Southeast Europe’s renewable energy market is entering a more advanced phase of development. As wind, solar and battery projects accelerate across the region, grid access is increasingly becoming a question not only of installed capacity, connection infrastructure and technical compliance, but also of the quality and stability of the electricity injected into the power system, writes Energy.Clarion.Engineer
The next generation of European grid connection requirements is expected to place greater attention on the dynamic behaviour of renewable assets, particularly whether large generating facilities create repetitive fluctuations that can interact with the wider Continental European synchronous system. The emerging issue concerns forced oscillations, a technical phenomenon that could become an important factor in the future approval, financing and operation of renewable projects.
Forced oscillations are periodic variations in active power output caused by mechanical behaviour, environmental conditions, equipment characteristics or control-system interactions. To address this challenge, ENTSO-E and WindEurope have developed a common assessment methodology that supports the proposed Network Code on Requirements for Generators 2.0 (NC RfG 2.0).
The revised network code has not yet been formally adopted by the European Commission, meaning that its provisions are currently proposed rather than legally binding. However, projects entering front-end engineering design, turbine procurement, grid studies or financing processes today may still be operating under the new framework once it becomes incorporated into national legislation.
The issue is particularly important for Southeast Europe because the region is closely integrated into the Continental Europe synchronous area. Serbia, Montenegro, Bosnia and Herzegovina, North Macedonia, Albania, Kosovo, Croatia, Romania, Bulgaria, Greece, Hungary and Slovenia are either directly connected to this system or operate within its wider electrical environment. A disturbance originating from a single generating facility can therefore interact with system-wide electromechanical behaviour and affect multiple countries.
The physical impact of an oscillation does not stop at national borders. Electricity markets may be divided into separate bidding zones, but the electricity grid remains a single interconnected machine where disturbances can propagate through transmission networks.
Forced oscillations are different from normal renewable generation variability. Wind farms naturally increase and decrease production as wind speeds change. Solar plants respond to changing sunlight conditions, while batteries adjust their output according to dispatch instructions. These variations are expected and managed by system operators.
Forced oscillations, however, involve repeated power fluctuations occurring at identifiable frequencies and continuing for sufficient periods to interact with the natural characteristics of the power system. When these frequencies approach the system’s own oscillation modes, the disturbance can potentially be amplified through resonance.
Wind turbines can generate such behaviour through several mechanisms, including tower shadow effects, blade-passing frequency, wind shear, rotor dynamics, structural vibration modes and active tower-damping systems. Mechanical movement within the turbine structure can translate into electrical fluctuations through changes in generator torque.
Solar and battery projects face different challenges. Their potential oscillations are more closely linked to inverter controls, plant-level controllers, weak-grid conditions and interactions between multiple converter-based systems operating at the same connection point.
The main concern for system operators is not necessarily the size of an individual fluctuation, but whether the disturbance occurs at a frequency that matches one of the grid’s natural modes. A relatively small oscillation from one renewable facility could become amplified across the interconnected system, creating additional stress on equipment and potentially contributing to protection actions, generator disconnections or, in extreme situations, wider system instability.
Continental Europe’s main inter-area oscillation modes generally occur between 0.1 and 1.0 hertz, while local and intra-area oscillations typically occur between 1.0 and 2.0 hertz. These frequency ranges are increasingly important for Southeast Europe because the region combines large synchronous generators, including hydro, coal, gas and nuclear plants, with rapidly expanding inverter-based renewable capacity.
The region’s transmission structure increases the importance of dynamic performance. Major electricity flows connect Romania with Bulgaria, Greece with the Western Balkans, Hungary with Central Europe and Serbia with neighbouring systems. Serbia also plays a significant role as a regional transmission corridor, while Serbia, Montenegro and North Macedonia cooperate through the SMM control block, which coordinates balancing energy and reserve exchange.
This interconnected structure means that renewable plants can no longer be assessed only according to local grid conditions. Their dynamic behaviour must also be evaluated according to how they interact with the wider regional electricity system.
Recent events have demonstrated the sensitivity of the European grid to disturbances. The Continental Europe system separation on 8 January 2021, which originated from cascading transmission events in Croatia, was not caused by forced oscillations. However, it highlighted how quickly local operational problems can affect a much larger synchronous area and underlined the importance of maintaining system stability across Southeast European corridors.
