What is demand side response (DSR)? Services, payments and measurement

Demand side response (DSR) is a deliberate change in a site's electricity use, down or up, made when the electricity system asks for it, in exchange for a payment or a lower bill. A cold store that switches off its compressors for an hour during the evening peak, a factory that moves a batch to the night, an electric boiler that runs harder when wind output is high, or a battery that discharges behind the meter are all demand side response.

The value comes from the grid side: reducing demand at the right moment does the same job for the system operator as starting a power station, and it avoids network reinforcement where a cable or transformer is near its limit. The site is paid for being available, for the energy it actually delivered, or both, and the evidence is the meter data at its connection.

Demand side response, demand response and demand side management

The terms overlap, and searches use all of them.

The EU definition, in Article 2(20) of the Electricity Directive (EU) 2019/944, is a change of electricity load by final customers from their normal or current consumption patterns in response to market signals, including time-variable prices or incentive payments, or by selling a demand reduction or increase in an organised market, alone or through aggregation.

Peak shaving and demand side response use the same equipment but answer to different signals. Peak shaving responds to the site's own bill: it cuts the highest interval of the month. Demand side response responds to the grid: it changes use when an external party calls, whether or not that moment is the site's own peak. The peak shaving vs load shifting guide prices the site-side case.

How demand side response works

Every DSR service follows the same cycle, whoever runs it.

1. Register and qualify. The site, usually through an aggregator, registers a unit with the service, proves the meters and the control path, and passes any test the service sets.
2. Declare availability. The unit declares, or bids, how much it can change and when. Some services pay for this availability on its own.
3. Receive the signal. An instruction, a market acceptance, a price or a local frequency measurement triggers the event.
4. Change the load. The site controller sheds, shifts or adds load, or runs generation or storage, within the process limits.
5. Measure the delivery. Interval meter data at the boundary is compared with a baseline, the estimate of what the site would have used without the event.
6. Settle. The service pays for availability and for measured delivery, and applies any penalty for under-delivery.

Sites rarely deal with the system operator directly. An aggregator, also called a demand side response provider or a virtual power plant operator, pools many sites into one unit large enough to meet the service minimum, registers it, bids it and shares the revenue. The site's job is the physical part: a load that can change safely, a control path that works, and metering that proves what happened.

How sites are paid for DSR in Great Britain

Great Britain has several routes, and one asset can often use more than one, provided the services allow the stacking and the same response is not sold twice.

Capacity Market. The Capacity Market pays for reliable capacity to be available in a delivery year that starts on 1 October, procured four years ahead (T-4) and one year ahead (T-1). A demand side response capacity market unit is paid per kW of de-rated capacity and must reduce demand when NESO declares a system stress event. A new DSR unit can prequalify unproven, but must pass a DSR test before the delivery year.

Balancing Mechanism. Independent aggregators can take part in the Balancing Mechanism as Virtual Lead Parties, a role created by Balancing and Settlement Code modification P344 and approved by Ofgem in 2018, without holding a supply licence. Modification P444, which Ofgem approved in April 2025, added compensation for the supplier whose customer's demand the aggregator moves. A Balancing Mechanism unit needs operational metering and must follow the dispatch it has offered within its declared parameters.

Demand Flexibility Service. NESO's Demand Flexibility Service (DFS) began in winter 2022/23. Since 27 November 2024 it has run all year as an in-merit margin tool, and since 9 April 2026 it accepts units from 0.1 MW, includes turn-up as well as turn-down, procures zonally and offers a self-nominated baseline option. From 7 October 2026 NESO also uses it for constraint management that it previously bought through the Local Constraint Market. Delivery is measured against a baseline built from half-hourly meter data; the baseline guide works through the default method.

Distribution network flexibility. Distribution network operators buy local flexibility to keep feeders and substations within their limits, as an alternative to reinforcement. The products are standardised through the Energy Networks Association's Open Networks programme and pay for availability, utilisation, or both. Location matters: only a site behind the constrained part of the network can provide the service.

Frequency response. The dynamic services respond automatically to local frequency: DC and DM deliver in full within 1 s, DR within 10 s. They suit batteries far better than most loads; the dynamic response guide covers the curves, the latency budget and the 20 Hz evidence. Static response, which switches a block of load at a frequency trigger, is the route open to flexible demand.

Network and energy charges. A half-hourly settled site pays distribution use of system (DUoS) unit rates that vary by time band, with the red band typically covering the weekday evening peak in the windows each network operator sets in its charging statement. Moving use out of the red band lowers the bill without any service contract. The Triads are the three half-hours of highest winter demand on the transmission system. Since April 2023 the transmission demand residual has been a fixed charge by site band (Ofgem decision CMP343). Only the smaller locational charge is still billed on Triad demand, so avoiding the Triads is worth much less than before.

Demand side response in Ireland

In the all-island Single Electricity Market, the main route is the Demand Side Unit (DSU): one or more Individual Demand Sites that EirGrid or SONI can instruct to reduce demand, registered with the TSO and SEMO. A DSU with an operational certificate must bid in the capacity auction, can contract to provide DS3 System Services, and is dispatched in the energy market. EirGrid's published guidance gives a 4 MW minimum to register a DSU, and a site above 10 MW can be a standalone DSU but cannot be aggregated with others. The Irish DSU guide covers the registration, testing, live signals and performance evidence.

