The new merchant risk in Balkan renewable markets

South-East Europe’s [[PRRS_LINK_1]] is entering a more difficult phase. For much of the past decade, wind and solar development across the Balkans was supported by a relatively favorable combination of conditions: rising wholesale electricity prices, low renewable penetration, growing investor appetite for emerging European infrastructure and policy momentum following Europe’s post-2022 energy crisis. Under those circumstances, even relatively straightforward renewable projects could achieve attractive returns.

By 2026, however, the economics of the market are changing fundamentally.

The biggest challenge facing developers is no longer whether renewable electricity can be generated competitively. The challenge is whether renewable electricity can maintain value once it enters increasingly saturated and volatile regional power systems.

This is the beginning of the merchant-risk era for Balkan renewables.

The shift matters because the region’s renewable market is gradually moving away from subsidy-heavy or scarcity-driven economics toward exposure to wholesale market dynamics that are becoming progressively more complex. Wind and solar developers across Serbia, Romania, Greece, Bulgaria and the wider Western Balkans increasingly face a combination of capture-price deterioration, congestion exposure, balancing costs and curtailment risk that did not exist at the same scale during the first investment cycle.

In practical terms, generating renewable electricity is no longer enough.

Developers now increasingly need to control flexibility, storage access, balancing capability and transmission positioning if they want projects to remain financeable over the long term.

The phenomenon is already visible across several SEE markets.

Greece provides one of the clearest examples. Rapid solar expansion combined with growing renewable penetration has created increasing midday price compression during high-irradiation periods. Solar plants generate most aggressively precisely when wholesale prices become weakest because the market is flooded with simultaneous photovoltaic output.

This is the core problem of capture-price deterioration.

A project may appear attractive when modeled against average wholesale electricity prices. Yet the actual realized price received by the project — the capture price — becomes materially lower because the asset consistently generates during oversupplied periods.

The same dynamic is gradually emerging elsewhere in the Balkans.

Romania’s renewable market increasingly experiences periods where strong wind output in Dobrogea and expanding solar generation weaken realized market values during high-production intervals. Serbia is entering a similar transition as utility-scale solar and wind projects accelerate simultaneously. Bulgaria’s growing solar buildout increasingly contributes to intraday price volatility.

Renewable abundance itself is beginning to undermine renewable pricing.

This changes project finance assumptions fundamentally.

Historically, many Balkan renewable projects relied on relatively simple generation-based financial models. Developers evaluated irradiation or wind resource quality, estimated annual output and modeled revenues against long-term electricity price expectations.

That framework becomes progressively less reliable once renewable penetration rises.

A solar project generating during systematically weak midday pricing periods may produce strong electricity volumes while still underperforming financially. Wind projects exposed to correlated regional weather patterns may face simultaneous congestion and balancing pressure during high-generation events.

Merchant risk therefore increasingly dominates the market.

The term itself refers to exposure to wholesale electricity market conditions without sufficient long-term contracted revenue protection. As subsidy frameworks evolve and governments gradually shift toward more market-based renewable structures, developers become more directly exposed to electricity price volatility and balancing costs.

This exposure is becoming more difficult to manage because SEE electricity markets themselves are changing structurally.

The region’s power systems are becoming increasingly weather-driven.

Wind conditions across Serbia, Romania and the Adriatic corridor increasingly shape regional price formation. Solar output in Greece and Bulgaria creates synchronized intraday pricing pressure. Hydrology in Albania and Montenegro influences balancing capability throughout the Balkans. Cross-border electricity flows fluctuate according to renewable conditions rather than conventional dispatch schedules.

This means renewable developers increasingly compete not only against thermal generation but against each other’s simultaneous production profiles.

Transmission infrastructure amplifies these pressures.

The Trans-Balkan Corridor and wider regional interconnections improve electricity mobility across South-East Europe, but they also expose markets more directly to synchronized renewable volatility. During periods of strong regional wind or solar output, congestion can spread across interconnected systems simultaneously.  

This creates periods where exporting surplus electricity becomes increasingly difficult precisely when renewable generation peaks.

Curtailment risk therefore becomes commercially relevant.

Historically, many SEE renewable developers assumed that nearly all generated electricity could enter the market without significant operational restrictions. As renewable penetration rises, however, transmission operators increasingly face balancing and congestion constraints forcing temporary reductions in renewable output.

This is especially important for solar-heavy systems.

Midday solar surges can overwhelm local transmission capacity if balancing infrastructure and export routes remain insufficient. Projects located near congested nodes therefore face materially greater merchant risk than assets integrated with stronger interconnection or storage capability.