Under the proposed framework, forced-oscillation requirements would primarily apply to Type C and Type D power park modules. Within the Continental Europe synchronous area, the proposed threshold for national classification of Type C facilities is 50 MW, while projects connected at 110 kV or higher voltage levels are generally considered Type D. National transmission system operators would still retain the ability to introduce stricter requirements.
As a result, a significant share of Southeast Europe’s future renewable pipeline could fall within the potential compliance framework. Large wind developments such as Serbia’s Čibuk 2, developed by Masdar and Taaleri, and Enlight Renewable Energy’s Pupin wind project, together with projects in Montenegro, Romania, Bulgaria, Croatia and Greece, represent the type of assets that may require additional dynamic performance verification.
The issue becomes even more complex where multiple renewable projects share connection infrastructure. Oscillations generated by individual turbines or separate sections of a wind farm are not always synchronised. At a common connection point, some fluctuations may partially cancel each other out, meaning that a project appearing problematic when assessed independently could perform within limits when evaluated as part of a larger interconnected facility.
This creates an important technical and contractual question: where exactly should compliance be measured? The answer could significantly affect project results.
Measurements could be taken at the individual plant transformer, the shared substation, the transmission-system connection point or an aggregated point of common coupling. The selected boundary must be clearly defined before detailed engineering is completed and should be reflected in grid-connection agreements, EPC contracts, turbine supply agreements and operational procedures.
Ownership of the connection infrastructure does not automatically determine responsibility for compliance. A developer financing a substation or export connection that later becomes part of the transmission network must still understand who is responsible for installing monitoring equipment, maintaining data systems and implementing corrective measures if performance requirements are not met.
The technical limits proposed under the new methodology would introduce a more detailed compliance framework for renewable generators. For onshore wind farms, continuous forced oscillations would generally be limited to the higher value of ±0.5% of maximum plant capacity or 500 kW. Temporary oscillations could reach ±2.5% of maximum capacity, but the plant would need to return within the continuous limit within 180 seconds and reduce the temporary deviation below half of that level within half the permitted recovery period.
Temporary exceedances would also be restricted in frequency. Under the proposed approach, they would generally be allowed for no more than 1% of each day, while the default assessment method would limit events to three exceedances per hour, evaluated at the 95th percentile over a measurement period.
The selection of these thresholds has a direct impact on project compliance. Testing conducted during the development of the methodology showed that compliance rates varied significantly depending on the selected limit. Under the strictest temporary onshore wind requirement, only a small share of assessed operating periods achieved compliance, while adoption of the proposed default threshold produced significantly higher results.
These differences demonstrate why national implementation of the rules cannot be treated as a simple technical procedure. A transmission system operator applying the strictest available interpretation could potentially classify standard turbine configurations as non-compliant, creating additional requirements for controller adjustments, operational changes or additional technical equipment.
The methodology itself is still developing. Available operational data covers mainly the 0.1–2.0 hertz frequency range, while the proposed obligation could extend up to 20 hertz. In addition, the analysed wind farms and manufacturers have not been publicly identified, while the assessment tool remains a developing MATLAB-based prototype rather than a fully mature industry platform.
Another challenge is distinguishing true forced oscillations from normal operating events. Turbine start-up and shutdown processes, power ramps, curtailment instructions, wind turbulence and system-support actions can create fluctuations that may resemble oscillatory behaviour.
To reduce false identification, the methodology proposes minimum detection periods, potentially between one and ten seconds, depending on the specific project and system conditions. However, this creates an additional requirement for accurate operational records. Developers must be able to demonstrate whether a detected event was caused by the generating facility itself or by an external grid-support instruction.
This makes advanced monitoring infrastructure increasingly important. Many existing renewable facilities rely on conventional SCADA systems that record active power at intervals of one second, ten seconds or longer. Such data may be insufficient to analyse higher-frequency oscillations between 2 and 20 hertz.
The proposed monitoring approach is closer to transmission-system measurement standards than traditional renewable plant monitoring. It relies on phasor measurement units (PMUs), preferably compliant with IEC/IEEE 60255-118-1, together with accurate current and voltage measurement equipment.
For oscillations up to approximately 2 hertz, a measurement resolution of around 100 milliseconds may be sufficient. Monitoring the full proposed frequency range requires substantially higher sampling capability, with practical systems expected to operate at around 50 samples per second.
These requirements should be incorporated during the early engineering stages of renewable projects. PMU installation, communication systems, time synchronisation, data storage and cybersecurity interfaces should be considered during substation design and procurement rather than added after construction.
