Load Shifting in a Heat Pump Environment

Load shifting in a heat pump environment means moving part of the heat pump’s electricity consumption from one time period to another. The system still delivers the required space heating, cooling and domestic hot water. It runs the heat pump earlier, later or at a different power level and stores thermal energy until it is needed.

Smart controls manage this process. They use information such as electricity prices, photovoltaic output, weather forecasts, building temperatures and grid limits. The purpose is to reduce electricity costs, increase self-consumption, limit peak power and support a more flexible electricity grid.

Heat pumps are well suited to load shifting because buildings and water stores can retain heat or cold. This thermal storage separates the time when electricity is consumed from the time when heating or cooling is delivered. International heat pump research describes this as demand-side flexibility based on thermal inertia and storage.

Load shifting at a glance

• What it is: Load shifting changes when a heat pump consumes electricity.
• What it does: It moves consumption away from expensive, congested or carbon-intensive periods.
• How it is done: The heat pump preheats, pre-cools or charges a thermal store before reducing its power later.
• Why it matters: It can reduce operating costs, avoid local power peaks and use more renewable electricity without reducing comfort.

The basic operating chain is:

Price, PV, weather or grid signal → energy manager → heat pump → thermal storage or building mass → heating, cooling and hot water

Definition of heat pump load shifting

Heat pump load shifting is the controlled relocation of electrical demand from one period to another. The required thermal service remains available. Only the timing and, in some cases, the power level of electricity consumption changes.

Load shifting is called Lastverschiebung in German. It is one element of the broader concept of Lastmanagement, or load management. It is also a form of demand-side flexibility.

A heat pump can provide two directions of flexibility:

• Upward flexibility: The heat pump consumes more electricity during a preferred period. This may occur when photovoltaic electricity is available or market prices are low.
• Downward flexibility: The heat pump consumes less electricity during an avoided period. This may occur during a price peak, grid constraint or site power peak.

What is being shifted?

The system shifts the heat pump’s electrical load. Electrical load is measured in kilowatts, or kW. Electricity consumption over time is measured in kilowatt-hours, or kWh.

The heat pump converts electrical energy into thermal energy. Thermal energy is normally expressed as kWh thermal, or kWh_th. The heat pump’s coefficient of performance, or COP, describes the relationship between thermal output and electrical input.

For example:

• A heat pump drawing 3 kW of electrical power has an electrical load of 3 kW.
• If it operates at that power for two hours, it consumes 6 kWh of electricity.
• At a COP of 4, it can produce approximately 24 kWh of thermal energy during that period.

What load shifting changes

A load-shifting controller can change:

• Compressor start and stop times.
• Compressor power or modulation level.
• Heating flow-temperature targets.
• Buffer-tank temperature targets.
• Domestic hot-water charging times.
• Room-temperature targets within an approved comfort range.
• Heating, cooling and hot-water priorities.
• The maximum electricity imported from the grid.
• The use of electric backup or immersion heaters.

What load shifting does not mean

Load shifting is not the same as reducing total energy consumption. A system can move 10 kWh from the evening to midday while still consuming approximately 10 kWh. Storage losses or inefficient operating temperatures can even increase total consumption.

Load shifting is also not the same as permanently lowering room temperatures. A permanent reduction is an energy-saving measure. Load shifting normally preserves the required service and moves its electrical input in time.

The heat pump environment

The heat pump environment includes more than the heat pump itself. It covers every component that creates, stores, distributes, measures or controls thermal energy.

Relevant entities include:

• The heat source, such as outside air, ground or water.
• The heat pump and compressor.
• Electric backup heaters.
• Underfloor heating, radiators or fan coils.
• Buffer tanks and domestic hot-water cylinders.
• The thermal mass of the building.
• Cooling circuits and chilled-water storage.
• Room, flow, return and storage-temperature sensors.
• A heat pump controller, HEMS, EMS or building management system.
• A smart meter and site electricity meter.
• A photovoltaic system, battery and EV charger.
• Electricity-price, weather and grid-control signals.

Load shifting must be designed around the complete system. A timer connected only to the compressor cannot account for comfort, storage condition, photovoltaic production or other electrical loads.

Core purpose of load shifting

The core purpose of load shifting is to separate the timing of electricity consumption from the timing of thermal demand. The building may need heat at 19:00, but the heat pump does not always need to produce that heat at 19:00. It may produce part of it earlier and store it.

A well-designed controller manages several objectives at the same time. It does not simply operate whenever electricity appears cheapest. It considers cost, efficiency, comfort, equipment limits and grid conditions.

Main objectives

1. Reduce electricity costs.
   The controller moves consumption into lower-priced tariff periods where technically sensible.
2. Increase photovoltaic self-consumption.
   The heat pump converts surplus solar electricity into useful heat, hot water or cooling.
3. Reduce site peak demand.
   The controller avoids simultaneous operation of the heat pump, EV charger, battery charger and other large loads.
4. Respect grid and connection limits.
   The system keeps imported power below a contractual or technical threshold.
5. Support renewable energy integration.
   The heat pump can increase consumption when renewable generation is abundant and reduce it when the power system is constrained.
6. Maintain thermal service.
   Room comfort, domestic hot-water availability and process requirements remain protected.
7. Create marketable flexibility.
   Larger systems may participate in demand-response or flexibility programmes through an aggregator.

The IEA Heat Pumping Technologies programme distinguishes between implicit flexibility, where users respond to tariffs or market prices, and explicit flexibility, where an operator provides an agreed flexibility service to a grid operator, supplier or market participant.

Why heat pump load shifting is needed

Electricity supply and demand do not always match

Solar and wind generation vary by time and weather. Building demand also changes across the day. Morning and evening heating demand can coincide with EV charging, cooking and other household or commercial loads.

Electricity networks must be designed for peak power, not only annual energy use. A short period with many heat pumps and EV chargers operating together can therefore create a network problem even when annual electricity consumption remains manageable.

