Learning from abroad

This report looks at what countries in Europe, North America and Australia have done to make household electricity use more flexible, what came of it, and what Belgian governments, regulators, grid operators and market parties can take from it. The first part of this summary sets out what other countries show, theme by theme. The second part summarises the recommendations for Belgium that Chapter 9 sets out in full.

What other countries show

1. New network tariffs have small measured effects, and politics steps in when bills jump. Where the effect of new household network tariffs has been measured, peaks fell by a few per cent, and by no more than about 7%. When a visible group saw its bill rise sharply, politicians stepped in: Slovenia's parliament passed an emergency law within weeks after households with solar panels faced network-bill increases of more than 200% (see Chapter 1).
2. What scales is a simple offer built around a device. Where large groups were moved onto time-varying prices by default, in Spain and California, evaluations found little or no response. The contracts that are growing, as in Britain and the Netherlands, are sold around an electric car or a heat pump and rely on automatic control: in Britain, car tariffs accounted for nearly nine-tenths of the growth in households on smart time-of-use tariffs between July 2024 and July 2025 (see Chapter 2).
3. Crisis support can keep or remove the reward for shifting use. Norway first based its support during the 2021-2022 energy crisis on the monthly average price, which kept households' reason to avoid expensive hours, and later on each hour, which largely removed it. Ireland instead caps the wholesale-linked part of dynamic contracts at €0.50 per kWh, a level the wholesale price rarely reaches (see Chapter 2).
4. Devices that respond on their own deliver; asking people to act delivers little. In schemes that pay households to cut their use during peak events, a household that has to act itself delivers about 0.01 to 0.25 kW per event in Britain and California, and one where a device acts automatically about 1 to 5 kW. Enrolling households by default adds participants but not necessarily response: when California enrolled four million households in a peak reward, those at the largest utility cut about 0.03 kW each (see Chapter 3).
5. Buying household flexibility is routine for British grid operators, to postpone reinforcement. Every British distribution grid operator buys flexibility in tenders and auctions. About 9 GW was under contract in 2024, far more than was used, and at the largest local market households supplied 23% of the flexible capacity. Under a shared method, flexibility is worth buying only up to what postponing reinforcement saves, so it bridges the time until reinforcement rather than replacing it. Elsewhere, buying flexibility from households is still at the trial stage or about to begin, as in the Netherlands in November 2026 (see Chapter 4).
6. Some countries simply require devices to be steerable, and it works where the infrastructure is already there. France is moving part of the cheap hours of more than 11 million households from the night to the afternoon by regulatory decision, and water heaters wired to a switch in the smart meter follow automatically. Germany's rule that lets grid operators dim new heat pumps and chargers during moments of grid stress still depends on smart meters that few homes have. When many appliances respond to the same signal at once, they risk creating a new peak, so the countries that switch centrally stagger the start times (see Chapter 5).
7. New rooftop solar can be made controllable without touching existing systems. Germany caps the exports of new systems, South Australia lets the grid operator lower the export limit only when the local grid is close to its limit, and several Australian states can switch off new inverters as a last resort. Built into new installations, these limits cost households little; for price signals on midday exports, no effect has been measured so far (see Chapter 6).
8. Market access alone brings little household volume, and reserve income fades fast. Five years after the United States ordered its wholesale markets to accept pooled home devices, those devices supplied only tens of megawatts. Once batteries rushed into Sweden's small reserve markets, prices fell by 80 to 90% within three years. For a home battery, the savings on its own household's bill are the steadiest part of its value. Offers that need equipment in hundreds of thousands of homes are hard to finance without a long, predictable payment. The first vehicle-to-grid offers, in Britain, France and Germany, combine a bidirectional charger and an electricity contract for one car maker's models, in Britain together with a leased car; none has yet published measured results (see Chapter 7).
9. The meters are mostly there; what matters is whether data, prices and control signals flow by default. Britain is moving every meter to settlement on measured half-hourly use, which gives every supplier a reason to help its customers shift, whatever contract it sells them. California publishes every time-varying rate in one public database that devices can read, and the Dutch grid operators have proposed a short list of five protocols that a home energy manager should speak. Germany shows what can happen when the meter itself is made very demanding: ten years on, only about 6% of metering points have one (see Chapter 8).

