Where Energy Data Begins

Where Energy Observations Begin

An observation is a single recorded fact: a number, a time, and the thing it describes. In the GB electricity system almost every observation begins at one of three kinds of physical sensor. The first is the smart meter, the small box that records how much electricity a home or business uses. The second is substation telemetry, the instruments inside the buildings and yards where the grid changes voltage and routes power. The third is the synchrophasor, a high-speed sensor on the high-voltage network that measures the precise shape and timing of the alternating current.

These three sources differ in four ways that matter for everything downstream: what they measure, how often they measure it, who owns the resulting data, and how quickly that data needs to be used. A smart meter records one number every half-hour and a person may never look at it. A substation sensor records voltage and current every few seconds and a control engineer may act on it within the minute. A synchrophasor records fifty samples a second and an automatic system may respond before any human sees it. The slower, settle-it-later readings end up on bills; the faster, act-on-it-now readings keep the lights on. Reading the system correctly means knowing which kind of observation is in hand.

Two recent changes set the scene. The rollout of smart meters reached about 37 million meters operating in smart mode by the end of 2025, roughly 71 percent of the meter base, so the smart meter is now the dominant source of raw readings by sheer count.⁸ And the network's asset records moved onto a shared model: the Long Term Development Statement Stage 2 publication of 29 May 2026 sets out distribution network assets in a common data format, so a reading taken at a substation can be tied to a stable record of that substation.¹ The operational and published data feeds that sit on top of these sensors are catalogued by NESO and the network companies.⁷

Smart meters: tens of millions of sensors reading every half-hour

A smart meter is the largest single source of energy data by the number of readings it produces. By the end of 2025 about 41 million smart and advanced meters had been installed in homes and small businesses, of which more than 37 million were operating in smart mode, around 71 percent of the meter base. A meter is in smart mode when it is on a known communications path and exchanging messages with the central smart-metering system; the rest sit in a basic mode for reasons such as a poor signal or a configuration still to be completed.⁸

An electricity smart meter takes one active import reading at the close of each half-hour, time-stamped to its own clock, and stores it locally. That is 48 readings a day. The reading is signed by the meter so that a later reader can tell it has not been altered, and it waits until an authorised party, usually the energy supplier, asks for it. The default request is a daily pull of the previous day's 48 readings. A gas smart meter works differently because it runs on a battery: it wakes once a day, exchanges its reading, and returns to a low-power state, so gas stays on a daily rhythm rather than a half-hourly one.

What a smart meter reading is not is also worth holding. It is not raw, continuous data; it is a tidy total for a fixed half-hour. It is not read by default at finer resolution than monthly for the supplier's own use: a household keeps the right to limit how granular the supplier's access is, with daily and half-hourly access taken only with consent. That consent layer is being put on a standard footing by the Consumer Consent Solution, which Ofgem decided on 29 April 2025 and appointed the Retail Energy Code Company to operate, so that a household can grant and manage consent to share its energy data.¹² The wider privacy rules for meter data sit in the Data Access and Privacy Framework,¹⁰ and the statutory duty for smart-meter communications now sits in Schedule 16 of the Data (Use and Access) Act 2025.⁹ How a reading is then carried, and how it reaches settlement, is set out on the digital infrastructure page.

Network telemetry: substation sensors and transmission synchrophasors

Network telemetry is the second source of raw readings. It produces far fewer observations than the meter fleet because there are far fewer assets, but each asset is watched far more often. The instruments live in substations, the sites where the grid steps voltage up or down and routes power between circuits. A large transmission substation is heavily monitored; a small local substation that feeds a few streets may have almost no instruments at all.