Heat pump load shifting reduces this timing mismatch. It can move consumption towards periods with available generation and network capacity. The EU electricity-market framework recognises demand response and storage as important tools for integrating variable renewable electricity and maintaining system stability.

Electricity prices are becoming more time-sensitive

Electricity costs may vary through:

• Day and night tariffs.
• Peak, shoulder and off-peak periods.
• Hourly or quarter-hourly market prices.
• Time-variable network charges.
• Maximum-demand charges.
• Grid-flexibility payments.
• Photovoltaic export prices.
• Negative or very low wholesale prices.

A fixed-price customer receives little direct incentive to move consumption. A customer with a time-of-use or dynamic contract receives a stronger signal. However, the complete tariff must be assessed, including taxes, network charges, supplier margins and subscription fees.

EU rules provide smart-metered customers with access to dynamic electricity-price contracts from at least one supplier and from suppliers serving more than 200,000 final customers. The rules also require information about the opportunities, costs and risks of these contracts.

Electrified buildings create new site-level problems

Heat pumps are often installed with photovoltaic systems, batteries and EV chargers. These devices can improve building energy performance, but they can also operate at the same time. Uncoordinated operation may exceed the building connection or create an expensive demand peak.

Typical business and property problems include:

• A limited electrical grid connection.
• An expensive transformer or connection upgrade.
• High commercial peak-demand charges.
• Low compensation for exported PV electricity.
• PV curtailment during high-generation periods.
• Simultaneous operation of several heat pumps.
• EV charging during the building’s heating peak.
• Production or occupancy schedules that limit operating times.
• A need to maintain heating or hot water during a grid-control event.

An energy management system addresses these problems by deciding which device can use power, when it can use power and at what level.

Smart buildings are expected to respond

The European Commission’s Smart Readiness Indicator assesses whether buildings can sense conditions, communicate and respond to occupants and energy grids. Its technical domains include heating, cooling, domestic hot water, electricity, EV charging, monitoring and control. Energy flexibility and storage are explicit assessment areas.

Load shifting therefore connects heat pump operation with the wider development of smart buildings. The heat pump becomes a controllable energy asset rather than an isolated heating appliance.

How heat pump load shifting works

Load shifting follows a closed control loop. The controller measures the current system, predicts future conditions, selects an operating plan and then checks the result.

Step 1: Measure the present condition

The controller records room temperatures, flow temperature, return temperature, buffer temperature, hot-water temperature and heat pump power. It may also measure total building import, photovoltaic generation and battery power.

This data shows whether thermal energy is already available. It also shows whether the electrical connection has enough remaining capacity.

Step 2: Forecast future demand and supply

The controller estimates future:

• Space-heating demand.
• Cooling demand.
• Domestic hot-water consumption.
• Outside temperature.
• Solar gains.
• Photovoltaic generation.
• Electricity prices.
• Grid constraints.
• Occupancy or production schedules.

A forecast allows the controller to prepare before a peak. A reactive controller can only respond after the peak has started.

Step 3: Define hard operating constraints

The system establishes limits that must not be violated. These include minimum and maximum room temperatures, safe storage temperatures, compressor limits, defrost requirements and maximum grid import.

The controller also protects domestic hot-water availability and any critical process load. Economic optimisation begins only after these constraints are satisfied.

Step 4: Calculate available flexibility

The controller estimates how much thermal energy can be stored. It also estimates how long heating, cooling or hot-water production can be delayed.

Available flexibility depends on:

• Building insulation and thermal mass.
• Outdoor temperature.
• Current room temperature.
• Heating-system temperature.
• Storage volume and temperature range.
• Domestic hot-water demand.
• Heat pump capacity.
• Acceptable comfort variation.
• Forecast accuracy.

Step 5: Preheat, pre-cool or charge storage

The heat pump operates during a preferred period. It may slightly raise a room-temperature target, charge a buffer tank or prepare domestic hot water.

The heat pump should use the lowest practical temperature increase. Excessive storage temperatures increase heat loss and reduce heat pump efficiency.

Step 6: Reduce demand during the avoided period

The controller reduces compressor power, lowers a setpoint or delays a non-critical charging cycle. In some systems, it may temporarily stop the compressor.

The building and thermal stores continue to release heat or cooling. Occupants should not experience a material loss of comfort.

Step 7: Recover gradually

After the avoided period, the controller returns the system to normal operation. It should avoid restarting every controlled device at full power.

A staggered or modulated recovery prevents a rebound peak. A rebound peak occurs when deferred loads restart together and create a new maximum.

Step 8: Verify the result

The controller compares actual operation with the planned schedule. It records whether the shift reduced cost or peak demand and whether comfort remained within limits.

Future schedules can then be adjusted. This feedback process is essential for predictive control.

Practical residential example

A house has underfloor heating, a hot-water cylinder and rooftop PV. The PV forecast indicates surplus electricity between 11:00 and 14:00. The controller prepares hot water and permits a small, approved rise in room temperature during that period.

The heat pump then operates less between 18:00 and 20:00. The building slab and hot-water cylinder supply the required thermal service. The household avoids buying part of its evening electricity and uses more of its own solar generation.

Key features of a heat pump load-shifting system

Metering and signal acquisition

Definition. Metering and signal acquisition collect temperatures, electrical power, thermal output, photovoltaic generation, tariff values and grid commands.

Purpose. The controller needs an accurate system state before it can move demand.

Benefits. Reliable data reduces incorrect charging, comfort violations and false savings calculations.

Example. A site meter shows total grid import while room and storage sensors confirm whether a two-hour reduction is possible.

Typical inputs include:

• Heat pump electrical power.
• Total building import and export.
• PV generation and forecast.
• Battery charge and discharge power.
• Room temperatures.
• Flow and return temperatures.
• Buffer and hot-water temperatures.
• Compressor state.
• Auxiliary-heater state.
• Electricity prices.
• Weather forecasts.
• DSO or aggregator signals.

Forecast-based scheduling

Definition. Forecast-based scheduling predicts future thermal demand, electricity prices and renewable production.