What this means for Belgium

Belgium already has many of the pieces that made flexibility grow elsewhere: digital meters in most Flemish homes, whose measured quarter-hourly values have been used in settlement between suppliers since 2026, a Flemish network tariff that charges for the monthly peak, an optional network tariff with time blocks in Wallonia, about 189,000 registered home batteries in Flanders, dynamic contracts on offer in all three regions, the first time-of-use contracts, rules that let independent aggregators sell flexibility, a shared platform to register flexibility providers (FlexHub), and a Flemish test market for congestion services. What it lacks is less the technology than the defaults, the offers and the measurement that put these pieces to work. Chapter 9 turns the lessons of the chapters into twelve recommendations. In short, by group of actors:

• Governments, federal and regional, could design crisis protection that still gives households a reason to avoid expensive hours, before the duty to offer a dynamic contract reaches all Flemish suppliers in 2029, for instance support based on the monthly average price or a cap like Ireland's. In any future product rule or subsidy for home chargers, they could require off-peak default hours and a random start delay as well as steerability, and heat-pump premiums could require domestic hot water to be heated in the middle of the day. If a safety net under market-based flexibility is wanted, it could apply to new and replaced equipment only, with a guaranteed minimum, a payment and published interventions, as in Germany.
• Regulators could publish, before a new network tariff starts, who will pay more and who less, phase the change in and evaluate it a few years later with meter data and a household survey. When designing fixed time blocks, they could check whether new peaks appear at the start of cheap windows and build in a staggered start. Jointly, the federal and regional regulators could require one machine-readable format for contract prices and network tariffs. And regulators could measure what moves: track time-of-use and other new contracts as well as fixed, variable and dynamic ones, and include them in their price comparison tools, ask suppliers how much consumption their products actually shift, and have grid operators report their flexibility purchases as contracted capacity, energy used and euros per kW, with the household share.
• Distribution grid operators could publish, per congestion point and with one shared method, the price up to which flexibility is cheaper than reinforcement. For households, they could consider a published availability price per kW per year, sold through suppliers and aggregators, and complete the planned extension of FlexHub, the platform they share with Elia to record which flexibility provider serves which connection, to all flexibility products, including their own congestion services, so that a household signs up its devices once and can change provider as easily as it changes supplier.
• The federal regulator and Elia could publish each year, in aggregate and within the confidentiality rules, how much of the capacity contracted in the capacity auctions comes from household devices. For any household product at times of scarcity, Elia could pay per kW measured on the device and use competitive bids from the start.
• Suppliers and aggregators could sell control as the product: a low fixed price or a cheap window in return for steering the car, battery or heat pump, switched on by default in a contract the customer chooses, with clear terms and an easy override. Home-battery offers could rest on several sources of income, with the savings on the household's own bill as the foundation and reserve income presented as volatile.
• Manufacturers and installers could make every new heat pump, charger and inverter able to receive an external signal over an open standard, such as those on the Dutch short list, since Belgium buys its devices on the same market, and commission it with price-following control switched on and, for heat pumps, with domestic hot water heated in the middle of the day.

Chapter 9 sets out each recommendation with the chapters it draws on, together with the patterns that run through the report.

The network tariff is the part of a household's electricity bill that covers the cost of the grid infrastructure. It is set by the regulator and the grid operators, not by suppliers, and it is the one price signal that every household receives whichever contract it chooses. Across the countries in this report it makes up between a fifth and a half of what a household pays per kWh: about 21% in Slovenia, 23% in Denmark, 34% in Belgium, 40% in Sweden and 50% in Norway (Figure 1.2).^{[1, 2]} How strongly a network tariff can steer behaviour depends on that share and on how much the tariff itself varies, for example between cheap and expensive hours or between a low and a high peak.

Across Europe, regulators and grid operators are rewriting household network tariffs to reward lower peaks. Where the effect has been measured, peaks fell by a few per cent, and by no more than about 7%.^{[3, 4, 5, 6, 7]} Where a visible group saw its bill jump, politicians stepped in, sometimes within weeks.^{[8, 9, 10]} Countries also differ in whether the new tariff applies to everyone or only to households that choose it. Some are adjusting their designs because fixed cheap hours risk creating a new peak when many devices switch on as soon as those hours begin.

Three designs in use

The new network tariffs follow three basic designs. The first charges each household for its own peak demand. Norway has done so for every household since July 2022, using wide price steps (for example 2–5 kW or 5–10 kW) based on the three highest hourly peaks of each month; Flanders, with its capacity tariff, has charged households per kW of their highest quarter-hour of the month since January 2023; and in 2022 Sweden's regulator ordered all its grid companies to introduce a peak-based charge by January 2027.^{[3, 10, 11, 12]} The second design varies the price per kWh by time of day. Most Danish grid companies charge about nine times as much per kWh between 5 and 9 pm in winter as at night, automatically for every customer, and the Netherlands plans a similar tariff for all households from 2029.^{[13, 14, 15]} Austria added a lighter variant in 2026: a 20% discount on the per-kWh network charge between 10 am and 4 pm from April to September, when solar output is highest.^{[16, 17]} In the third design, each household has a reserved level of power, which it either chooses itself or is given by the grid operator. Every Spanish household chooses how many kW to reserve, with a separate and almost free level for nights and weekends, and in Slovenia the grid operator sets each household's reserved power automatically for five time blocks, based on the household's own peaks of the previous year.^{[18, 19, 20]}

