The bankability of renewable energy projects in Southeast Europe is changing, with Week 23 illustrating why average day-ahead prices are no longer sufficient. The region saw higher demand, weaker variable renewables, stronger thermal dispatch, higher imports and wide price divergence across markets. A project financed on a simple average-price assumption would miss most of the real risk.
Week 23 demand, generation and price divergence
Variable renewable output fell 8.9% week on week, including wind down 15.5% and solar down 5.1%. Regional electricity demand rose 8.2% to 15.15 TWh. Thermal generation increased 24.5%, while net imports rose 9.1%.
Prices moved differently across the region, with Bulgaria and Italy rising while Serbia, Hungary, Croatia and Romania softened. This combination of demand growth, reduced variable output and higher thermal dispatch coincided with the observed divergence in market pricing.
Why average day-ahead prices can miss project risk
The market conditions described in Week 23 can expose weak revenue modelling for merchant and contracted renewable assets. Solar generation can face low midday prices even when weekly averages remain elevated. Wind output may be supported by strong annual production but still incur high imbalance costs during volatile weeks.
Merchant exposure can also depend on how generation aligns with higher-price hours. If a project’s generation profile is poorly matched to periods with elevated prices, the value implied by average market pricing may not be realised.
Layered revenue stacks for bankable RES projects
Bankable RES projects increasingly require layered revenue stacks rather than relying on day-ahead income alone. Beyond day-ahead market revenues, developers are expected to account for intraday optimisation and balancing-market participation. Ancillary services, corporate PPAs and guarantees of origin also form part of the revenue mix.
Battery co-location and curtailment management are additional elements that can affect project outcomes under changing market conditions. In this context, a stronger revenue stack is described as improving resilience against the risks reflected in Week 23.
Contract structures and risk allocation in key SEE markets
The approach is especially relevant in Greece, Romania, Bulgaria, Croatia, Serbia and Hungary as renewable pipelines grow and grid constraints become more visible. Lenders are described as needing to assess not only energy volumes but also timing of production, connection location and imbalance-risk allocation. Curtailment allocation is also highlighted as a factor in financing discussions.
Corporate PPAs are cited as potentially improving bankability when structured appropriately. Fixed-price PPAs can reduce merchant exposure but may shift shape and balancing risk to the generator, while indexed PPAs may preserve upside while leaving off-takers exposed to volatility.
Batteries as part of firmness and balancing strategy
Batteries are increasingly included in bankability frameworks for renewable projects. They can shift output, reduce imbalance costs, capture evening spreads and improve firmness under operational variability.
For solar projects, BESS is described as helping protect against price cannibalisation. For wind projects, it can smooth forecast deviations and support balancing strategies.
Week 23 as a signal for modelling assumptions
The conditions observed in Week 23 indicate that SEE renewables are not operating in a simple growth market environment. Volatility, flexibility requirements and grid access are presented as factors that influence returns for new projects.
The next bankable renewable projects are described as those designed from the start for this complexity across power markets in Southeast Europe.