Purpose. It identifies the most suitable operating periods before demand occurs.

Benefits. It reduces unnecessary preheating and protects comfort during long shift windows.

Example. The controller may prefer a slightly higher-priced but warmer afternoon period because an air-source heat pump can operate more efficiently then.

Price alone is not enough. The controller should consider the expected COP at each time. It should also consider storage losses and the amount of heat actually required.

Flexibility calculation

Definition. Flexibility calculation estimates the amount of electrical load that can be moved and the maximum safe shift duration.

Purpose. It connects thermal storage capacity with an electrical operating plan.

Benefits. It prevents the system from promising more flexibility than the building can supply.

Example. A controller may determine that hot-water charging can be delayed for four hours, while space heating can only be reduced for one hour during cold weather.

A useful estimate is:

Shift duration ≈ usable stored thermal energy ÷ average thermal demand

This value changes continuously. A building may provide several hours of flexibility in mild weather and very little flexibility during design winter conditions.

Thermal storage management

Definition. Thermal storage management controls energy held in water, building materials or cooling media.

Purpose. It creates a time buffer between heat production and heat delivery.

Benefits. The heat pump can avoid an unfavourable electricity period without interrupting service.

Example. A buffer tank is charged before a network peak and then supplies the heating circuit while compressor power is reduced.

Effective storage control requires more than a maximum temperature. It should account for stratification, heat loss, minimum usable temperature and the actual heating-system requirement.

Compressor modulation and setpoint control

Definition. Modulation changes compressor output instead of using only full-power start and stop commands.

Purpose. It shapes the load profile more precisely and maintains stable thermal output.

Benefits. Modulation can reduce peaks, limit cycling and improve temperature control.

Example. A heat pump may reduce electrical input from 4 kW to 2 kW during a site peak rather than stopping completely.

Not every heat pump supports external power modulation. Some systems accept only operating-state or enable signals. Compatibility must be checked for the exact model and controller version.

Comfort, hygiene and safety guardrails

Definition. Guardrails define the conditions that optimisation may not violate.

Purpose. They protect occupants, equipment and domestic hot-water service.

Benefits. Load shifting remains invisible to users and does not compromise safe operation.

Example. A price signal may delay hot-water charging, but the controller overrides that delay when the available hot-water volume becomes too low.

Guardrails should cover:

• Minimum and maximum room temperatures.
• Maximum flow and storage temperatures.
• Frost protection.
• Defrost operation.
• Minimum compressor running and stopping times.
• Domestic hot-water availability.
• Applicable hygiene routines.
• Critical commercial or process temperatures.
• Manual user overrides.

Site power and peak-demand control

Definition. Site power control limits the combined electricity imported by all major devices.

Purpose. It protects the electrical connection and avoids demand peaks.

Benefits. A building may avoid connection upgrades, demand charges or protective-device trips.

Example. When an EV starts charging, the EMS temporarily reduces heat pump power while preserving the required room temperature.

The control target should normally apply at the grid connection point. This allows the system to account for on-site PV and battery discharge.

Auxiliary-heater management

Definition. Auxiliary-heater management controls immersion heaters and electric backup heating separately from the compressor.

Purpose. It prevents resistance heating from cancelling the benefit of load shifting.

Benefits. The system avoids a sudden high electrical load and preserves heat pump efficiency.

Example. The compressor may be permitted to charge a hot-water cylinder during a low-price period while the immersion heater remains disabled.

Auxiliary heaters require explicit monitoring. A controller that records only total heat pump power may not identify whether additional resistance heating caused a peak.

Compressor-cycle and rebound management

Definition. Cycle management limits rapid start-stop operation and controls recovery after a shift.

Purpose. It protects compressor life and prevents a new peak after the event.

Benefits. The heat pump operates more smoothly and the measured flexibility remains useful to the site or grid.

Example. Ten heat pumps in a residential development restart in sequence rather than at the same second.

IEA heat pump flexibility research notes that frequent starting and stopping can increase maintenance risk. The same research warns that optimisation should consider building power peaks, not only day-ahead electricity prices.

Communication and interoperability

Definition. Interoperability allows the heat pump, meter, PV system, battery and energy manager to exchange usable commands and measurements.

Purpose. It enables coordinated operation across devices from different manufacturers.

Benefits. The site can optimise total energy flow instead of controlling each device independently.

Example. A HEMS receives PV production and sends a permitted power value to the heat pump.

Possible communication methods include:

• Digital input contacts.
• SG Ready operating states.
• Modbus TCP or RTU.
• BACnet in commercial buildings.
• EEBUS.
• Manufacturer APIs.
• Inverter-specific interfaces.
• Smart-meter gateways.
• DSO or aggregator control channels.

A protocol name alone does not guarantee compatibility. Both devices must support the same data points, commands and use case.

Monitoring and verification

Definition. Monitoring records actual load shifting, comfort and energy performance.

Purpose. It confirms whether the strategy creates value.

Benefits. Operators can identify failed controls, storage losses, auxiliary heating and forecast errors.

Example. A monthly report compares peak kW, heat pump electricity, COP and shifted consumption with the previous baseline.

Useful performance indicators include:

• Maximum site import in kW.
• Heat pump peak power.
• Shifted electrical energy in kWh_e.
• Thermal energy delivered in kWh_th.
• COP and seasonal performance.
• PV self-consumption.
• Electricity cost per kWh_th.
• Auxiliary-heater consumption.
• Compressor starts.
• Comfort deviations.
• Hot-water shortfalls.
• Rebound peak.
• Flexibility-event success rate.

Where thermal energy can be stored

Building thermal mass

Definition. Building thermal mass is the heat-retaining capacity of floors, walls, ceilings, furniture and other materials.

Purpose. It allows the heat pump to preheat or pre-cool the building before an avoided period.

Benefits. It provides storage without installing a separate tank and is especially useful with low-temperature surface heating.

