Europe’s latest grid-connection rules are turning power-system stability from a specialist engineering concern into a material development and financing risk for renewable projects. The change is particularly significant in Southeast Europe, where developers are adding increasingly large wind, solar and battery installations to transmission systems that combine ageing infrastructure, long cross-border transmission routes, concentrated conventional generation and limited local sources of voltage support.
ENTSO-E’s new technical guidance on forced oscillations, published in July 2026 after two years of work with WindEurope, addresses periodic fluctuations injected into the network by power-generating equipment. The guidance supports two new provisions proposed for the revised Network Code on Requirements for Grid Connection of Generators, or RfG 2.0, covering the permissible amplitude and duration of oscillations produced by power park modules.
Although the immediate work focuses on wind farms, the regulatory direction extends much further. ENTSO-E has stated that the requirements will also apply to solar photovoltaic plants and electricity-storage modules, making the issue relevant to almost every utility-scale renewable project now under development in Serbia, Montenegro, Bosnia and Herzegovina, North Macedonia, Albania, Bulgaria, Romania, Croatia and Greece.
Forced oscillations differ from more familiar grid-code requirements such as fault ride-through, reactive-power control, active-power control and frequency response. They occur when generating equipment repeatedly injects power variations at a particular frequency. In wind turbines, these variations can be caused by tower movement, blade-passing effects, wind shear, turbulence, waves or active tower-damping systems. Solar and battery installations can create different oscillatory behaviour through converter controls, plant controllers, filters and interactions between multiple power-electronic devices.
The risk becomes serious when the injected frequency is close to a natural mode of the transmission system. The grid can amplify the disturbance through resonance, producing fluctuations significantly larger than those at the original source. A local control problem can then propagate across a synchronous area, stress equipment, trigger protection systems or contribute to cascading disconnections.
The draft RfG 2.0 provisions address oscillations in the range of 0.1–20 Hz for larger Type C and Type D power park modules. The lower part of this range overlaps with inter-area and local electromechanical modes traditionally associated with synchronous power systems. Frequencies between approximately 2 Hz and 20 Hz increasingly reflect interactions among converters, control systems and network equipment.
The upper boundary is partly practical. Measurements above 20 Hz would generally require point-on-wave equipment that is not yet standard across European transmission systems. The proposed framework therefore allows much of the compliance assessment to rely on high-resolution phasor measurements, specialised power-quality recorders and advanced data-processing tools.
That technical detail carries a substantial commercial consequence. Grid compliance can no longer be demonstrated solely through generic OEM certificates and conventional RMS dynamic models. Developers may increasingly need site-specific measurements, validated frequency-domain behaviour, higher-resolution simulation models and evidence showing that interactions between turbines, inverters, plant controllers, transformers, compensation equipment and the surrounding network remain stable under credible operating conditions.
This is particularly relevant to projects using equipment from Chinese or Turkish manufacturers. The issue is not the origin of the technology itself. Several non-European OEMs offer strong hardware, competitive pricing and extensive operating experience. The risk lies in whether their control models, source-code protections, validation procedures and technical support are compatible with European and Serbian grid-compliance processes.
An OEM may provide a black-box RMS model suitable for load-flow, short-circuit and conventional dynamic studies while declining to release the more detailed electromagnetic-transient representation required to investigate converter interactions. A model may perform correctly in the manufacturer’s simulation environment but produce different results after translation into the software used by EMS, CGES, HOPS, ESO, Transelectrica or IPTO. Version control creates another exposure: a turbine or inverter firmware update during construction can invalidate studies completed during the development phase.
For a 150 MW wind farm, the resulting compliance package can include turbine-level and plant-level RMS models, EMT models, harmonic impedance data, plant-controller logic, reactive-power-control validation, fault ride-through simulations, frequency-response tests, oscillation studies and field measurements during staged energisation. The studies must also cover the main transformer, collection system, shunt reactors, STATCOM or synchronous condenser where applicable, as well as the characteristics of the grid at the connection point.
Wind must be treated separately from solar. Wind turbines combine converter controls with rotating mechanical structures and aerodynamic excitation. Larger turbine rotors and taller towers introduce different natural frequencies and damping requirements. Wind projects also have higher capacity factors and frequently connect in remote areas through long 110 kV, 220 kV or 400 kV lines, making their system value and stability behaviour materially different from those of a solar plant with the same nominal capacity.
