, coal can set the marginal price and keep overall levels lower. As demand rises or renewable output declines, gas moves into marginal supply, lifting prices.
This transition shows up in intraday patterns where evening peaks often coincide with falling solar output and require additional balancing from gas-fired generation. Carbon pricing further changes relative competitiveness: at current EUA levels (€70–75/t), coal faces an additional cost estimated at about €60–80/MWh compared with roughly €25–35/MWh for gas due to higher emissions intensity. Over time, that mechanism narrows coal’s advantage unless fuel costs or policy settings offset it.
Forward prices signal continued thermal reliance
Forward markets reflect the same structural linkage between power pricing and thermal economics. Power forward prices for calendar year 2026 are trading around €113–114/MWh, indicating expectations of continued reliance on thermal generation alongside sustained carbon pricing. For developers preparing EPC packages or grid connection schedules, this matters because contracting assumptions about price formation influence bankability models for both renewable build-out and storage revenue projections.
The fuel-price coupling also introduces volatility that affects hedging strategies across the value chain. Changes in gas prices tied to global LNG dynamics or shifts in carbon pricing can transmit quickly into electricity prices, creating both risk management needs and opportunities for participants engaged in trading frameworks. For operators planning dispatch rules or maintenance windows, this volatility increases the importance of operational studies that quantify how often thermal assets will remain marginal under different renewable scenarios.
Flexibility build-out remains central to changing outcomes
A transition away from thermal marginal pricing requires system changes rather than only capacity additions. Large-scale battery energy storage systems are positioned as a critical component because they can shift renewable output across time when solar declines or wind variability creates supply gaps. Demand-side flexibility—industrial load management and electrification strategies—can also reduce reliance on thermal generation by aligning consumption with renewable availability.
However, these solutions are still in early stages of deployment in the SEE region, so thermal generation continues to define marginal pricing even as its share of total generation declines. Until storage scale and demand response reach sufficient levels, developers should expect a transitional market environment where renewables reshape the supply curve but do not yet fully redefine dispatch economics.
Broader implications for grid modernization and investment readiness
For decarbonisation planning, higher renewable capacity can reduce emissions intensity while fossil fuels remain central to marginal price setting during balancing hours. That means project developers must treat grid modernization—transmission reinforcement and connection readiness—as part of a broader flexibility strategy rather than an isolated infrastructure task. Engineering studies that evaluate curtailment risk, congestion patterns and storage dispatch requirements become more consequential when market clearing remains thermally anchored.
For investors and utilities assessing pipeline priorities, asset value increasingly depends on position within the merit order and exposure to fuel and carbon costs—not only on nameplate generation profiles. Projects that can operate flexibly and respond to evolving price signals are likely to perform better in this environment as procurement frameworks move toward hybrid delivery concepts combining renewables with BESS capabilities.
Overall, the SEE market remains “in transition” rather than post-thermal: renewables are growing rapidly toward peak-day dominance, but marginal pricing still follows coal and gas constraints until flexibility solutions are integrated at scale into system operations.