Example. An underfloor heating system charges the floor slab during a PV-rich afternoon and reduces compressor operation during the evening peak.

Building mass is most useful in well-insulated buildings with slow temperature change. It is less predictable in buildings with high heat loss, uneven room control or large internal gains.

The approved temperature band should remain small. Overheating rooms to maximise storage reduces comfort and wastes energy.

Heating buffer tank

Definition. A buffer tank stores heated water for the space-heating circuit.

Purpose. It separates heat pump production from immediate heating-system demand.

Benefits. It offers measurable thermal capacity and can support hydraulic stability.

Example. A 500-litre buffer is raised by 5 K before a high-price period.

The approximate thermal capacity of water is:

Stored heat in kWh_th ≈ volume in litres × temperature change in K × 0.001163

For a 500-litre store and a 5 K increase:

500 × 5 × 0.001163 ≈ 2.9 kWh_th

At a COP of 3, the compressor needs approximately 1 kWh of electricity to produce this heat, excluding pumps and losses. The usable amount may be lower because of mixing, minimum system temperature and standing losses.

A buffer tank is not automatically required for every load-shifting project. Oversized tanks increase cost, space use and heat loss. The building and heating system may already provide sufficient volume and thermal inertia.

Domestic hot-water cylinder

Definition. A domestic hot-water cylinder stores thermal energy for washing, bathing and other hot-water uses.

Purpose. It allows water heating to occur before the actual draw-off period.

Benefits. Hot-water demand is often easier to move than space-heating demand.

Example. The cylinder is charged at midday using PV electricity instead of being reheated after evening showers.

The controller must retain enough usable hot water. It must also comply with manufacturer instructions and applicable hygiene requirements.

Raising the cylinder temperature increases storage capacity, but it can reduce COP and increase heat loss. The selected temperature should therefore reflect actual demand rather than the maximum possible value.

Chilled-water and building cooling storage

Definition. Cooling storage retains cold in a building, water tank or specialised storage medium.

Purpose. It moves cooling production away from hot, expensive or grid-constrained periods.

Benefits. It can reduce afternoon electrical peaks in cooling-dominant climates.

Example. A commercial building pre-cools its structure during the morning and reduces chiller or reversible heat pump power during the late-afternoon peak.

Cooling control must also manage humidity and condensation. Pre-cooling should not create uncomfortable room temperatures or moisture problems.

Large thermal stores and thermal networks

Definition. Large thermal storage uses high-volume water tanks, district networks or process stores.

Purpose. It decouples large heat pump plants from short-term network and building demand.

Benefits. Commercial, industrial and district systems can shift substantial loads for longer periods.

Example. A heat pump cascade charges a district heating store when electricity prices are favourable and reduces output during a grid peak.

Large systems require hydraulic modelling, redundancy and detailed operational planning. Their economic value may include energy-market optimisation, demand-charge reduction and contracted flexibility.

Electrical battery storage

Definition. A battery stores electricity rather than thermal energy.

Purpose. It supplies the heat pump or other devices when grid electricity is expensive or limited.

Benefits. It can coordinate electrical loads that thermal storage cannot serve.

Example. A battery supports the heat pump during a site import limit while the thermal store supplies part of the heating demand.

A battery is complementary to heat pump load shifting. It is not a substitute for thermal system design. Thermal storage is limited to heating or cooling, while a battery can serve any electrical load.

Types of heat pump load-shifting control

Fixed-schedule control

Definition. Fixed-schedule control uses programmed start, stop or setpoint times.

Purpose. It moves operation into known tariff periods.

Benefits. It is simple and does not require live price or PV data.

Example. Domestic hot water is prepared during a fixed off-peak period every night.

The limitation is low adaptability. The schedule does not react to weather, occupancy or changing electricity prices.

Time-of-use tariff control

Definition. Time-of-use control follows predetermined peak, shoulder and off-peak prices.

Purpose. It reduces consumption during recurring expensive periods.

Benefits. Prices are predictable and easy to configure.

Example. A heat pump charges its buffer before a weekday evening peak period.

This model works best when tariff periods are stable and the price difference is large enough to cover additional storage losses.

Dynamic electricity-price control

Definition. Dynamic control uses electricity prices that change by hour or market settlement interval.

Purpose. It selects operating periods with the lowest expected cost.

Benefits. It can respond to short-term market conditions and renewable generation.

Example. The controller prepares heat during a low-price afternoon and reduces operation during an evening price spike.

The controller should optimise the cost of delivered heat, not electricity price alone. Dynamic contracts also expose the customer to price volatility.

PV-surplus control

Definition. PV-surplus control increases heat pump operation when on-site solar generation exceeds other demand.

Purpose. It converts exported electricity into useful thermal energy.

Benefits. It can increase self-consumption and reduce grid import later.

Example. The heat pump raises the hot-water target when PV export exceeds a defined threshold.

Forecast-based control normally performs better than a simple instantaneous threshold. It can avoid repeated starts when clouds cause rapid changes in PV output.

Peak-limit control

Definition. Peak-limit control keeps site power below a fixed or variable maximum.

Purpose. It protects the grid connection and avoids maximum-demand costs.

Benefits. It coordinates the heat pump with EV charging, batteries and other large loads.

Example. The EMS reduces heat pump input when site import approaches 20 kW.

Peak-limit control may shift energy into a later period. It should therefore manage the recovery load as well as the original peak.

Grid-led or explicit demand response

Definition. Explicit demand response changes heat pump operation after a request from a DSO, supplier or aggregator.

Purpose. It provides a measurable flexibility service to the electricity system.

Benefits. The operator may receive lower network charges or a flexibility payment.

Example. A group of heat pumps temporarily reduces grid import during a local network constraint.

Contract terms must define event duration, response power, measurement method, availability and user override. The heat pump still requires safety and service protections.

Predictive or model-based control

Definition. Predictive control uses mathematical or digital models of the building, heat pump and storage.

Purpose. It selects the best operating schedule across several future intervals.