The financial consequences are substantial.

Infrastructure lenders and institutional investors increasingly evaluate renewable projects through the lens of capture-price resilience and balancing exposure rather than simply generation potential. Merchant risk models now include assumptions around curtailment probability, intraday price cannibalization and congestion-related revenue erosion.

This transition favors certain project structures over others.

Hybrid renewable-storage systems increasingly attract stronger financing conditions than standalone merchant wind or solar projects. Batteries allow developers to shift electricity delivery away from oversupplied periods and participate in balancing markets simultaneously.

Storage effectively transforms intermittent renewable generation into partially dispatchable infrastructure.

The rapid growth of battery pipelines across SEE markets directly reflects this shift.

Serbia alone now has approximately 4.54 GWh of planned storage projects linked to EMS agreements. Greece is accelerating large-scale battery deployment. Romania increasingly integrates storage into future renewable structures. Bulgaria’s storage market is gradually emerging as solar penetration rises.

The economics behind these projects are fundamentally tied to merchant-risk management.

Batteries monetize volatility itself. They absorb electricity during low-price oversupply periods and discharge during higher-value balancing intervals. As intraday spreads widen across SEE markets, storage increasingly acts as a financial hedge against renewable cannibalization.

Hydropower flexibility also becomes strategically important.

Reservoir systems in Albania, Montenegro and Romania increasingly resemble premium balancing assets because they provide dispatchable low-carbon generation capable of stabilizing renewable-heavy electricity flows. Flexible hydro effectively supports the monetization of intermittent renewables elsewhere in the region.

This explains why countries with strong balancing infrastructure increasingly gain competitive advantages inside the renewable transition.

The geopolitical environment further complicates merchant risk.

Europe’s energy crisis initially created extremely supportive wholesale pricing conditions for renewable projects. Yet as markets stabilize and renewable penetration rises, price structures become more volatile and increasingly linked to regional balancing capability rather than simple scarcity.

CBAM-related dynamics add another layer.

Cross-border electricity flows between EU and non-EU Balkan markets increasingly face carbon-related commercial pressure. According to recent Energy Community analysis, Q1 2026 already showed a decline of approximately 25% in commercial electricity exchanges between the EU and Western Balkans, partly linked to changing market structures and carbon-related factors.  

This creates uncertainty around future export economics for renewable-heavy systems lacking sufficient balancing integration or carbon competitiveness.

The role of power traders is expanding rapidly inside this environment.

Historically, many renewable developers relied primarily on generation economics and long-term supply assumptions. The future market increasingly rewards sophisticated trading capability, forecasting quality and portfolio optimization.

Renewable projects now require dynamic market management.

Weather forecasting, intraday optimization, balancing participation and cross-border congestion management increasingly determine profitability. Developers without strong trading capability may struggle to monetize renewable output efficiently inside volatile markets.

This explains why utilities, commodity houses and infrastructure funds increasingly seek integrated renewable-flexibility portfolios rather than isolated generation assets.

Owning wind or solar capacity alone becomes less attractive than controlling combinations of generation, storage, balancing access and transmission optionality.

The future Balkan renewable market therefore likely belongs to integrated infrastructure operators rather than pure generation developers.

Yet many risks remain unresolved.

Balancing markets across SEE are still evolving and remain fragmented. Regulatory treatment of storage differs between jurisdictions. Intraday market liquidity remains uneven. Grid modernization continues lagging renewable deployment in several countries.

There is also the risk that renewable expansion itself outpaces flexibility infrastructure.

If solar and wind capacity continue growing faster than storage, interconnections and balancing capability, merchant pressures may intensify sharply. Negative pricing events, curtailment and capture-price erosion could become significantly more common across the region during the next decade.

This does not mean renewable investment stops.

Europe’s decarbonization trajectory still strongly supports long-term renewable expansion. Industrial electrification, hydrogen development and low-carbon supply-chain requirements all increase structural demand for renewable electricity.

But the market is becoming much more selective.

The era where nearly any renewable megawatt automatically generated attractive returns inside SEE markets is gradually ending.

The next investment cycle will increasingly reward projects capable of managing volatility rather than simply producing electricity.

The winners in Balkan renewable markets may therefore not necessarily be those building the largest generation portfolios.

Strategic advantage increasingly belongs to developers controlling flexibility, storage, balancing capability and sophisticated trading infrastructure inside a power system where volatility itself is becoming the dominant economic variable.

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