Distribution utilities across emerging markets are investing in visibility below the transmission level — sensors on feeders and transformers, smart meters and monitoring platforms — on networks that were long operated with little real-time information.

The drivers are rooftop solar and reverse flows, electric-vehicle charging, pressure to cut losses and outage times, and regulators tying tariffs to reliability metrics.

What is being deployed

Fault indicators and feeder sensors, transformer monitoring, smart meters with communications, advanced distribution management systems and outage-management tools. Programmes are often phased, starting with the worst-performing or highest-load feeders. Our earlier report on digital control centres covers the transmission side.

Supplier implications

Volume orders for sensors, meters and communications; software and integration contracts; and cybersecurity requirements attached to anything connected. Local support and interoperability with legacy systems are decisive. See our grid section.

Background: the invisible half of the grid

Transmission networks in emerging markets are generally well instrumented — SCADA, protection relays and, increasingly, phasor measurement units give control rooms a real-time picture. Distribution networks are not: many utilities cannot see voltage, load or outages below the primary substation, and learn of faults from customer calls. That was tolerable when power flowed one way. It is not tolerable when rooftop solar, EV charging and behind-the-meter batteries turn feeders into two-way networks, when loss-reduction programmes need metering data, and when regulators set reliability targets. The IEA’s grid analysis and the World Bank’s digital utility work both single out distribution visibility as a priority.

What is being deployed, in more detail

• Smart meters and AMI at customer and transformer level, giving load, voltage and outage data.
• Feeder sensors and fault indicators, often wireless and battery-powered, on medium-voltage lines.
• Distribution automation: remotely operated switches and reclosers that isolate faults automatically.
• ADMS and DERMS platforms that turn sensor data into control actions and host DER management.
• Communications: cellular, RF mesh and fibre networks — and the cybersecurity requirements that come with them.

What it means for suppliers to utilities and OEMs

Distribution sensing is one of the broadest procurement categories in the utility market: meters, sensors, communications modules, RTUs, reclosers, software platforms and integration services, usually bought in staged programmes with development-bank finance. Interoperability (IEC 61850, DLMS/COSEM), cybersecurity and local support are scored heavily, and pilots precede fleet roll-outs. Suppliers should track digitalisation programmes on our grid reliability page and understand utility qualification as described in How to sell to utilities in emerging markets.

Quick answers

What is grid sensing below transmission level?

Meters, sensors, automated switches and software that give utilities real-time visibility and control of medium- and low-voltage distribution networks.

Why are utilities investing in distribution visibility now?

Because rooftop solar, EVs and batteries make distribution flows two-way, and because loss reduction and reliability targets require data the utilities did not previously have.

Sources and further reading

• IEA — Electricity Grids and Secure Energy Transitions — grid digitalisation analysis
• World Bank — Energy — utility digitalisation programmes
• IEC 61850 — substation and distribution automation standard
• EnergiTech Media — Cybersecurity requirements enter utility procurement — related coverage

This article was researched and written by the EnergiTech Media editorial team and last reviewed in August 2026. We update country and sector guides as tenders, plans and regulations change. Spotted something out of date? Email support@energitechmedia.com.