Benefits. It can balance price, COP, PV, comfort and site power in one calculation.

Example. The controller compares a cheap cold night with a slightly more expensive but warmer afternoon and selects the period with the lower cost of useful heat.

Model-based control requires good data and commissioning. A poor building model can create incorrect schedules.

Hybrid multi-objective control

Definition. Hybrid control combines dynamic prices, PV, weather, grid limits and comfort requirements.

Purpose. It optimises the complete energy system rather than one signal.

Benefits. It avoids conflicts between devices and operating objectives.

Example. A controller uses PV for hot water, reserves battery capacity for the evening and limits the combined heat pump and EV load.

This is normally the most capable control type. It also requires the highest level of integration.

Heat pump load-shifting use cases

Detached house with photovoltaic generation

Problem: Midday PV electricity is exported at a low value while the heat pump buys electricity in the evening.

System response: The controller prepares hot water and stores limited heat in the building during the PV period.

Business value: The household increases self-consumption and reduces later grid purchases.

Home with a dynamic electricity tariff

Problem: Electricity prices vary strongly between hours.

System response: The heat pump schedules heating and hot-water production around expected price and COP.

Business value: The customer reduces the average cost of useful heat while maintaining a defined comfort range.

Home with heat pump, EV charger and battery

Problem: Several large loads can exceed the building connection.

System response: The HEMS assigns available power according to priority, thermal state and departure time.

Business value: The owner can operate more electrical equipment without increasing the connection capacity.

Multi-family residential building

Problem: Several heat pumps or central plant stages may start at the same time.

System response: The controller staggers starts, manages storage and limits total power.

Business value: The operator reduces simultaneous demand and maintains more stable operation.

Hotel or hospitality building

Problem: Heating, cooling and hot-water demand overlap with kitchen and laundry loads.

System response: The BMS forecasts occupancy and prepares thermal storage before high-demand periods.

Business value: The hotel reduces peak demand without limiting guest comfort.

Office, school or retail property

Problem: The site has predictable occupancy but high daytime electricity demand.

System response: The building is preheated or pre-cooled before occupancy and during favourable tariff periods.

Business value: The operator reduces operational peaks and uses the building structure as a flexibility resource.

Industrial or process application

Problem: The business needs stable process temperatures and faces high capacity charges.

System response: Large heat pumps charge process or water storage outside production peaks.

Business value: The company reduces maximum electrical demand while protecting production requirements.

Heat pump cascade or district heating plant

Problem: Large thermal demand and volatile electricity prices create significant operating-cost exposure.

System response: The plant controller selects heat pump stages and storage charging based on heat demand, market price and minimum running times.

Business value: The operator can reduce operating cost, avoid excessive cycling and potentially provide flexibility services.

Cooling-dominant regions

Problem: Cooling demand peaks during hot afternoons when electricity networks are highly loaded.

System response: The heat pump pre-cools the building or chilled-water store earlier in the day.

Business value: The property reduces afternoon peak power and may benefit from lower tariff periods.

Benefits of heat pump load shifting

Benefits are not automatic

Load shifting can reduce electricity cost without reducing electricity consumption. It can also increase consumption if the strategy uses unnecessarily high storage temperatures or creates additional heat loss.

A poor strategy may:

• Operate an air-source heat pump during colder hours.
• Increase heating flow temperature too far.
• Overheat a buffer tank or building.
• Activate an electric immersion heater.
• Create frequent compressor starts.
• Cause a large rebound peak.
• Shift consumption into a low wholesale-price period with high total network charges.
• Ignore supplier fees or tariff risk.
• Store more heat than the building requires.

Compare the cost of useful heat

The relevant value is not only the price of electricity. It is the cost of delivered thermal energy.

A simplified calculation is:

Cost per kWh_th ≈ all-in electricity price per kWh_e ÷ expected COP

Example:

• Electricity at €0.20/kWh with a COP of 2 produces heat at approximately €0.10/kWh_th.
• Electricity at €0.26/kWh with a COP of 4 produces heat at approximately €0.065/kWh_th.

The higher electricity price produces cheaper heat in this example. A price-only controller would make the wrong decision.

This is particularly important for air-source heat pumps because outdoor temperature affects efficiency. iDM also notes in its current product information that switching solely on electricity price may increase costs when heat pump efficiency is not considered.

Selection criteria for a load-shifting solution

Define the primary objective

The project should begin with one clearly measured problem. A system designed for PV self-consumption may use a different control strategy from a system designed for network power limits.

Possible primary objectives include:

• Dynamic electricity-price optimisation.
• Time-of-use tariff optimisation.
• PV self-consumption.
• Maximum-demand reduction.
• Grid-connection protection.
• Compliance with DSO controllability rules.
• Flexibility-market participation.
• Carbon-intensity optimisation.
• Coordinated operation with EVs and batteries.

Secondary objectives can then be added. Conflicting objectives require a priority order.

Check the heat pump’s control capability

Verify the exact heat pump model, controller and software version. Marketing terms such as “smart-grid ready” do not define every available command.

Check whether the system supports:

• Start or enable commands.
• Power limitation.
• Compressor modulation.
• Heating setpoint changes.
• Hot-water setpoint changes.
• Cooling setpoint changes.
• Operating-mode selection.
• Auxiliary-heater lockout.
• Feedback of power and operating state.
• Remote software updates.
• Fail-safe operation after communication loss.

Quantify usable thermal flexibility

Storage volume alone does not determine flexibility. The calculation must include the useful temperature range and the building’s demand during the shift period.

Assess:

• Buffer volume and temperature limits.
• Domestic hot-water volume.
• Building heat-loss rate.
• Building thermal mass.
• Heating-emitter type.
• Current flow temperature.
• Expected outdoor temperature.
• Permitted room-temperature variation.
• Expected hot-water draw-off.
• Storage and distribution losses.
• Minimum compressor running times.

The required store should not be sized only from nominal heat pump capacity. It should be sized around the thermal demand that must be covered during the intended shift window.