Solar presents another challenge: scale combined with limited visibility. A transmission-connected solar park can be monitored at one point of common coupling, but distribution networks increasingly contain hundreds of smaller inverter-based installations whose combined behaviour is not fully observable to the TSO. ENTSO-E plans a separate expert process during the fourth quarter of 2026 to examine non-observable embedded generation, particularly solar PV.
Battery projects add bidirectional operation and rapidly changing control modes. A BESS can switch between charging, discharging, frequency response, reactive support and standby within short intervals. Its value to the grid depends on this flexibility, but control transitions can create interactions that are not captured by a simple steady-state model. Grid-forming batteries may improve system strength, yet they require a more demanding verification process than conventional grid-following systems.
The financial exposure begins well before commissioning. A medium-sized Southeast European wind project can carry total investment costs of approximately €1.2 million–€1.6 million per MW, depending on terrain, turbine supply, balance-of-plant costs and grid infrastructure. For a 150 MW project, that implies an indicative investment envelope of €180 million–€240 million. A comprehensive grid-compliance workstream involving specialised studies, instrumentation, OEM model development and independent verification may absorb 0.5–1.5% of project CAPEX, or roughly €0.9 million–€3.6 million.
That cost is manageable when incorporated during FEED and procurement. It becomes significantly more expensive after equipment selection. Late discovery that the selected turbine or inverter requires a STATCOM, control-system redesign or additional harmonic filtering can add several million euros and delay energisation by six to 18 months.
A 12-month grid-connection delay can reduce project equity returns by approximately 1.5–3 percentage points, depending on leverage, interest during construction, the power-price environment and whether the EPC contractor or OEM accepts liability. Delays can also place pressure on debt availability periods, PPA long-stop dates, equipment warranties and eligibility deadlines under support schemes.
The contract structure therefore matters as much as the engineering. Turbine and inverter supply agreements should contain binding obligations to provide usable and validated models, support TSO studies, participate in factory and site testing, correct non-compliance and maintain model consistency following firmware changes. Grid-code compliance should remain an OEM performance obligation rather than a loosely worded cooperation commitment.
EPC contracts should allocate responsibility for the complete plant response at the point of connection. The EPC contractor cannot reasonably guarantee grid performance when the OEM controls the underlying converter logic but refuses access to the necessary models. A bankable arrangement requires aligned obligations across the EPC contractor, OEM, plant-controller supplier, transformer vendor and compensation-system provider.
Owner’s Engineer oversight becomes central at these interfaces. The OE needs a live grid-compliance matrix linking every requirement to its design evidence, simulation model, responsible party, test protocol, acceptance criterion and final certificate. Model submissions should be version-controlled alongside actual equipment settings. Factory acceptance testing must verify that the delivered controller matches the model used for the approved studies.
Commissioning should then proceed through staged energisation. Initial tests can confirm transformer and collection-system behaviour before individual generating units are introduced. Turbines or inverter blocks can be added progressively while recording voltage, frequency, active and reactive power, harmonics and oscillatory behaviour. Final plant-controller tests should cover normal dispatch, ramping, curtailment, voltage control, frequency response and credible disturbances.
The underlying regulatory timetable gives developers some room, but not much comfort. ENTSO-E expects the European Commission to complete the amended RfG during 2026, after which national implementation may take up to three years. Projects entering procurement or construction during that period will face a moving compliance baseline. A plant designed only around today’s minimum national requirements could be technically outdated before receiving final operational notification.
Serbia and other Energy Community markets will not remain isolated from this change. Their transmission systems are synchronously connected to Continental Europe, their TSOs participate in ENTSO-E structures and their market integration depends on regulatory alignment. Lenders financing projects with operating lives of 25–30 years are unlikely to accept equipment that meets only a narrow local interpretation but cannot demonstrate compatibility with the emerging European standard.
The new stability rules favour projects that treat grid compliance as a design discipline rather than a final permitting exercise. They also reward OEMs willing to provide transparent models, testing support and enforceable performance guarantees. In a region where grid connection has already become one of the main constraints on renewable deployment, model quality, controller behaviour and documented commissioning evidence are becoming bankability assets in their own right.
