On April 28, large parts of Spain and Portugal experienced a sudden blackout that left the two countries with many lingering questions.
The direct cause was a voltage surge that caused a series of grid failures and triggered automatic shutdown mechanisms in power stations. The event sparked a public blame game, with Spain’s high dependence on wind and solar energy—now accounting for over half its electricity mix, miscalculations by the national grid operator and insufficient investments in the power grid all cited as possible contributing factors.

Beyond its immediate causes, this blackout underscores a wider issue: Europe’s electricity networks are under pressure. Renewables, electrification of heating and transport, and changing consumption patterns are reshaping demand on a grid that wasn’t built for this. At the low-voltage level, where households, EV chargers, and solar panels connect, the impact is particularly acute: Power flows used to go in one direction, from utility to customer. Now, a home might be both a consumer and a producer, exporting rooftop solar while charging an electric vehicle.  

At the same time, peak loads are rising. A cluster of homes switching on heat pumps during a cold snap can overload local feeders. When this happens, the options are limited: either upgrade the infrastructure at high cost, or better manage what already exists. It’s this second route—managing smarter rather than just building more—that’s attracting attention from European governments and regulators. 

A Tale of Three Countries’ Efforts to Digitise Their Local Networks

Across Europe, Governments are beginning to set expectations for smarter, more responsive grids.  

Germany is among the most advanced. The so-called “Paragraph 14a” of its Energy Industry Act (EnWG) came into force in 2024, allowing distribution system operators to remotely reduce output to appliances like heat pumps or EV chargers, to reduce grid stress.  

At the same time, it imposes new requirements on these distributors: for example, they have to drive grid investments to keep up with energy demand and cannot refuse to connect new energy-consuming assets to the network. They must also publish a record of the actions taken, their scope and duration.  

This approach relies on digitisation—smart meters and digital models of low-voltage networks that forecast congestion and adjust demand. As a result, static models are now widespread, and many operators are advancing toward dynamic digital twins. 

The UK is following a similar path, with Ofgem requiring Distribution Network Operators (DNOs) to modernize their local electricity networks under the RIIO-2 price control framework. This includes mandatory improvements in digitisation, reliability and system flexibility. Each DNO must publish a Digitalisation Strategy and Action Plan, which outlines efforts such as deploying digital twins, improving data strategy, enabling real-time visibility of low-voltage networks and supporting peak load management beyond the meter.  

If Germany could provide a blueprint, France provides the cautionary tale. The country has rolled out Linky smart meters nationwide, technically capable of similar control. However, the move has met with significant resistance and backlash, leading to legislation blocking the possibility to throttle energy output.  

Outdated Practices Make a Compelling Case for Digitisation

While the overall direction is clear, practical challenges abound.

The primary one is that low-voltage grids come to digitisation with very traditional management practices, such as basic GIS maps, historical load data and paper records. Outage detection has long been, and still often remains, manual in the form of customer complaints.  

Another hurdle is the consolidation of scattered asset data, such as cables in one database, maintenance logs in another, or control systems separate from planning tools. This lack of integration makes it difficult to plan proactively, shift to better maintenance practices or for technicians to arrive on site with the right information and the right tools.

A further challenge—but also a strong reason to digitise—is the aging workforce. In 2019, Eurostat reported that a third of utility workers were over fifty. In a field still reliant on informal knowledge, this raises the urgency to document processes and support intuitive know-how with reliable data. 

The Way Forward: From Digital Models to Digital Twins

This triple pressure has existed for years, accelerated by the pandemic, and led utilities to develop GIS-based digital models of their networks. These helped standardise asset records and visualise topology, with some ability to simulate load flow or support investment planning. Many DSOs now use static models as their “system of record.”

But static models capture the network at a fixed point. They don’t ingest real-time data, can’t simulate dynamic behaviour and are often disconnected from operational systems. They’re useful for planning, but simulations become unreliable if the underlying data doesn’t match actual grid conditions.

The goal now is to build live, data-fed digital twins that combine sensor inputs, smart meter data and asset condition information. A twin can simulate outages, assess the impact of adding new solar capacity or predict equipment failure.

What does it look like in practice? What has emerged as a common core for this capabilities is a specialized platform that can integrate with third-party systems (like SCADA, AMI, DNA, DMS, CIS and WAMS), to track outages and restore service, feed customer communications, monitor and operate the distribution system and provide grid analysis and optimization and manage and inform field crews. This platform can then be coupled with popular maintenance and asset management software  

Challenges remain. Digital twins require clean, synchronized data from multiple sources, which many utilities lack. They also require investment in IT infrastructure, cybersecurity, and staff training. But as grid complexity grows, the old model of reactive management is no longer viable.