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Glossary · Energy industry & energy transition

Digitalisation

Digitalisation Data power system energy transition Automation IT OT

In the electricity system, digitalisation refers to the recording, transmission, processing and use of information in digital form. It makes it possible to monitor, calculate, automate or coordinate technical and organisational processes. It does not refer only to individual devices such as digital meters or sensors. It refers to the interplay of measurement, communication, data model, software, control, market process and responsibility.

At its core, digitalisation translates physical states into usable information. A grid section has a voltage and a line has a utilisation level. A heat pump has an operating state, a charge point has an available capacity and a photovoltaic installation has a current feed-in. Digitalisation makes such states measurable and transmittable, and in suitable cases also controllable. From this, forecasts, switching decisions, billing, flexibility offers or grid operation measures can arise.

The technical level ranges from sensors and metering devices via communication networks to control systems, data platforms and automated market processes. In the energy sector, a distinction is often made between IT and OT. IT stands for classic information technology, i.e. data processing, communication, software, user management and billing systems. OT stands for operational technology. It is used to monitor and control physical installations, such as substations, generation plants, protection systems or grid control technology. In the electricity system, both areas are growing closer together. This opens up new possibilities, but also creates new dependencies.

Data, control and responsibility

Digitalisation is often equated with data collection. This equation obscures the important difference between observing and intervening. A digital measured value initially shows only a state. Only when it is processed in a defined process can an action follow from it. This may be a grid calculation, price information, a switching operation, curtailment, automatic charging scheduling or a warning message in grid operation.

Several questions must be settled for this: Who may collect the data, and who may see it? At what temporal resolution is it needed, and how quickly must it be available? Which entity may derive a control decision from the data? And who is liable if an automatic intervention is wrong or fails to occur? Digitalisation therefore changes not only the technology. It also shifts responsibilities between grid operators, suppliers, metering point operators, aggregators, plant operators, platform providers and state supervision.

This becomes clearly visible with the smart metering system. It is more than a modern electricity meter. In Germany, it consists of a digital metering device and a smart meter gateway as a secured communication unit. It can record consumption and feed-in values at finer time resolution and transmit them securely. Together with a control device, it can also serve as an access point for control or market processes. Its benefit, however, depends on whether tariffs, grid charges, control rules, data protection requirements and technical interfaces fit together. A digital meter without suitable processes generates data, but does not yet make better use of grid capacity.

Distinction from automation, electrification and software modernisation

Digitalisation is closely linked to automation, but they are not the same. Automation means that a process runs without constant individual human decisions. Digitalisation can make automation possible, for example when a battery responds to price signals or a distribution system operator controls installations in a grid-serving way. However, there are also purely digital processes without automatic control, for example a better forecast or digital billing.

Digitalisation must also be distinguished from electrification. Electrification means that applications previously run on fossil fuels are switched to electricity, for example heating, transport or industrial process energy. Digitalisation, by contrast, describes the information and control level. It becomes necessary when these new electricity applications are integrated into the grid in large numbers. A heat pump consumes electricity, an electric car charges, an industrial plant changes its electrical load. These processes only become digitally visible and controllable through measurement, communication and suitable operating rules.

Mere software modernisation is likewise something different. A new user interface, an app or a digital invoice can be useful, but do not necessarily affect the energy-economic function. For the electricity system, what counts above all are digital applications that achieve one of these aims: they improve measured values, secure grid operation, unlock flexibility, accelerate market processes or make installations coordinable in a timely manner.

Why digitalisation is becoming more important in the electricity system

In the past, the electricity system was geared more towards large, plannable power plants. Electricity flowed predominantly in one direction, from the higher grid levels to consumers. Digital technology existed even then, above all in power plants, transmission grids and control centres. What is new is how much has to be coordinated in the distribution grids. Photovoltaic installations, battery storage, heat pumps, charge points, controllable consumption devices and smaller generators are spread across millions of locations. Many of them depend on the weather, on user behaviour or on market prices.

