The renewable energy landscape in South-East Europe is undergoing a significant transformation as the region grapples with the limitations of its electricity infrastructure. Countries such as Serbia, Montenegro, Bosnia and Herzegovina, and North Macedonia are experiencing not just grid congestion but a fundamental shift in how power markets operate. The existing systems were not designed to handle large-scale variable generation, leading to new regulatory and financial realities that stakeholders must navigate.
Transmission system operators are revising grid access protocols, formalizing balancing responsibilities, and developing market mechanisms for ancillary services. This evolution is reshaping the criteria for evaluating renewable projects, moving away from a focus solely on resource quality and capital costs to include factors like grid positioning and operational flexibility. The implications of these changes are profound for investors and developers.
In Montenegro, recent draft transmission rules from Crnogorski elektroprenosni sistem illustrate this shift clearly. These regulations align with ENTSO-E standards and embed economic impacts of grid constraints into project frameworks. Renewable generators are now required to provide essential services such as voltage support and frequency response, while also taking on balancing responsibilities and accepting curtailment under specific conditions.
This new set of obligations redefines renewable energy from a passive generation model to an active service model. As a result, grid access has become a valuable asset influenced by detailed system studies and location sensitivity. In Montenegro’s interconnected system, the scarcity of grid access is exacerbated by cross-border export dependencies, creating financial profiles that hinge more on connection strength than on natural resource availability.
Delays in grid readiness have become common, often extending from 12 to 18 months. Such delays can significantly compress equity internal rates of return by 2 to 4 percentage points, particularly amid volatile market conditions. Additionally, compliance with technical requirements necessitates advanced equipment investments ranging from €50,000 to €150,000 per MW, adding millions to project budgets for utility-scale developments.
Curtailment risks further complicate the investment landscape. While renewables enjoy priority dispatch as a principle, operators increasingly have the authority to reduce output for system stability. In Montenegro, this has led to curtailment rates between 3% and 8%, with stress scenarios predicting losses of 10% to 20% during peak generation periods with low demand. This reality forces lenders into more conservative debt sizing strategies, thereby increasing capital costs.
In contrast, Serbia benefits from a more robust transmission system managed by Elektromreža Srbije, featuring a well-established 400 kV network and expanding interconnections. Although this provides some resilience against congestion issues faced by smaller systems like Montenegro’s, localized bottlenecks are emerging in wind-rich areas of eastern Serbia. Balancing responsibilities are tightening there too, with curtailment currently moderate at around 2% to 5%, yet trending upward as renewable penetration increases.
Bosnia and Herzegovina presents its own unique challenges due to its fragmented transmission system overseen by Elektroprenos Bosne i Hercegovine. Regulatory alignment with European standards is still developing, resulting in lower immediate exposure to curtailment but concealing deeper structural risks that could surface as integration costs rise sharply during regulatory convergence.
North Macedonia finds itself in an intermediate position with its operator MEPSO implementing relatively advanced regulations while facing physical network constraints that limit expansion potential. A recent major disturbance linked to overvoltage conditions highlighted the fragility of its infrastructure under stress. For developers here, storage solutions are becoming increasingly necessary despite lacking fully developed market incentives.
Across these four markets, balancing responsibilities have shifted from marginal considerations to central cost drivers for renewable producers. Imbalance costs now range from €3 to €8 per MWh for solar projects and €5 to €12 per MWh for wind projects as systems become saturated and less capable of absorbing variability without intervention.
Battery storage is emerging as critical infrastructure rather than an optional enhancement within South-East Europe’s energy strategy. By mitigating excess generation and smoothing output fluctuations, storage systems can significantly reduce curtailment losses and imbalance costs while enabling participation in ancillary service markets.
Despite challenging economics—capital costs for storage range between €300,000 and €600,000 per MWh—integrating storage into hybrid configurations can enhance risk-adjusted returns by stabilizing cash flows and improving dispatchability. This trend is evident in Montenegro where hybrid models are becoming standard; similarly in Serbia where strategic differentiation is crucial; while Bosnia and North Macedonia will likely follow suit as constraints intensify.
The renewable energy investment paradigm in South-East Europe is shifting from capacity expansion towards system integration and operational flexibility. Transmission networks are evolving from passive components into active determinants of value creation within power markets. As ancillary service markets gain importance alongside storage solutions, stakeholders must reassess their strategies to adapt effectively to these changes.
Ultimately, the focus of renewable energy development in South-East Europe is transitioning towards how effectively capacity can be integrated within strained systems rather than merely expanding installed capacity. Grid constraints and storage economics are now central factors reshaping market dynamics across the region.
