Grid access rules and storage costs are reshaping renewable economics across South-East Europe

Renewable build-outs across South-East Europe are colliding with a structural constraint: the region’s power systems were not designed for large-scale variable generation. For policymakers, developers and lenders, the shift is no longer just about temporary congestion—it is changing how value is created in electricity markets.

From resource-led projects to system-flexibility economics

The change is reflected in regulatory language that may sound incremental but carries major financial consequences. Transmission system operators are tightening grid access rules, formalising balancing responsibilities and introducing mechanisms for ancillary services. Together, these measures are dismantling the older approach in which renewable projects were judged mainly on resource quality and capital cost.

In its place is a framework where returns depend heavily on grid positioning as well as system flexibility and operational responsiveness. That means developers increasingly face questions that go beyond installed capacity: whether a site can reliably connect to the network, how it will behave during constrained periods, and what it will be required to provide to keep the system stable.

Montenegro shows how obligations can embed constraint costs into design

Montenegro offers a clear example of where the region appears to be heading. Draft transmission rules issued by Crnogorski elektroprenosni sistem align the country with ENTSO-E operational standards while embedding the economic consequences of system constraints directly into project requirements.

Renewable generators are expected to provide voltage support, frequency response and real-time dispatchability. They must assume full balancing responsibility and accept curtailment under defined system conditions. The practical effect is that renewables move from being treated as passive generation to functioning as active providers of system services.

For investors, grid access becomes a scarce asset shaped by detailed system studies and sensitive location factors. In Montenegro’s relatively small interconnected network—where cross-border export capacity plays an outsized role—wind-rich northern areas and coastal solar corridors can face structurally weaker nodes. As a result, project financial profiles depend less on irradiation or wind speeds than on how and when connections work within the transmission network.

Delays, compliance capex and curtailment risk raise financing pressure

The consequences are already measurable. Delays in grid readiness of 12 to 18 months are becoming more common, affecting capital deployment timelines and returns. Under typical project finance structures, such delays can compress equity internal rates of return by 2 to 4 percentage points—particularly when revenue assumptions are already strained by market volatility.

Technical compliance adds further cost. Renewable plants may need advanced inverter systems, reactive power compensation equipment and full integration with transmission operator control systems—adding between €50,000 and €150,000 per MW depending on technology. For utility-scale projects, that translates into several million euros of incremental investment that must be reflected in financial models.

Curtailment risk compounds these pressures. While priority dispatch remains a formal principle across the region, transmission operators are increasingly empowered to reduce output for stability reasons. In Montenegro—where balancing depends heavily on export capacity—this creates embedded production-loss risk during periods of high generation and low demand. Base-case curtailment assumptions of 3% to 8% are becoming standard, with stress scenarios reaching 10% to 20% under constrained conditions.

Serbia’s sturdier backbone helps today—but the direction is similar

Serbia benefits from a larger transmission system operated by Elektromreža Srbije, including a well-developed 400 kV backbone and expanding cross-border interconnections. That provides resilience relative to Montenegro by reducing immediate exposure to congestion for some projects.

However, bottlenecks are still emerging as penetration rises—particularly in wind-rich regions of eastern Serbia—and balancing responsibilities are being tightened alongside stricter enforcement of grid codes. Curtailment remains moderate for now (typically 2% to 5%), but the underlying trend points upward.

The market therefore offers relative stability rather than immunity from structural change. As balancing costs rise and constraints intensify, standalone renewable economics are expected to converge toward the pressures already visible in Montenegro. Internal rates of return currently in an 8% to 11% range could compress as additional costs are internalised and revenue volatility increases.

Bosnia’s “permissive” surface masks integration risks

Bosnia and Herzegovina presents a different challenge due to institutional complexity that leaves parts of its transmission framework more fragmented. Regulatory alignment with European standards is less advanced and balancing mechanisms remain underdeveloped.

This can appear permissive at first glance: lower immediate exposure to curtailment and balancing costs may encourage development activity. Yet structural risks persist beneath that surface. Transmission corridors linking Bosnia with neighbouring systems are being expanded but coordination between entities remains limited, while localised congestion has already appeared—especially at distribution level where solar penetration is increasing rapidly.

The absence of fully developed balancing markets can effectively hide integration costs rather than eliminate them. As regulatory convergence accelerates, those costs may be internalised abruptly later on—creating delayed but potentially sharper adjustments for project economics. Return expectations of 8% to 12% therefore carry higher uncertainty than in more mature markets.

North Macedonia combines regulatory clarity with physical fragility

North Macedonia sits between these extremes. The system operator MEPSO has implemented an advanced regulatory framework including detailed grid codes and formal balancing requirements. At the same time, physical network constraints remain significant: medium-voltage saturation limits expansion prospects while higher-voltage performance is sensitive to voltage fluctuations.

A major disturbance linked to overvoltage conditions highlighted how fragile the network can be under stress. For renewable developers this creates a paradox: regulatory clarity improves predictability but physical constraints increase curtailment likelihood as capacity grows.

Storage is already emerging as a technical necessity in certain regions even without fully developed market incentives. Expected returns in the 7% to 10% range face increasing volatility as constraints tighten alongside continued growth in renewables.

Imbalance costs become central—and storage moves into the core business case

A common pattern runs through all four markets: balancing responsibility has shifted from a marginal issue into a central cost driver. Renewable producers must forecast output, submit schedules and absorb financial consequences for deviations from those schedules.

For solar projects imbalance costs typically fall between €3 and €8 per MWh; wind exposure is higher at roughly €5 to €12 per MWh. These costs rise as systems become more saturated and less able to absorb variability without active intervention.

Against this backdrop battery storage is moving from optional optimisation toward critical infrastructure for stability across South-East Europe. Its role spans multiple functions: absorbing excess generation reduces curtailment losses; smoothing output lowers imbalance costs; providing fast-response services enables participation in ancillary service markets.

The investment case remains challenging because storage capital costs range from €300,000 to €600,000 per MWh—an addition that materially affects budgets even before considering financing structure or integration complexity. Still, when paired with renewables in hybrid configurations, storage can improve risk-adjusted returns by stabilising cash flows and enhancing dispatchability while partially offsetting curtailment and balancing impacts.

The report notes that this approach is already becoming default in Montenegro for new developments; emerging as a strategic differentiator in Serbia; and viewed as an inevitable next step in Bosnia and North Macedonia as constraints intensify.

The next phase: integration over expansion

The broader implication for investors is that renewable energy investment across South-East Europe is entering a new phase after an initial wave defined by resource capture and capacity expansion. The next wave will be defined by system integration capabilities—where transmission networks become active determinants of value rather than passive infrastructure—and where ancillary service revenues evolve from peripheral supplements into essential components of earnings potential.

This requires reassessing project evaluation methods beyond simplified assumptions about load factors and power prices. Developers need models that incorporate grid availability, curtailment probability, balancing costs and potential multi-layer revenue streams tied to flexibility services—as well as account for regulatory convergence across markets aligning more closely with European standards while internalising costs previously externalised.

Those able to secure strong grid positions early while integrating storage into assets designed for multiple market layers may find opportunities in systems increasingly rewarding flexibility; others risk seeing returns eroded by constraints that appear less temporary than structural.