Overcoming PV Integration Limits in Low-Voltage Distribution Systems

Budapest University of Technology and Economics, Zero Carbon Hub (ZKK): Péter Kaderják, PhD; Pálma Szolnoki, PhD; Anna Mészégető

Budapest University of Technology and Economics, Smart Power Lab (SPL): Beáta Polgári; Dávid Raisz, PhD; Ádám Sleisz, PhD; Zoltán Jakab; András János Horváth; Dániel Divényi, PhD; Ágnes Závecz, PhD; János Csatár, PhD

Contact:

Pálma Szolnoki at BME ZKK: szolnoki.palma@bme.hu

Dávid Raisz at BME SPL: raisz.david@vik.bme.hu

Downloadable documents:

• ECF Regulatory Report
• ECF Technical Report

Introduction

The European Union plans to decarbonise its electricity system by 2040. As the share of variable renewable energy sources increases within the electricity system, the challenge of maintaining grid stability becomes progressively more complex and demanding for both Transmission System Operators (TSOs) and Distribution System Operators (DSOs). Low-voltage (LV) sections are increasingly reaching their photovoltaic (PV) hosting capacity limits, prompting DSOs to restrict the connection of additional PV installations.

Although the goals of decarbonization and energy independence call for the expansion of renewable electricity generation, the grid is beginning to signal constraints on the further integration of weather-dependent resources. Therefore, we must find new, innovative solutions that enable the seamless addition of further intermittent renewable energy capacities to the system.

European policy makers have paid significantly more attention to transmission grid solutions, even though distribution grids also offer a large untapped potential to enhance the integration of intermittent renewable sources. Some of these solutions are also able to prevent excess generation from being exported to upstream medium- and high voltage networks, thereby alleviating the burden on transmission grids.

Results of the technical analysis

The aim of our study was to analyze how the PV hosting capacity of the distribution grid can be increased through various measures. The initial focus was on community energy initiatives, but the analysis also identified other measures that could enhance the integration of intermittent renewables into the grid.

The effectiveness of these measures was assessed using two different LV network models: one representing a typical Hungarian LV transformer supply area with four feeders, and the other based on the international CIGRÉ benchmark model, which reflects a residential feeder in a European LV system. A three-phase, unbalanced, four-wire grid model was used, and load-flow calculations were performed. The simulation covered a full year, derived by scaling the results from 24 representative days (one weekday and one weekend day per month).

The baseline scenario was defined at the level of installed PV capacity at which the grid reaches its PV hosting limit—specifically, a point at which it violates at least one of the predefined criteria outlined in the DSO Network Code. Once this condition is reached, the connection of additional solar panels is restricted. Starting from this ‘saturated’ state, we explored and applied various mitigation measures, assessing their effectiveness in further increasing the grid’s PV hosting capacity before hitting the integration threshold again.

Different scenarios were evaluated using three key indicators. The first indicator assessed the extent to which the PV hosting capacity of each grid model can be increased through applying the specific measure. The other two indicators evaluated the impact of the measure on the underlying network beyond the MV/LV transformer.

The key findings regarding the DSO-side measures are as follows:

• Transformer upgrades can alleviate one of the most limiting conditions.

According to Hungarian Grid Code regulations (effective October 2024), the total PV power connected to a transformer area cannot exceed the transformer rated power. Replacing the transformer (e.g. 250kVA to 400kVA or 630kVA) would result in some cases in significantly higher PV hosting capacity, before the voltage-based limiting condition is met.

• Allowing temporary overloading of transformers enables higher integration of renewables.

Prohibiting further PV installations based on the rated power of the transformer is an overly conservative, strong condition. Allowing 10% more PV than the transformer rating would still be safe. Transformers may be significantly overloaded for short periods of time (depending on preceding loading conditions). Furthermore, in practice there is always some non-negligible load even in high-production periods.