Retrofitting such systems after commissioning can require modifications to protection panels, additional testing and operational interruptions. For this reason, dynamic monitoring capability should become part of the standard design philosophy for large renewable and storage projects.
The compliance process will also continue beyond the construction phase. Initial assessment would only begin after a project has completed a period of commercial operation, with the first evaluation requiring sufficient operating data to represent different weather conditions, loading levels and operating scenarios.
A renewable project could therefore achieve energisation, complete standard grid compliance testing and begin commercial operation while still carrying a potential future compliance obligation related to forced oscillations.
This creates a new consideration for project financing. Lenders and investors will need to treat dynamic performance as a continuing operational requirement rather than a one-time construction milestone. Financing agreements will increasingly need clear allocation of responsibility for modelling, monitoring, data analysis, equipment upgrades, manufacturer support, controller modifications and potential production losses.
A general commitment that turbines or inverters comply with the applicable grid code may no longer be sufficient. The final compliance outcome may depend on project-specific limits established by the transmission operator, the selected measurement point, aggregation methodology and the chosen detection algorithm.
The issue also extends into turbine structural design. Many modern turbines use active tower damping systems that adjust generator torque to reduce mechanical stress. However, those same control actions can influence electrical power output and potentially create measurable oscillations.
As a result, stricter grid requirements could create unexpected interaction between electrical performance and structural engineering. Reducing power fluctuations may require changes that increase mechanical loads, potentially affecting tower design, foundation requirements, fatigue calculations or certification procedures.
Once a turbine configuration has been certified and a project has reached commercial operation, such modifications can become technically complex and financially expensive.
Developers may consider several mitigation solutions, including battery storage, STATCOM equipment, flexible AC transmission technologies, improved control algorithms and structural damping systems. The appropriate solution will depend on the source of the oscillation.
Battery storage could provide additional flexibility by absorbing rapid changes in renewable output. However, batteries are not automatically a universal solution. Poorly coordinated inverter controls could introduce additional dynamic problems, particularly in weak-grid locations.
Hybrid projects combining wind, solar and storage will therefore need to be designed as integrated control systems rather than separate assets connected together. The interaction between multiple inverters, plant controllers and grid-support functions must be analysed as a single operational unit.
For Southeast Europe, the challenge is amplified by uneven regulatory implementation across countries. Serbia, North Macedonia and Bosnia and Herzegovina have made progress in adopting existing European grid connection requirements, while Montenegro, Albania and Kosovo are still developing parts of their formal implementation frameworks.
In Serbia, the transmission operator EMS already performs functional testing and approval procedures for energisation, temporary connection and permanent connection. However, the introduction of more advanced dynamic requirements could increase the workload of national operators, particularly as large volumes of wind, solar and battery projects approach commissioning at the same time.
The region also lacks a strong network of authorised independent technical certifiers capable of performing complex dynamic assessments. Transmission system operators remain responsible for much of the validation process, relying on simulations, manufacturer documentation, commissioning tests and operational measurements.
Without coordination, different national approaches could create unnecessary barriers for investors. Separate technical thresholds, measurement requirements and evidence standards adopted by EMS, CGES, NOSBiH, MEPSO, KOSTT and OST could force developers and equipment suppliers to prepare different compliance packages for each market.
A coordinated Southeast European framework would improve investment certainty. Common rules for measurement locations, sampling rates, data formats, operational exclusions, monitoring periods and assessment methodologies would allow developers to standardise technical solutions while preserving national system operator authority.
The renewable pipeline in Southeast Europe already faces major challenges from grid congestion, limited transmission capacity and lengthy connection procedures. Forced-oscillation requirements add another layer of complexity, linking turbine design, inverter controls, substation engineering and the long-term ability of projects to operate.
Projects entering the front-end engineering stage today should therefore be designed for future grid requirements rather than current minimum standards. The cost of installing high-quality monitoring systems, preparing accurate data infrastructure and defining contractual responsibilities during construction is significantly lower than redesigning controls, modifying equipment or repeating compliance testing after commercial operation.
The introduction of forced-oscillation requirements should not be viewed only as an additional regulatory burden. Properly implemented, the framework can improve the stability of a rapidly changing electricity system where renewable generation will represent an increasingly large share of power production.
For Southeast Europe, the transition toward higher renewable penetration will require not only more megawatts but also better control, stronger grids and more advanced technical coordination. The projects that integrate these requirements from the beginning will be better positioned to secure financing, complete grid connection procedures and operate successfully in the next generation of Europe’s electricity market.
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