Ireland demand side units: monitoring and system services evidence

An Irish Demand Side Unit (DSU) brings one or more electricity users into the Single Electricity Market as a dispatchable unit. Its response can come from plant shutdown, on-site generation or a combination agreed through the DSU arrangement.

The commercial product, Grid Code obligation and site operating plan are related, but they are not the same record. The market participant registers the unit and receives the dispatch. EirGrid owns the compliance process and site-specific signal requirements. The site owner still needs an operational record that explains what was available, what changed and whether production, safety or equipment limits constrained the response.

Current DSU size and registration boundaries

EirGrid's published DSU guidance states the following boundaries.

Capacity is not the same as ordinary annual consumption or a site's maximum import connection. Record how the flexible MW quantity was derived, which assets contribute, which loads must remain running, and how on-site generation is treated. The approved DSU registration and Grid Code documents control the formal capacity.

EirGrid publishes separate two-hour, six-hour and 24-hour capacity test procedures, a signals and communications test, and an aggregate report template. It may also require further testing for ongoing performance monitoring. Use the current templates supplied for the specific test rather than copying a previous site's test pack.

Build the site record from the main incomer inward

The first operational measurement belongs at the electrical boundary where the site's demand change is visible. From there, separate the assets that make the response.

1. Main incomer. Record three-phase active power, reactive power, voltage, current, power factor, frequency and cumulative energy with a documented sign convention.
2. Controllable loads. Record the running state, measured demand, operating limit, command, acknowledgement and process constraint for each participating load or group.
3. On-site generation. Record generator output, availability, fuel or energy constraint, start command, breaker state and the independent change at the incomer.
4. Battery storage. Record AC power, state of charge, available charge and discharge power, mode, alarms and active limit. Keep the battery management system's protection role intact.
5. Essential demand. Identify loads that cannot be curtailed and the condition that restores a flexible load before safety, quality or production is affected.
6. Communications. Record freshness, latency, clock source and quality for every value used in availability or performance calculations.

A site can reduce grid demand by turning off a load, starting generation or discharging a battery. These actions can produce a similar incomer trace while having different emissions, fuel, process, warranty and recovery consequences. Preserve the asset-level record alongside the boundary measurement.

Availability, enabled state and delivery are different signals

The DS3 New Signals Requirements for aggregators distinguish several facts that should remain separate in an operational model.

For the automated frequency-response signals described in the published requirements, the analogue availability, quantity-provided and main-incomer values use one-second resolution with no more than five seconds of latency. The current DS3 protocol separately requires aggregated real-time SCADA demand data at one hertz or better for aggregated sites providing POR, SOR or TOR1, time-stamped and synchronised to a common time. It also requires individual-site data after a performance incident under the stated process.

Those are programme requirements, not a universal setting for every sensor on a site. Preserve the exact service, contract, signal list and document revision that creates each requirement. Do not resample a slow point to one second and describe it as one-second measurement.

Event evidence needs a common clock

A useful event record connects the instruction to the physical outcome.

1. Store the instruction, source, target, requested MW and receipt time.
2. Store the enabled state or acknowledgement without treating it as delivered power.
3. Measure the main-incomer response and each contributing asset on a shared time base.
4. Record the pre-event value, response ramp, sustained interval and recovery or rebound.
5. Record unavailable sites, stale signals, overrides and process constraints.
6. Preserve the raw intervals used in an aggregate calculation and the calculation version.

The DS3 System Services Protocol describes performance monitoring after dispatch instructions, frequency events and fault disturbances. Depending on the service, the TSO can use metering, SCADA, phasor measurement units and event recorders. The service provider's operational dashboard can help investigate the event, but it does not decide the contractual performance scalar.

For FFR performance assessment, the current protocol requires the service provider to complete the TSO template using monitoring-equipment data in the defined format and resolution within three working days. That makes retained, time-aligned source data more useful than a dashboard screenshot or an exported summary with no quality flags.

Commissioning checks for an individual demand site

• Match the main incomer, participating assets and essential loads to the approved single-line diagram and DSU site list.
• Confirm meter ratios, phase order, sign and timestamps during a known load change.
• Compare the site's operational incomer value with the approved TSO or aggregator signal at the same instant.
• Exercise each approved load, generator or battery action within its safe operating procedure and measure the boundary response.
• Verify that a stale asset value removes its contribution from availability instead of carrying forward the last good value.
• Test loss and restoration of communications without creating a false response or a duplicate event.
• Confirm that local protection, process interlocks and battery or generator controllers can reject an unsafe command.
• Retain the signal list, configuration, firmware, calculation version and witnessed test record used for acceptance.

These checks do not replace EirGrid's witnessed Grid Code tests or SEMO registration. They make the owner's data capable of explaining a pass, shortfall or disagreement.

The FASS transition is still moving

The all-island Future Arrangements for System Services (FASS) programme is changing procurement, market and regulatory arrangements. As of 6 October 2026, the SEM Committee is consulting on licence changes needed to establish the system-services markets, while current DS3 Regulated Arrangements documents and contracts continue to define existing obligations.

Do not build a new project around an assumed cutover date or a draft signal set. Keep a controlled requirements register with the current Grid Code, System Services Code or contract, TSO signal list, implementation timetable and SEM Committee decisions. Assign an owner to review it before procurement, before compliance testing and before market go-live.

Where EpiSensor fits

EpiSensor can measure the site's electrical boundary, collect state and limit data from documented Modbus or BACnet equipment, and preserve time-series and event records on an on-site Edge Gateway. It can also forward approved operational data to an aggregator or owner platform.

The approved TSO communications path, market interface, compliance equipment and settlement record retain their formal roles. EpiSensor's useful role is to give the site owner an independent, asset-level explanation of availability and response: what was ready, what was instructed, what changed, and what the main incomer actually measured.

Use the demand response baseline guide for interval and counterfactual design. For storage, apply the battery demand-response guide and command-verification pattern before enabling control.