Evaluate the heating and cooling distribution system

Low-temperature emitters generally provide better conditions for efficient preheating. Underfloor heating also adds useful thermal mass.

High-temperature radiators may offer less practical storage within the building. They can still support load shifting through a buffer or hot-water store, but high temperature targets may reduce COP.

Cooling systems require additional checks. Humidity, surface temperature and condensation protection must remain active during pre-cooling.

Check metering and data availability

Dynamic control needs accurate, timely data. A monthly electricity bill is not sufficient for operational optimisation.

Check for:

• Smart-meter availability.
• Meter-data interval.
• Real-time site power measurement.
• PV production measurement.
• Import and export measurement.
• Room-temperature sensors.
• Buffer and hot-water sensors.
• Access to tariff data.
• Weather and PV forecasts.
• Data retention and export.
• Communication reliability.

Assess other flexible assets

The heat pump should not be optimised in isolation where a battery or EV charger is present. Each asset competes for the same electrical connection and may respond to the same low-price period.

The energy manager should understand:

• EV departure time and required charge.
• Battery state of charge.
• Battery reserve requirement.
• PV export limit.
• Heat pump thermal state.
• Building maximum import.
• Other large electrical loads.
• Generator or backup-power conditions.

Analyse the complete tariff

Review the complete bill, not only the advertised spot price. Dynamic energy prices may form only one part of the customer’s total cost.

Include:

• Energy price.
• Network energy charge.
• Maximum-demand charge.
• Fixed supplier charge.
• Dynamic-tariff subscription fee.
• Taxes and levies.
• Metering cost.
• PV export value.
• Negative-price treatment.
• Price caps or floors.
• Contract termination conditions.

Verify local regulatory requirements

Control requirements differ by country, DSO and installation date. A system may require a smart meter, approved control device, separate meter or specific communication route.

The installer should confirm:

• Applicable DSO rules.
• Electrical registration requirements.
• Network-tariff eligibility.
• Heat pump and backup-heater treatment.
• Required control interface.
• Customer override rights.
• Data-protection requirements.
• Applicable building and hot-water standards.

Check commissioning and support

The value of load shifting depends on commissioning. Default settings cannot represent every building, tariff and occupancy pattern.

Require:

• A documented control strategy.
• Defined comfort limits.
• A tested fail-safe state.
• Verification of auxiliary-heater control.
• A communications test.
• Baseline and post-commissioning data.
• Remote or local diagnostic access.
• A process for software updates.
• Clear responsibility between installer, controls provider and energy supplier.

Selection red flags

Be cautious when a proposal:

• Promises savings based only on the lowest hourly price.
• Does not model heat pump COP.
• Assumes every litre of storage water is usable.
• Ignores the building’s heat loss.
• Cannot detect the auxiliary heater.
• Has no rebound-control strategy.
• Requires excessive room or storage temperatures.
• Does not state the exact compatible models.
• Cannot export performance data.
• Has no safe mode after a communication failure.

Load shifting compared with related concepts

Load shifting versus load shedding

Load shifting delays or advances consumption. The thermal service remains available through storage or later recovery.

Load shedding reduces demand by stopping a service. An emergency shutdown of heating is load shedding unless the missing heat has already been stored or can be delivered later without service loss.

Load shifting versus peak shaving

Load shifting focuses on timing. Peak shaving focuses on the maximum kW value.

A heat pump can support both. It can move hot-water preparation to another period and modulate the compressor to remain below a power limit.

Load shifting versus energy efficiency

Efficiency reduces the amount of electricity required. Load shifting changes when that electricity is used.

The strongest system combines both. It first reduces heat demand and flow temperature, then shifts the remaining efficient load.

Thermal storage versus battery storage

Thermal storage directly supports heating or cooling. It avoids converting stored electricity back into heat and can provide significant thermal capacity.

A battery is more versatile because it can serve any electrical load. It also has electrical conversion losses, cycling limits and a finite usable capacity. The correct choice depends on whether the business problem is thermal or electrical.

Time-of-use tariffs versus dynamic tariffs

A time-of-use tariff has predetermined periods. It is easier to understand and control.

A dynamic tariff changes according to market or system conditions. It offers more optimisation opportunities but creates greater price risk and requires automated control.

Integration with other energy systems

Photovoltaic integration

Definition. PV integration uses measured or forecast solar generation to influence heat pump operation.

Purpose. It moves heating, cooling or hot-water production into periods with local electricity production.

Benefits. It can reduce grid import and increase the value of on-site generation.

Example. The controller charges domestic hot water when expected PV production exceeds the site’s normal electrical demand.

A robust strategy should use both a forecast and live measurements. Live data corrects forecast error, while the forecast prevents short cloud movements from causing repeated compressor starts.

Battery integration

Definition. Battery integration coordinates the heat pump with electrical storage.

Purpose. It prevents the heat pump and battery from competing for the same low-price or PV period.

Benefits. The site can reserve battery capacity for loads that cannot use thermal storage.

Example. PV first supplies current demand, then the heat pump charges thermal storage, while the battery retains a reserve for the evening.

The optimum priority depends on battery efficiency, export value, expected evening load and heat pump COP. A fixed priority is not always optimal.

EV charging integration

Definition. EV integration shares available site power between transport and thermal demand.

Purpose. It keeps total imported power within the connection limit.

Benefits. The building may avoid a larger electrical connection.

Example. The EMS temporarily reduces heat pump power when an EV must reach a required charge before departure.

The controller should compare thermal urgency with EV departure time. It should not simply give permanent priority to one device.

HEMS and building management systems

Definition. A home energy management system or building management system coordinates multiple energy assets.

Purpose. It applies one site-level strategy across the heat pump, PV, battery, EV charging and other loads.

Benefits. It prevents independent controllers from issuing conflicting commands.

Example. A BMS limits total building power while maintaining room temperatures and hot-water production.

Commercial systems may also integrate occupancy schedules, weather data, ventilation and process loads. The energy manager should exchange both commands and operating feedback.

