Monitoring and control systems

Digital infrastructure has enabled the transition from a passive, periodically surveyed network to one that can be observed, analysed and acted on in close to real time. However, not all networks have digitalised at the same pace. As power systems transform around the world, the replacement and modernisation of assets is an opportunity to accelerate digitalisation.

Modern grids require real-time visibility and responsive control. Better sensing, connectivity and data systems enable operators to see network conditions more clearly, while remotely controlled assets allow operators to act in near-real time and optimise system performance.

Data and situational awareness

Network operators cannot optimise what they cannot measure. Real-time visibility of the network is therefore the foundation for every downstream application. Traditional SCADA-EMS are being complemented by wide-area monitoring systems (WAMS), which combine high-frequency measurements across broad network areas to give operators a system-wide view of voltage, frequency, power flows and dynamic stability, allowing a wider array of advanced decision support tools. The value of data depends as much on its volume as on its quality, consistency and accessibility, which remain uneven even within a single utility. Unfortunately, a joint study of the European associations of transmission system operators (TSOs) and distribution system operators (DSOs) found that utilities tend to treat data management as a series of disconnected processes rather than a continuous, integrated flow across departments and operators.

Digital twins (see box) are emerging to connect real-time visibility to the network studies that underpin planning and operations. As monitoring and data quality improve, a digital twin can keep the underlying network model current as the system itself changes, rather than relying on periodic manual updates. It can also support control-room simulation grounded in actual measured conditions, rather than assumptions or a manually set system state.

Controllability: Turning visibility into action

Visibility only creates value once operators, or automated systems acting on their behalf, can act on what they see. This depends on remotely controllable grid assets (breakers, switches, tap changers, protection relays and power-electronic devices), integrated with SCADA and EMS so that a detected condition can trigger a response in seconds rather than requiring a field crew to be dispatched. Controllable grid assets are not rolled out everywhere; in particular, many older distribution feeders rely on manual switching and legacy protection, constraining the response capability of the operators.

Digital adoption is highly uneven among network operators, shaped by system needs, regulatory frameworks, investment cycles and institutional capacity. Data in this report comes from an IEA-conducted global survey of network operators in 2026, that received 25 responses: 11 from transmission operators and 14 from distribution operators across Europe, North America, South America, East and Southeast Asia, and Oceania. While the sample is not statistically representative, it provides a geographically diverse snapshot of current digital maturity, deployment priorities and perceived barriers. The starkest divide is between transmission and distribution: transmission is comparatively data-rich and easier to digitalise, since transmission networks have fewer, larger and more standardised assets to instrument than the myriads of dispersed low-voltage assets found in distribution. It is in distribution networks, closest to fast-growing distributed resources, where data gaps are the largest. Many surveyed DSOs report having high ambition, including for the low-voltage grid,1with most aiming to digitalise over 50% of their low-voltage substations by 2035, even for entities starting from close to zero today.

Transmission grids

Digital technologies already play a significant role in modern transmission grids. SCADA and EMS provide real-time monitoring and control of major assets, while digital sensors, PMUs and weather measurements add higher-resolution data on flows, voltage, frequency, equipment condition and operating limits. The use of drones and satellite-based technology enables inspection of power lines and vegetation management with lower effort and reduces exposure of staff to potentially hazardous conditions.

Traditional SCADA-EMS relies on few data combined with asset and system models or estimated variables. For example, a line capacity is estimated based on conditions along the conductor itself, typically approximated from weather data and static assumptions, rather than continuous direct measurement of its actual condition, such as temperature, icing or ageing. The growing level of digitalisation in transmission opens the door to advanced tools such as DLR and control-room decision support. The priority is to keep pushing the integration of SCADA, EMS, PMUs, WAMS and weather and asset data into trusted planning and operational workflows, so that operators can manage flows, stability, congestion and dynamic rating across meshed networks. The main challenge is breaking down data silos, extending monitoring to the asset level where it matters most, and giving operators confidence to act on more dynamic information.

Distribution grids

Traditionally, distribution grids had unidirectional flows and were operated in a static way, with manual switching and limited automation. As more variable supply and demand connects, the flows become bidirectional and networks need to be managed more dynamically.

