Quick summary

IEC 61850 has become the backbone of the digital substation, promising multi-vendor interoperability and far less wiring than legacy telecontrol protocols. Yet IEC 60870-5-104 is not simply switched off, and the real engineering challenge is managing a coexistence between the two while keeping protection and cyber risk under control.

Introduction

For decades, substation communication was a patchwork. Control centres talked to substations over telecontrol protocols such as IEC 60870-5-104, while inside the substation, devices from different vendors often could not exchange data without expensive, custom conversion. Interoperability between equipment, sometimes even between versions from the same supplier, was a recurring engineering problem.

IEC 61850 was created to resolve that. It replaced bespoke point-to-point wiring and proprietary messaging with a standardised, object-oriented model for power utility automation. The result is the digital substation, but reaching it is rarely a clean switchover, because the protocols serve different layers of the grid and have to coexist for years.

Why IEC 61850 became the digital substation standard

First published in 2003, IEC 61850 defines communication networks and systems for power utility automation, and it has since grown into a central standard for both substation automation and the wider smart grid (Electronics, 2023). Its defining promise is interoperability: devices from different manufacturers can exchange data through a shared information model rather than through vendor-specific translation.

The practical gains are significant. Standardised data models and the XML-based substation configuration language reduce engineering effort, Ethernet and fibre replace bundles of copper wiring, and high-speed messaging supports protection signalling fast enough for real-time operations. Redundancy protocols keep communication available even when a network path fails.

IEC 61850's real value is not speed or wiring savings alone, but the ability to integrate multi-vendor equipment without rebuilding the integration from scratch each time.

That said, interoperability in practice is not automatic. Peer-reviewed analysis of multi-vendor deployments has documented issues such as latency under high traffic and mismatches between manufacturers' implementations, which is why structured testing is essential rather than optional (Electronics, 2023).

Takeaway: IEC 61850 became the digital substation standard by enabling multi-vendor interoperability through a shared data model, though real deployments still demand rigorous interoperability testing.

Understanding what actually needs to migrate

A frequent misconception is that IEC 61850 simply replaces IEC 60870-5-104 everywhere. The two protocols largely serve different layers. IEC 60870-5-104 is a telecontrol protocol carrying data between control centres and substations or RTUs over TCP/IP, while IEC 61850 operates principally inside the substation, across the station bus and process bus, and increasingly across distributed energy resources.

Because of this, migration is usually about modernising automation inside the substation while the control-centre link continues to run IEC 60870-5-104, at least initially. Gateways translate between the two worlds, presenting IEC 61850 data to a control centre that still expects telecontrol messaging. The implication is that operators are managing coexistence, not a single cutover, and the gateway becomes a critical and sensitive component.

This phased reality is what makes protocol integration across vendor generations the defining skill of a substation modernisation programme, because the hardest engineering sits at the boundaries where new digital systems meet equipment and protocols that will remain in service for years.

Takeaway: Migration rarely means replacing IEC 60870-5-104 outright; it means digitalising the substation with IEC 61850 while gateways bridge to a control-centre link that still uses telecontrol protocols.

Planning a phased migration

Because a substation cannot be taken offline for a wholesale rebuild, modernisation proceeds in stages. A workable sequence tends to follow a recognisable shape:

• Build an accurate inventory of existing devices, protocols and communication paths

• Define the target architecture, including station bus, process bus and redundancy

• Introduce IEC 61850 in new or refurbished bays while legacy bays continue to operate

• Deploy gateways to mediate between IEC 61850 and existing IEC 60870-5-104 links

• Test interoperability across vendors before each stage goes live

The interpretive point is that the inventory step is where most projects either succeed or stall. An operator that does not know precisely what is installed and how it communicates cannot design a coexistence architecture that will hold, and across the Nordics and DACH, where substation fleets span many vendors and decades, that discovery work is substantial.

The pacing also reflects asset lifecycles. Protection relays and other intelligent electronic devices are long-lived, so a realistic migration aligns with refurbishment cycles rather than forcing premature replacement, which keeps capital spending proportionate to the benefit gained.