Smart meters and tariff data

Definition. A smart meter records consumption in defined time intervals and may support remote data exchange.

Purpose. It enables time-based billing and verifies whether load shifting occurred.

Benefits. The customer can use dynamic or time-variable tariffs and measure the result.

Example. Quarter-hourly meter data confirms that a heat pump avoided a network peak period.

Billing data and real-time control data are not always the same. A separate site meter may be required where the official meter does not provide sufficiently fast local data.

DSO and aggregator integration

Definition. DSO or aggregator integration connects the heat pump system to an external flexibility request.

Purpose. It allows a group of loads to support local or market-level grid operation.

Benefits. Customers may receive reduced network charges or flexibility revenue.

Example. An aggregator coordinates hundreds of heat pumps and reduces their combined power for a defined period.

The interface must preserve local control. The building controller should decide how the requested reduction is delivered while protecting equipment and service limits.

Heat pump cascades

Definition. A cascade uses several heat pump modules to serve one larger thermal system.

Purpose. It matches output to demand and provides redundancy.

Benefits. The plant can shift load by selecting the number and operating level of active modules.

Example. Two modules charge storage before a peak, while one module maintains minimum operation during the peak.

Cascade sequencing should consider equal runtime, minimum run time, source conditions and hydraulic flow. Starting all modules together can create a significant electrical peak.

Recommended control priority

A complete energy manager should use a clear priority hierarchy:

1. Equipment safety, frost protection and defrost.
2. Mandatory grid and electrical connection limits.
3. Domestic hot-water hygiene and critical process requirements.
4. Occupant comfort and service availability.
5. Compressor lifetime and efficient operation.
6. Site peak reduction.
7. Electricity-price, PV and carbon optimisation.
8. Optional flexibility-market revenue.

Economic optimisation should never override a hard safety constraint.

SG Ready and advanced energy management

The SG Ready label identifies heat pumps and compatible components with a defined load-management interface. The interface can be used for grid-oriented operation or for increasing PV self-consumption. It is an interface specification, not a complete optimisation algorithm.

Current BWP requirements describe three principal operating states for heating heat pumps:

1. Limited electrical power.
2. Normal operation.
3. Boosted operation for thermal storage.

Older documentation and existing installations often use a four-state contact arrangement. Installers must therefore follow the exact rule version and device documentation. The current BWP page includes both the newer three-state requirements and the legacy four-state description.

An SG Ready contact can communicate a general operating request. A digital EMS can provide more detailed information, such as:

• A variable power limit.
• A heating or hot-water setpoint.
• Available PV power.
• A site import limit.
• A start time and end time.
• Operating-state feedback.
• Fault information.
• Measured electrical power.

SG Ready can therefore be a useful entry-level interface. Predictive, multi-device load shifting normally requires more granular communication and feedback.

Regulatory and market context in priority regions

The following examples are current to August 2026. Tariffs, supplier offers and technical rules can change. Every project should confirm current requirements with the responsible regulator, DSO, supplier and qualified installer.

European Union

EU electricity-market rules promote active consumers, demand response and energy storage. Smart-metered consumers have a legal route to dynamic electricity-price contracts, while suppliers must explain the associated opportunities and risks. The EU electricity-market reform that entered into force in July 2024 also strengthened the role of flexibility in integrating renewable generation.

For building projects, the Smart Readiness Indicator provides an additional policy context. It treats grid responsiveness, energy flexibility and storage as recognised smart-building capabilities.

Germany

Germany’s §14a EnWG rules cover new controllable consumer devices such as heat pumps with a grid connection power above 4.2 kW. Since 1 January 2024, affected new systems must allow network-oriented control. During a concrete local grid risk, the DSO can temporarily limit grid consumption to a defined minimum rather than switching off normal household electricity.

For many installations, the minimum is 4.2 kW. Larger heat pumps and cascades above 11 kW use a scaled minimum under direct control. Customers receive a reduced network charge in return, and an EMS can allocate available power among heat pumps, batteries and EV charging while accounting for local PV or battery discharge.

Germany also offers different network-charge modules. Module 2 reduces the network energy rate to 40% and requires a separate meter. Module 3 has allowed time-variable network charges in combination with Module 1 since April 2025.

Austria

Austria provides a current example of a time-variable network incentive. From 1 April to 30 September 2026, the Sommer-Nieder-Arbeitspreis reduces the network energy charge by 20% between 10:00 and 16:00 for eligible network-level 7 customers. Quarter-hourly smart-meter data is required.

E-Control specifically identifies heat pumps and EV charging as loads with significant potential to benefit from moving consumption into the midday period. This measure illustrates how network tariffs can encourage greater use of midday solar generation.

Switzerland

From tariff year 2026, Swiss rules allow a dynamic network tariff to be used as a base tariff for smart-metered customers when a non-dynamic optional tariff is also offered. Regional dynamic tariffs are also possible. Federal guidance emphasises quarter-hour measurement, transparent tariff information and intelligent control.

The same control principles apply to heat pumps, EV chargers and other flexible loads. Customers should verify the local DSO’s tariff structure and control offer because implementation can vary by network area.

Italy, including South Tyrol

ARERA defines time bands such as F1, F2 and F3. Prices can therefore differ according to the time of consumption. Customers with second-generation electronic meters may also have free-market contracts using other time bands.

For heat pump users in South Tyrol and other Italian regions, the relevant opportunity depends on the selected retail contract, meter and network conditions. A controller should use the actual contracted tariff rather than assuming that every F1, F2 or F3 price follows the same structure.

Spain

Spain’s 2.0TD network tariff uses three energy periods and two contracted-power periods. For mainland Spain, the Balearic Islands and the Canary Islands, the valley energy period includes 00:00 to 08:00 on working days and all hours on weekends and national holidays.

This structure creates a clear use case for scheduled hot-water preparation, preheating and pre-cooling. Retail electricity contracts may add separate price signals, so the controller should use the customer’s complete tariff.