The challenges in distribution are similar to those in transmission, with one major addition: far more assets to instrument, finer granularity, and the task of combining fragmented feeder, substation, transformer and smart meter data into operational capability. This task is assigned to digital platforms: distribution management system (DMS), advanced distribution management system (ADMS) and distributed energy resource management system (DERMS), which coordinates rooftop solar, batteries, electric vehicles and flexible demand so they can support, rather than stress, local networks.

Digitalisation priorities in distribution are to strengthen low-voltage visibility, putting smart meter data to operational use (not only for billing use) and deploying automation. Smart meters support load flow visibility while making consumers more aware of their consumption and enabling new billing structures. Smart meter data need to be reliable and integrated with ADMS and DERMS data into operational workflows to deliver value, but many datasets are currently isolated. Most emerging market and developing economies (EMDEs) have an even more basic priority: improving feeder and transformer visibility, digitising asset registers, expanding communications and building the operational capability to use data consistently.2

Regional digitalisation adoption

The Smart Grid Index (SGI), run by Singapore’s power network owner and operator SP Group, highlights the pattern of improving but uneven digital maturity.3 The 2024 benchmark covers 92 utilities across 36 countries and assesses multiple dimensions of grid smartness across seven dimensions:

• monitoring and control

• data analytics

• supply reliability

• distributed energy resource and storage integration

• renewable and EV integration

• cybersecurity

• customer-facing services.

The merit of the index is that it does not reward the installation of sensors or meters, but rather how far the data have been put into operational use, such as hosting-capacity assessment, voltage and congestion management, active network management, outage restoration, dynamic operating limits and secure co‑ordination with distributed resources.

North America records the highest regional average score, supported by strengths in data analytics and distributed energy resource integration, while Europe shows more balanced performance across categories. Asia Pacific is closing the gap fastest, helped by rapid gains in supply reliability, a dimension where the region has improved significantly over the past decade, and rapid progress in advanced metering. Utilities in Asia Pacific narrowed the gap thanks to alignment in investment, data systems and operational priorities.

Replacing or refurbishing an asset is the moment to build in digital readiness, by embedding sensing, measurement, communications and monitoring tools and controls at a fraction of the cost of a separate retrofit programme later. Missing this window is costly: once new equipment goes in without it, operators are typically locked out of embedding these capabilities for another full asset lifetime, which can run to several decades, incurring higher costs and delays later on. Since a large share of network spending is already committed to asset replacement, embedding sensors, controls and GET compatibility into these renewal programmes makes modernisation part of planned investment, rather than a separate upgrade requiring its own business case.

Grid assets and the demand they serve operate on very different investment timelines. Power lines, transformers, substations and protection systems typically turn over across decades, far more slowly than the pace of change on the demand side. This mismatch also applies within the digital layer itself: sensing and measurement devices, communications and data systems, and monitoring and control platforms can often be refreshed faster than primary grid equipment, but their value depends on whether the underlying assets were designed to host them.

In advanced economies, there is an opportunity to modernise grids in the coming years. Much of the asset base is ageing: in Europe and North America, a significant share of the lines and cables are approaching the end of their typical operational lifetime. In EMDEs the asset age profile is younger, with roughly 40% commissioned in the past decade and around 35% more than 20 years old. Ageing assets are more prone to faults and require investment to extend their lives, so replacement needs are increasingly converging with demand for new capacity.

Capturing the modernisation opportunity does not mean waiting passively for assets to reach end of life. Where the case is strong, for example on corridors facing the sharpest capacity or stability pressure, utilities can bring modernisation forward, replacing or upgrading assets ahead of schedule specifically to embed digital and GET-ready capability sooner, rather than only opportunistically as natural replacement cycles fall due. The same long asset lives that create this opportunity also constrain how quickly it can be captured: primary equipment often remains in service for more than 40 years, and control and protection systems are typically refreshed only every 15-20 years. Modernisation therefore needs to be managed across overlapping investment cycles: conventional buildout where clearly needed, digital-by-default replacement cycles that embed sensing and measurement tools, communication, data, and monitoring systems, analytics and control capabilities, and GETs and AI-enabled tools that can act as near-term bridges while slower infrastructure, regulatory and manufacturing cycles catch up.