How can DSOs rise to the investments challenge? Implementing Anticipatory Investments for an efficient distribution grid

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Executive summary and recommendations

The timely deployment of a wider array of distributed generation sources and the electrification of demand in regions with limited or no grid capacity is unlikely to meet the European Union’s climate goals without anticipatory investments in grid infrastructure. This is particularly pertinent at the distribution level, as distribution grids are currently ill-equipped to manage the integration of gigawatts (GWs) as outlined in the EU’s Fit for 55 and REPowerEU objectives. While distribution networks have been instrumental in supporting the energy transition thus far, there is an urgent need for further expansion, modernisation and digitalisation to accommodate the growing influx of renewable energy sources (RES) and the electrification of final energy consumption. Moreover, in situations where the need for grid expansion is driven by electrification and decarbonisation targets, delays in implementation not only impede the energy transition but also hinder economic growth.

Despite this, existing regulatory frameworks in several European countries, including Spain, Romania, Portugal, and the Netherlands, lean towards restricting investments in distribution networks for the future due to the influence of current grid tariffs. This approach hinders adequate network development, which is crucial for ensuring lower overall energy tariffs for consumers in the future. With the EU's reinforced climate ambitions and stringent timelines, there is a distinct imperative to shift from a traditional incremental approach to anticipatory grid development.


The distribution system operators’ (DSOs) objective in presenting this paper is to develop proposals for a forward-looking development of the grid, aimed at delivering positive societal impacts.

For the implementation of anticipatory investments, Eurelectric suggests the following definition:

An anticipatory investment is one that proactively addresses expected developments, looking beyond immediate needs of generation or demand, assuming with sufficient level of certainty that new generation and demand will materialise, notwithstanding potential low utilisation in the short term.

Below is a list of considerations that national regulatory authorities (NRAs) will have to address when implementing anticipatory investments:

  • Once transposed, the national Network Development Plans (NDPs) of DSOs outlined in Article 32 of the Electricity Directive (Directive (EU) 2019/944) should serve as the primary mechanism for projecting anticipatory investments. Ideally, these plans should establish a forward-looking perspective up to 2040, which will evolve over time. If investment caps are in place, their removal should be prioritised as a first step.


  • Adequate incentives should be put in place for DSOs to make anticipatory investments. To be able to invest, DSOs need sufficient remuneration and a stable and predictable investment environment.


  • Various approaches can be considered when assessing anticipatory investment needs, with final decision to engage in the investments entrusted to the DSO. Since most investments in new renewables and electrification will occur at the distribution level, it is crucial to ensure that the development of grid investment plans follows both a top-down and bottom-up approach to ensure alignment between decarbonisation targets and infrastructure The following actions are recommended:
    • Member States should establish long-term electrification scenarios, through roadmaps or national energy and climate plans (NECPs). Those scenarios should include intermediate milestones to facilitate a gradual implementation of anticipated investments. The Governance Regulation should undergo a review to include a specific new section mandating Member States to assess investments necessary in grids to achieve electrification and decarbonisation objectives.
    • DSOs should engage with regional and local authorities to obtain their energy transition plans, ensuring alignment with broader regional objectives.
    • DSOs can lead public consultations to gather input from stakeholders and communities on electrification priorities and infrastructure requirements.
    • DSOs can conduct individual discussions with network users and local authorities to understand specific electrification needs and tailor investment plans accordingly.


  • Reciprocal coordination between transmission system operators (TSOs) and DSOs is paramount. In due course, TSO plans should be coordinated with anticipatory investment forecasts. As per Article 57 of Regulation (EU) 2019/943: agile and flexible updates should be made to TSO planning, allowing for the incorporation of DSO needs and the consequent anticipatory investments. This ensures the optimisation of efficiency and effectiveness of the entire electricity system. Moreover, if DSOs request provisional capacity at a certain location for distribution purpose, TSOs should respond in a timely manner with the delivery of the requested capacity.


  • Taking into consideration local specificities, NRAs could also explore the possibility of empowering DSOs to construct TSO network in application of article 51.8 of Directive (EU) 2019/944, in cases where the TSOs are unable to accommodate the requests of DSOs into their national development plans (NDPs) in a timely manner. In such instances, in those Member States where DSOs are not allowed to own transmission assets, a property transfer should take place according to the DSOs’ related incurred costs based on rules stated by the NRA.


  • The validation methodology for anticipatory investments involves notifying and providing information to regulatory authorities, primarily through submission of NDPs to the NRAs. The validation should occur ex-ante. Cost recovery must always be ensured, including an adequate return on investments.


  • As the entire society benefits from enhancing the grid in a forward-looking manner, anticipatory investment costs borne by the DSOs must be financed in the same way as other investments, i.e., through tariffs. This approach aligns with the Electricity Regulation (EU) 2019/943 Article 18 and revised Electricity Market Design (EMD) Article 18, ensuring fair distribution of costs and benefits across stakeholders. In addition, deferral strategies may be proposed to mitigate immediate cost impacts, with warranties provided by NRAs to DSOs for external funding purposes.


  • Where public funds are available, NRAs should provide incentives for DSOs to utilise them for anticipatory investments.


  • Anticipatory investments are likely to require comprehensive review of connection charging policies moving towards a shallow per megawatt (MW) connection fee[1], instead of invoicing the customer for the actual incurred connection costs, which can vary based on location and condition of existing network. This approach would ensure a level playing field for customers regardless of their connection.


  • The remuneration regime should be reviewed to reduce pressure on the short-term cost reduction driver. In the transition to output-based remuneration regarding anticipatory investments, performance indicators such as efficiently delivering capacity and/or avoiding customer supply refusals for longer than a specified duration could be used to incentivise DSOs.


  • Risk assessment should be improved, with regulation prioritising inadequate grid development risk mitigation over concerns about potential underutilisation of assets. Accordingly, DSOs' regulated income, particularly weighted average cost of capital (WACC) established ex-ante and regulatory asset base (RAB), should not be adversely affected during the development of anticipatory investments. They should have the capability to recover all efficiently incurred costs, regardless of the initial level of asset utilisation. A specific method of efficiency assessment should be implemented for anticipatory investments where needed.


[1] Where shallow connection charges are applied, only costs for the physical connection of the generator to the nearest practical point of the existing network are borne by the generator, whereas deep connection charges mean that generators also have to pay for all necessary grid reinforcements beyond the connection point. Additionally, there are hybrid connection charges, which tend toward a shallow or deep regime and can therefore be referred to as "shallowish". See Eurelectric’s November 2018 “Charges for Producers connected to Distribution Systems” report.

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