Poland

Since 24 August 2024, Polish electricity suppliers serving at least 200,000 final customers have been required to offer dynamic-price contracts to eligible consumers. A remotely read meter is a basic requirement. The Polish regulator also stresses that customers need to understand the price risks and actively manage consumption.

Heat pump automation can reduce the need for manual price monitoring. The business case should still include supplier fees, contract terms and the actual ability to shift winter heating demand.

Finland

Dynamic electricity contracts are already established in Finland. At the end of 2024, they represented approximately 33% of household electricity contracts. Finland’s Energy Authority states that customers bear the price-fluctuation risk, although dynamic contracts are usually the least-cost option where consumption can be moved to cheaper hours.

This makes Finland a strong use case for predictive heat pump control. Cold-weather efficiency, comfort reserves and winter price exposure remain important design factors.

Implementation process

Step 1: Establish a baseline

Record at least:

• Heat pump electricity consumption.
• Thermal output where available.
• Maximum site power.
• PV import and export.
• Auxiliary-heater use.
• Room and hot-water temperatures.
• Compressor starts.
• Existing tariff cost.

The baseline should cover representative weather and occupancy conditions.

Step 2: Define the target

Choose a measurable target such as:

• Reduce evening heat pump demand by 2 kW.
• Keep total site import below 15 kW.
• Move 30% of hot-water electricity into PV hours.
• Reduce annual peak-demand charges.
• Avoid a specified dynamic-price percentile.
• Provide an agreed flexibility response.

Step 3: Map controllable components

Document every heat pump, heater, pump, valve, storage tank, meter and energy asset. Record its communication interface and safe operating limits.

This step identifies missing sensors or incompatible controls before installation begins.

Step 4: Estimate flexibility

Calculate usable storage and expected demand for each intended shift period. Repeat the calculation for mild, normal and design winter or summer conditions.

Flexibility should be stated as both:

• Power flexibility in kW.
• Energy flexibility in kWh over a stated duration.

Step 5: Configure constraints

Set comfort, hygiene, safety and power limits. Configure minimum compressor running and stopping times.

The system should also define what happens after loss of internet, meter data or external control.

Step 6: Test each operating mode

Test:

• Normal operation.
• Increased consumption.
• Reduced consumption.
• Maximum site power.
• PV-surplus operation.
• Dynamic-price operation.
• Auxiliary-heater lockout.
• Communication failure.
• Manual override.
• Recovery after an event.

Step 7: Monitor the first operating period

Compare expected and actual results. Look for cycling, excessive storage temperature, comfort deviation or rebound peaks.

Optimisation settings should then be adjusted gradually.

Step 8: Review performance seasonally

A winter heating strategy may not suit spring PV production or summer cooling. Seasonal review keeps the control model aligned with actual operating conditions.

Load shifting turns a heat pump into a flexible electrical load. The system moves heating, cooling or hot-water production to a more suitable period and uses thermal storage to maintain service. Effective control combines measurement, forecasts, thermal models, equipment limits and site-level energy coordination.

The main value comes from reducing operating costs, using more photovoltaic electricity, controlling peak power and supporting grid flexibility. These benefits depend on correct design and commissioning. The controller must optimise the cost and impact of useful heat rather than following a single price or PV signal.

For iDM projects, the NAVIGATOR energy manager and optional iON optimisation provide a system-based route from basic heat pump control to predictive load shifting. The final configuration should always reflect the building, tariff, heat pump model, local regulation and required comfort level.

Frequently asked questions

Does load shifting reduce heat pump electricity consumption?

Not necessarily. Its primary function is to change the timing of consumption. Total consumption may fall, remain similar or increase depending on heat pump efficiency, storage temperature, heat losses and auxiliary-heater use.

Does every heat pump support load shifting?

Most heat pumps can support basic scheduling. Advanced load shifting requires suitable control inputs, sensors and operating feedback. The exact capability depends on the heat pump model, controller and software version.

Is a buffer tank required?

No. The building mass, heating circuit and domestic hot-water cylinder may already provide useful flexibility. A buffer should be installed only where it serves a justified hydraulic or storage purpose.

Can load shifting work without photovoltaic panels?

Yes. A heat pump can respond to time-of-use tariffs, dynamic prices, peak-demand limits or grid-control requests without PV.

Can load shifting work with a fixed electricity tariff?

Yes, but the direct energy-cost benefit may be limited. It may still reduce site peaks, protect a connection or coordinate the heat pump with an EV and battery.

Will occupants notice the temperature change?

A correctly commissioned system should remain within a defined comfort range. The controller may use small temperature variations, but it should not create noticeable overheating or cooling.

How long can a heat pump load be shifted?

The duration can range from minutes to several hours. It depends on weather, building heat loss, storage capacity, hot-water demand and the permitted comfort range.

Can load shifting damage the heat pump?

Normal controlled modulation and scheduling should not damage a correctly designed system. Poor control can increase cycling, interrupt defrost or activate backup heating. Minimum run times and manufacturer limits must remain active.

Is SG Ready sufficient for dynamic tariff optimisation?

SG Ready can communicate general operating states. Dynamic, predictive optimisation normally also needs tariff data, measurements, forecasts and a controller that can evaluate the complete system.

Can air-source and ground-source heat pumps both shift load?

Yes. Air-source heat pumps require particular attention to outdoor temperature and defrost. Ground-source systems normally have more stable source temperatures, but borehole, ground-loop and compressor limits still apply.

Can heat pump cooling be shifted?

Yes. Buildings and chilled-water systems can be pre-cooled. Humidity, condensation and comfort limits must remain active.

Is a dynamic electricity tariff always cheaper?

No. The customer accepts price volatility and may pay supplier or metering fees. The tariff is most suitable where enough consumption can be automated and moved without reducing efficiency.

Should the controller follow the lowest electricity price?

Not automatically. It should compare the all-in electricity cost, expected COP, thermal demand and storage losses. The lowest electricity price does not always produce the lowest-cost heat.