• Replacing the transformer with an On-Load Tap Changer (OLTC) is an effective way to alleviate static voltage problems. An OLTC can also help manage increasing levels of electrification of demand (e.g. due to expected proliferation of EVs or heat pumps) and resulting sudden demand increases.
• Similar effects can be reached with line replacement, i.e. increasing the line cross-sections. (However, this is usually a large investment, especially if – e.g. in accordance to local regulations – overhead lines have to be replaced by underground cables.)

In addition to DSO-side measures, we also analysed how coordinated actions taken by system users could impact and potentially enhance PV integration capacity. In particular, we examined different forms of community energy initiatives—that are based on energy sharing—and compared their effects with those of the baseline scenario and the DSO-side interventions.

Our main findings on the impact of network user involvement are as follows:

• By coordinating the placement of PV production units within the network to achieve an optimal layout from a grid perspective, network users can enhance the PV hosting capacity of the low-voltage (LV) area—achieving an effect comparable to that of OLTC implementation or line replacement. A further result is that a centrally located PV system is not necessarily more effective than partially decentralized PV systems, provided the latter are optimally placed from a grid perspective.
• Scenarios exploring the use of community coordinated battery storage revealed that these systems are highly effective for integrating PVs. Storage not only boosts the local PV capacity that can be accommodated but also reduces the reverse power flow to the higher voltage levels. In this regard, it proves to be significantly more effective than OLTC transformers or line upgrades, which provide only localized improvements and are unable to prevent excess generation from being exported to upstream network levels. Furthermore, results indicate that there is no significant difference between centralized and decentralized storage arrangements in terms of network impact; both configurations can be beneficial. The key factor, however, is the control strategy governing storage use. If a shared “behind-the-meter” storage system is managed with a community-level optimization approach, rather than individual optimizations, PV hosting capacity can be significantly increased, and the reverse flow to the higher voltage levels reduced. Notably, even a partial application of community-level optimization alongside individual optimization yields these positive effects.

• Another key finding of the analysis regarding storage is that four-hour storage sizing is recommended over the currently more common two-hour approach. This longer duration is more effective in capturing surplus generation during sunny periods and enabling its local use at a later time, therefore more beneficial for the grid as well.

• Demand-side response (DSR) can offer benefits comparable to storage in facilitating PV integration, and it presents a significantly more cost-effective solution than installing storage systems.
• Reactive power (Q(U)) control is a highly effective way to increase the PV hosting capacity by ensuring proper voltage regulation, assuming line types with certain line parameters (X/R ratio not too small). However, during sunny hours, the produced PV power and the required reactive power consumption together might be higher than the inverter rated power. Therefore, either an oversizing of some inverters (~20%) or the curtailment of power generation by a small amount (still much less than with P(U) regulation) is necessary. A downside is that applying reactive power control leads to a slight increase of network losses. On the plus side, not all PV inverters need to contribute to Q(U) control: it is sufficient to control about one third of inverters, in particular those farthest away from the transformer.

Finally, we have also analysed an electrification scenario which revealed that while integrating weather-dependent renewables is the current priority, and can be also aided by alternative network technologies, the rise in consumption due to electrification through a massive penetration of e-car charging or heat pumps demands nearly immediate network upgrades. Community energy activities proved effective also in this scenario by mitigating peak demand through DSR and storage, helping to reduce and delay the network expansion needs associated with electrification.

Policy implications

Although the analysis showed that engaging network users in addressing PV integration challenges can yield more efficient outcomes than traditional DSO-side measures, such involvement requires more than a straightforward investment. It calls for a rethinking of the existing regulatory framework. Our study includes a cost-benefit analysis of involving community energy initiatives into grid support and based on the findings, proposes recommendations for a suitable regulatory approach.

These insights also contribute to the ongoing discussion surrounding the implementation of the Electricity Market Design (EMD) reforms on energy sharing, which must be adopted by summer 2026.

As electricity systems near their PV hosting limits, the need for innovative and forward-looking solutions becomes critical to maintain momentum toward decarbonization. This calls for a broader reassessment of available measures at the DSO level which includes not only expanding the DSO’s own set of tools but also embracing user-driven approaches, such as community energy initiatives, that support and complement grid operations.