As a result, the state of the electricity system becomes more fine-grained and more variable. Distribution grids must not only deliver electricity but also absorb feed-in. Bottlenecks can arise locally even though sufficient generation is available in the overall system. There may also be times when a lot of renewable electricity is available, but loads, storage or grids do not respond appropriately. Digitalisation does not resolve such situations on its own. But it provides the information needed to recognise them and handle them in an orderly way.

An important variable here is the load profile. Annual electricity consumption in kilowatt-hours says little about when power is needed. For grid operation and security of supply, the temporal distribution counts: When do heat pumps run, when do electric cars charge, when do households draw power, when do commerce and industry run their processes? Digital measurement turns a mere annual quantity into a time-resolved picture. Tariffs, grid planning, forecasts and control mechanisms can be derived from it.

Digitalisation is also important for integrating renewable energy. Wind and solar power depend on the weather. Their feed-in must be forecast, balanced and integrated into market and grid processes. The residual load is the load that remains after deducting feed-in from wind and sun. It fluctuates more than in a system with predominantly conventional generation. Digital forecasting and control systems help to better align generation, storage, loads and grid operation over time.

Legal framework in Germany (as of November 2026)

In Germany, it is mainly the Metering Point Operation Act (Messstellenbetriebsgesetz) that governs the digitalisation of metering. It does not provide for an obligation to equip every metering point with a smart metering system. According to the Bundesnetzagentur, installation is mandatory for generation installations above 7 kW, for consumers with more than 6,000 kWh annual consumption and for controllable consumption devices under § 14a EnWG. The timing requirements in § 45 MsbG are equipment quotas for the default metering point operators (grundzuständige Messstellenbetreiber). They are not a deadline obligation for each individual metering point. By the end of 2032, at least 90 percent of the mandatory groups are to be equipped.

As of the reference date of 30 June 2026, according to the Bundesnetzagentur, 26.1 percent of the mandatory installation cases relevant for the quota were equipped. This refers to consumers with an annual consumption of 6,000 to 100,000 kWh, including the cases under § 14a EnWG. The statutory interim quota of 20 percent by the end of 2025 has thus been exceeded on average. Individual metering point operators may, however, be well below it. Relative to all roughly 54.1 million metering locations, the share of smart metering systems was 5.9 percent, which amounts to just over 3.17 million devices. The authority points out that competitive metering point operators are not fully covered. The actual overall quota is therefore likely to be somewhat higher.

The second important pillar is § 14a EnWG. Since 1 January 2024, new controllable consumption devices with a grid connection capacity of more than 4.2 kW in the low-voltage grid must be capable of being curtailed in a grid-oriented manner. These include, for example, private charge points, heat pumps, air conditioners and electricity storage systems. The grid operator may limit their consumption in the event of impending overload. However, a minimum power of 4.2 kW must be maintained. In return, the operator may no longer refuse the connection of such devices because of feared grid overload, and the device operators receive reduced grid charges. This is a good example of the ordering of intervention rights described above: control is permitted, but limited, subject to conditions and linked to compensation.

On the market side, § 41a EnWG has obliged all electricity suppliers since 1 January 2025 to offer customers with a smart metering system a dynamic electricity tariff. Previously this applied only to suppliers with more than 100,000 final consumers. Without a smart metering system, such a tariff is not possible. This shows how metering infrastructure and market product depend on each other.

Typical misunderstandings

  • Digitalisation as a neutral efficiency machine: Digital systems improve processes only if the metering concept, data quality, responsibility and incentives fit together. A grid operator needs different data than an electricity supplier, an aggregator or an end customer. For some applications, quarter-hour values on the following day are sufficient; others need values at second resolution or local information close to real time. Too much data at the wrong resolution can be just as obstructive as too little.