Demand side response in the EU

Article 17 of the Electricity Directive (EU) 2019/944 requires member states to allow final customers, including those offering demand response through aggregation, to take part in all electricity markets alongside generators, without discrimination. It also lets independent aggregators enter the market without the consent of the customer's supplier. Each country has implemented this in its own way:

• Spain: independent aggregation and active demand response and the SRAD verification;
• France: NEBCO demand flexibility, the successor to the NEBEF mechanism;
• Italy: TIDE and the UVA units;
• Germany: Section 14a EnWG, which lets the distribution network operator limit controllable consumers such as heat pumps and wallboxes in exchange for a lower network charge.

The 2024 electricity market design reform, Regulation (EU) 2024/1747, added a peak-shaving product. It applies only after the Council declares a regional or EU-wide electricity price crisis: member states can then direct system operators to buy demand reductions at peak times. ACER reported on 10 July 2025 that introducing such products under normal market conditions would do more harm than good, so outside a declared crisis the existing markets remain the route for demand response.

Which loads can take part

A load suits demand side response when it can change quickly, hold the change for as long as the service needs, and recover without harming the process. Stored energy is what makes that possible: thermal mass, a hot water store, a reservoir, a battery or a production buffer.

Check two limits before any asset is offered. The first is safety and the process: interlocks, minimum run and off times, and product limits must stay in local control, as the local control and interlock guide sets out. The second is the permit: generators used for DSR are subject to emissions rules, and a backup generator that may run only for emergencies or testing cannot be offered as flexibility without the right permit.

Worked example: a cold store turns down 300 kW for two hours

A cold store with a normal evening demand of about 900 kW commits 300 kW of turn-down to a two-hour event, metered in 30-minute intervals. Compressors stop in stages, and the product temperature rises slowly through the event, so the last interval delivers less. After the event the compressors run harder to pull the temperature back down. The product limit decides how long the store can hold: quick-frozen food must stay at −18 °C or colder, and chilled food at the limit its country sets. The food storage temperature guide lists those limits, and the probe placement guide covers measuring the product rather than the air.

The commitment was 300 kW for 2 hours, or 600 kWh. The site delivered 565 kWh, an average of 282.5 kW, which is 94.2% of the commitment. The rebound took back 105 kWh in the following hour, so the net energy moved out of the event period was 460 kWh, and the site's demand reached 1,050 kW, 150 kW above its normal level, just after the event.

The payment follows from those numbers and the service rules. With purely illustrative prices, not market rates, of £10 per MW per hour for availability over a four-hour window and £200 per MWh for utilisation:

• availability: 0.3 MW × 4 h × £10/MW/h = £12, before any performance factor;
• utilisation: 0.565 MWh × £200/MWh = £113.

Many services scale or cut the payment when delivery falls short of the commitment, and some ignore delivery above it. Whether the rebound counts depends on the service: an event-only measurement ignores it, but if the rebound lands in the site's own peak interval or a red band period, it costs the site money that the event payment has to cover. Two lessons follow. Commit what the site can hold through the last interval, here about 260 kW rather than 300 kW. And control the recovery: staging the compressors back in over an hour would keep the rebound below the normal peak.

What a site needs: measurement and evidence

Boundary metering. The service measures the change at a defined boundary, usually the site's connection or the settlement meter. Every other load behind that boundary appears in the result, so a kitchen or a production line that starts during the event hides part of the response. Submetering the flexible asset separately shows what it did, even when the boundary figure is disturbed.

Interval resolution. Great Britain settles in 30-minute periods, and the EU balancing guideline requires a 15-minute imbalance settlement period. A boundary meter recording at those intervals is the minimum. Faster services need more: frequency response is assessed from 20 Hz data. Use the interval demand calculator to turn a meter's interval energy into average kW.

A baseline you can check. The payment depends on the baseline, so keep enough history in the same meter data to reproduce it. A programme's default baseline can under-state delivery on a site whose load varies with weather or production.

A record of the control path. Log the instruction, the time it arrived, the action taken and the asset's state on the same clock as the meter data. When delivery is short, that record shows whether the cause was the signal, the controller, the asset or the baseline.

A safe state on a lost link. If the site loses contact with the aggregator during an event, it must return the loads on time. The end of the event cannot depend on a message arriving.

The automated demand response guide covers the signals, the control loop and the commissioning checks in detail.

Demand side response with EpiSensor

EpiSensor provides the measurement and local control at the site. The aggregator or VPP operator keeps the market registration, bidding, dispatch and settlement.

A ZEM electricity monitor meters the connection and each flexible circuit at Class 0.5S with its current sensors, so the asset's response can be separated from other loads. The ZDR demand response controller meters a three-phase supply to the same class and responds to under-frequency within 100 ms: the ZDR-20 and ZDR-21 switch a load or start a generator through a relay, and the ZDR-22 sends a set point to a battery over Modbus. The ZDR-21 and ZDR-22 add GPS time and 20 ms event records.

A Gateway running Edge keeps the readings and the automations on site. Edge enforces local stop conditions, such as a product temperature limit, saves the end action of a timed event before it starts, and forwards the data to the aggregator's platform over MQTTS or HTTPS when the link is available. The refrigeration demand response, electric boiler demand response and battery demand response guides lay out complete sites, and the Demand Response & VPP page shows the whole system.