Takeaway: A phased migration aligned to refurbishment cycles, beginning with a precise asset inventory, is more durable and affordable than attempting a single wholesale switchover.

The cybersecurity dimension of digitalisation

Digitalising a substation expands its attack surface. Replacing isolated, hardwired logic with networked, Ethernet-based communication creates connectivity that, while operationally valuable, introduces exactly the kind of exposure that regulators now scrutinise. A digital substation is a richer target than its analog predecessor.

This is where modernisation intersects directly with regulation. The NIS2 Directive and the electricity sector's Network Code on Cybersecurity both expect operators to manage OT risk rigorously, and IEC 62443 supplies the technical controls, including the zones and conduits model that segments a digital substation into defensible compartments. The reason this matters is that an IEC 61850 migration designed without security in mind can satisfy an engineering goal while creating a compliance liability.

The most sustainable approach treats cyber resilience as part of the migration design rather than a later addition. Segmentation, secure gateway configuration, and monitoring of substation traffic should be specified alongside the automation architecture, because retrofitting them onto a completed digital substation is far harder and more expensive.

Takeaway: Digitalising a substation widens its attack surface, so security controls aligned with NIS2, the NCCS and IEC 62443 should be designed into the migration, not bolted on afterwards.

Conclusion

Moving toward IEC 61850 is one of the defining modernisation efforts in the European grid, unlocking interoperability and efficiency that legacy telecontrol protocols cannot match. But it is a transition managed in phases, with IEC 60870-5-104 and gateways remaining part of the architecture for years.

The operators who navigate it well share a pattern: they start from an honest asset inventory, plan around refurbishment cycles, test interoperability relentlessly, and design cybersecurity in from the beginning. Handled that way, the digital substation becomes not just a faster one, but one that is genuinely ready for a more connected and more regulated grid.

FAQ

Does IEC 61850 replace IEC 60870-5-104?

Not directly. The two protocols mainly serve different layers of the grid. IEC 60870-5-104 is a telecontrol protocol used between control centres and substations or RTUs, while IEC 61850 operates principally inside the substation. In practice, operators digitalise the substation with IEC 61850 and use gateways to bridge to control-centre links that still run IEC 60870-5-104, so the two coexist for years.

What are the main benefits of migrating to IEC 61850?

IEC 61850 enables interoperability between equipment from different manufacturers through a shared data model, reduces wiring by using Ethernet and fibre instead of copper, supports high-speed protection signalling, and provides redundancy for resilient communication. Its standardised configuration language also lowers engineering effort, and the standard increasingly extends to distributed energy resources and wide-area monitoring.

What are the biggest challenges in an IEC 61850 migration?

The main challenges are achieving genuine multi-vendor interoperability, which requires structured testing rather than assuming devices will work together, and managing the coexistence of legacy and digital systems through gateways. Building an accurate asset inventory is foundational, and the expanded cyber attack surface of a digital substation must be secured from the outset.

How does an IEC 61850 migration affect cybersecurity compliance?

Digitalising a substation increases its connectivity and therefore its attack surface, which brings it more firmly within the scope of frameworks such as NIS2 and the Network Code on Cybersecurity. IEC 62443 provides the technical controls, including network segmentation through zones and conduits. Designing these controls into the migration is far more effective than retrofitting them later.

Sources

• Review of the legacy and future of IEC 61850 protocols encompassing substation automation systems – Electronics (peer-reviewed) – 2023 – https://www.mdpi.com/2079-9292/12/15/3345

• Interoperability based on IEC 61850 standard, systematic literature review and case study – Electric Power Systems Research (peer-reviewed) – 2023 – https://www.sciencedirect.com/science/article/abs/pii/S0378779623002444

• Substation bill of materials, managing supply chain cyber risks on IEC 61850 digital substations – arXiv (preprint) – 2025 – https://arxiv.org/pdf/2503.19638