  • Complete controllability: Not every installation that is digitally reachable should be remotely controllable at will. Control in the electricity system touches on security of supply, data protection, property rights, comfort, operational risks and market freedom. For private consumption devices, interventions must be limited, traceable and legally properly regulated. In industrial processes, wrong control signals can endanger production.

  • Vague notion of real time: Grid protection operates in the range of milliseconds, system operation in seconds to minutes. Balancing and market communication usually run in quarter-hours or longer intervals. A digital application must fit the relevant time scale. Billing a dynamic tariff does not require control in the millisecond range. For the protection of a grid section, by contrast, a delayed data point is not sufficient.

  • Digitalisation equals transparency: Digital measurement can create transparency, but does not have to. Data may reside in proprietary systems, be hard to access or be shared only to a limited extent for data protection and security reasons. Transparency arises only through defined data models, access rights, interfaces, verification rules and trust in the institutions involved. Without this order, digitalisation can even create new opacity, because important decisions disappear into software or automatic rules.

Economic and institutional context

Digitalisation costs money before its benefit becomes visible. Metering systems must be installed, communication links operated, data protected, software maintained and staff trained. Added to this are costs for standardisation, certification, IT security and legal coordination. These costs do not automatically arise where the benefit arises. A grid operator may benefit from better control options, while a plant operator bears the effort at the interface. A supplier can offer dynamic tariffs, but needs reliable metering data from the regulated metering sector for this.

This distribution gives rise to perverse incentives. If an investment in digital infrastructure brings benefits mainly for the overall system but is poorly remunerated for the individual investor, it progresses only slowly. If data access for market participants is opened very widely, opportunities for innovation arise, but also risks for data protection and security. If control rights are centralised too strongly, this can block flexibility or damage trust. If they are distributed too unclearly, it remains open in the event of a bottleneck who may act.

Digitalisation also changes the role of distribution system operators. They must know more about local grid states, assess bottlenecks in advance and integrate controllable installations into system operation. Part of system coordination thus moves to the lower grid levels. Transmission system operators remain responsible for large-scale stability, the system balance and frequency maintenance. Digital interfaces between the grid levels therefore become more important, because local measures can feed back onto the overall system.

For markets, digitalisation opens new ways of using flexibility. Small installations can be pooled to respond to prices or grid signals. Battery storage, electric vehicles, heat pumps or industrial loads can shift their operating times, as long as technical limits and users' wishes are respected. This flexibility, however, does not arise automatically through connectivity. It needs price signals, product definitions, metering rules and balancing procedures. In addition, it must be clearly separated what is market-based optimisation and what is a grid-related intervention.

Security as a technical operating condition

The further digitalisation advances, the more important IT security and operational security become. Electricity supply is part of the critical infrastructure. A digitally networked energy system depends on secure communication channels, authentication, unaltered software and resilient operating procedures. Faulty updates or data, compromised access or overloaded communication systems can directly affect operation. Cybersecurity is therefore not an add-on function added afterwards, but part of the technical design. In Germany, the energy-specific IT security obligations were reorganised in the Energy Industry Act (Energiewirtschaftsgesetz) with the implementation of the European NIS 2 Directive. In this context, providers of digital energy services such as aggregators also came more into focus. The details depend on the type of installation, size and classification of the operator.

Security does not mean doing without digital systems. Analogue or poorly observable systems also have risks. The task is to shape digital dependencies deliberately: with separated security zones, robust emergency processes, tested interfaces, logging, redundancies and clear fallback levels. An electricity system must not only be digitally efficient in normal operation, but must also remain manageable during disruptions.

In the electricity system, digitalisation is thus the information and control layer that connects physical installations, market processes and grid operation. It makes states visible, shortens reaction times and can make flexibility usable. Its value does not result from the amount of data or the number of devices. It results from how well measurement, rules, responsibility, security and operational benefit fit together.

Sources

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Edited by eCMS on 11.11.2026 19:06

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