The workhorse device is the Remote Terminal Unit, often working alongside Intelligent Electronic Devices that combine protection and measurement. Together they record the voltage on each busbar, the current and power on each circuit, the position of each switch, the tap position and temperature of each transformer, and any fault event. At transmission level the readings flow on a one to two second rhythm; at distribution level it is more like two to ten seconds at a main substation, and event-driven or nothing at a small one. The data is carried to the operator's control room using standard protocols, chiefly IEC 60870-5-104 at transmission and DNP3 at distribution, where engineers see it and the control system runs its safety checks against it.⁷

Above ordinary telemetry sits the synchrophasor, produced by a Phasor Measurement Unit. A PMU measures the voltage and current waveform 50 times a second, works out the phase angle, and stamps every sample against the GPS time signal so that samples from sites hundreds of kilometres apart can be compared to the same instant. Around 80 PMUs across the transmission network feed a wide-area monitoring service that NESO and the transmission owners use to watch system stability and spot oscillations before they grow. The Grid Code sets the operational duties at transmission that this monitoring supports.⁵

Telemetry does not normally leave the company that owns it. It is the live picture the operator uses to run the system, and only aggregated or derived figures are published: the national demand outturn, the generation mix behind the Carbon Intensity service, the wind output. None of these public feeds republishes the raw substation stream; each one is a summary computed against it inside the operator. The asset model that lets a reading at one substation be compared with the same substation later rests on the Common Information Model base in IEC 61970-301.⁴

Dynamic line ratings: turning local weather into extra network capacity

A dynamic line rating is a worked example of new sensors creating new data to solve a real problem. An overhead line can only carry so much current before it heats up and sags too far. The traditional limit is a fixed seasonal figure, set against a cautious assumption about a still, warm day. But a line in a cold wind can safely carry more, because the wind cools the conductor. A dynamic line rating measures the actual weather and the actual conductor temperature and works out, minute by minute, how much the line can really carry right now.

The data flow is an extension of ordinary telemetry. Weather sensors on the tower or the conductor measure wind speed, wind direction, air temperature and sunlight; a temperature sensor or a thermal model tracks the conductor itself. A small computation turns these into a live current rating that feeds back into the control room, where it informs how much power can be routed down that line. The reading rhythm is typically one to ten minutes.⁷

Asset records: giving every reading a stable identity in the network model

A reading is only useful when its subject is known. A voltage of 11,200 volts means little until it is tied to a named transformer, at a named substation, on a named circuit. Asset records are the part of the data layer that supplies that identity. They are not sensor readings; they are the slow-changing register of what exists on the network and how it connects, and the live readings hang off them.

The register is organised by the voltage cascade, the steps the grid takes from the highest transmission voltage down to the socket. Each step has its own population of assets, its own sensors and its own place in the shared data model. The table below ties each voltage tier to the kind of asset record that represents it.

Two standards supply the shared vocabulary. IEC 61970-301 sets the Common Information Model base used for the transmission network,⁴ and IEC 61968-13 sets the distribution profile that represents the lower-voltage network.³ Each asset in the published model carries a stable identifier, an mRID, that is kept across every later publication, so the same transformer can be tracked from one statement to the next. The first large GB instance of this regulated, model-based publishing is the Long Term Development Statement Stage 2 release of 29 May 2026, with the agreed schedule and the move to a common model set out in Ofgem's derogation letter of 13 May 2026.¹ The official location of record for the data-exchange definitions is the BSI CIM Engagement Hub.² The full treatment of this model, and how it is validated, is on the LTDS explained page; the voltage cascade as an engineering subject is on the voltage page.

The first handoff, and where the longer journey continues

The first handoff is the natural edge of physical data generation. Up to that point the story is about equipment and measurement; past it, the story is about carriage, trust, settlement and rules, and each of those has a page that owns it properly. Holding the boundary in mind keeps the picture from blurring into one undifferentiated stream.

• A smart meter reading is handed to the communications hub at the property and then enters the smart-data pipe. How that pipe is licensed and how it carries the reading is on the digital infrastructure page.
• Once carried, an electricity reading is reconciled into money through the settlement run. That seven-stage journey from a meter reading to a settled bill is on the data lifecycle and settlement page.
• Substation telemetry is handed to the operator's control room and stays there, surfacing publicly only as the aggregated feeds that the wider energy data layer catalogues by type, owner and format.
• Who may see which reading, and under what consent and privacy rules, is set out alongside the carriage on the digital infrastructure page.

Read in order, the three sensor families, their readings and their first handoffs are the foundation the rest of the data layer is built on. Everything a market, a regulator or a planner later does with energy data depends on a measurement that began at one of these sensors and was handed off, intact and identified, into a system that could carry it.