Measured effects are a few per cent

Few of these tariffs have been evaluated (Figure 1.1). Norway's regulator had its reform evaluated with national meter data in 2025: peaks had been affected only to a small degree.^[3] Ellevio, one of Sweden's three largest grid operators and the first of the three to introduce the peak charge, measured 2–3% lower peaks after a year.^[4] A Ghent University study of about 42,000 Flemish households found monthly household peaks about 3% lower on average and about 5% lower in homes with an electric car.^[5] In California, time-of-use prices that two utilities applied by default cut peak use by between 1 and 7%.^{[6, 7]} Forecasts made before a tariff starts are higher. In the Netherlands, a national programme on grid congestion, run jointly by government, regulator, grid companies and suppliers, estimated in advance that the planned tariff would lower peak load by 11%; Fluvius's scenarios for a Flemish time-of-use tariff showed 10–20%.^{[21, 22]} The studies use different measures and methods, so together they show a pattern rather than precise, comparable figures.

The effect comes mainly from households with devices whose electricity use they can move to other times. The Flemish study found only a small, statistically insignificant change in households without low-carbon technologies such as an electric car, home battery or heat pump.^[5] In Spain, 63% of households reserve more power than they use and 44% said at the end of 2023 that they ignore hourly price differences; in Norway, about half of the population does not know that its grid bill depends on its peak.^{[3, 18]} A network tariff therefore tends to work best through devices that respond on their own, which Chapters 2 and 3 look at more closely.

When bills jump, politics steps in

In several countries, a new network tariff met political resistance as soon as a visible group saw its bill rise. Slovenia moved every household to its five-block tariff in October 2024 without a transition phase.^[20] Households with solar panels saw their annual network bills rise by more than 200%.^{[8, 9]} Those bills had been low because the panels reduce how many kWh a household takes from the grid; but the panels do little for the winter evening peak, and the new tariff charges mainly for that peak.^[23] Parliament passed an emergency law unanimously within weeks, although the regulator and parliament's own legal service warned that it encroached on the regulator's independence.^{[8, 9]} In Sweden, the regulator's 2022 decision gave every grid company until January 2027 to introduce a peak-based charge; in March 2026, less than ten months before that deadline, the government stopped the obligation.^{[10, 24]} Norway postponed its reform by six months in 2021 and later extended the transition phase.^{[11, 25]}

A reform of the tariff structure does not raise what a grid operator collects in total. Its total revenue is capped by the regulator; the reform changes who pays how much.^[26] Public debate in parliaments and the media nevertheless often treated such reforms as a price rise, as in Sweden, and analyses of who would pay more and who less were often not published in advance. When Ellevio returned to its old tariff in June 2026, that brought it no extra revenue either.^[27]

Default or choice, and the risk of new peaks

Most of the countries in this chapter apply the new tariff to everyone: Norway, Denmark, Slovenia, Spain and, from 2029, the Netherlands.^{[3, 13, 15, 18, 20]} A tariff that applies to everyone reaches every household but risks the kind of political backlash described above; an opt-in tariff avoids that risk but, as Chapter 3 shows for other optional schemes, tends to reach only a few per cent of households.

Fixed cheap blocks carry a risk of their own. Because the cheap hours start at the same moment for everyone, devices set to follow them, such as car chargers on a timer, can all switch on together and create a new peak. Research on electric-car charging has found such peaks at the start of cheap periods, and in one Danish neighbourhood with many electric cars, 76% of the moments when the local transformer was loaded beyond its capacity fell in the cheap night window.^{[28, 29]} One answer is to combine fixed cheap hours with a charge on each home's own peak. The peak charge gives every household a reason not to switch everything on at full power at once, while the fixed windows still point to the cheaper hours. Austria's draft rules for 2027 do this: they would charge each home for its highest quarter-hour of the month and, on top of that, keep fixed windows in which the per-kWh charge is lower.^[30]

What this means for Belgium

• Regulators and grid operators could build an evaluation into every new network tariff, with meter data and a survey, as Norway did.^[3] The Flemish capacity tariff has been assessed by Fluvius and by an independent university study; Wallonia's optional time blocks and Brussels' planned tariff could be evaluated in the same way from the start.^{[5, 31, 32, 33, 34]}
• Regulators and grid operators could publish, before a tariff starts, who will pay more and who less, and phase in the change. Slovenia's softened tariff now brings in its winter prices step by step over three winters.
• Regulators designing time blocks could check whether new peaks appear at the start of cheap windows, and consider combining blocks with a peak charge, as Austria plans.^[30]
• Governments may expect pressure when a visible group sees its bill rise, and could prepare for it with a published analysis of who pays more and who less, rather than with emergency changes.

The supplier contract sets the price of the energy itself, a little under half of the average Belgian household price per kWh in 2025; network charges, levies and taxes make up the rest (see Chapter 1).^{[1, 2]} A contract can reward flexible use in four ways: a dynamic price that follows the wholesale market; fixed cheap and expensive time blocks, known as time-of-use; a tariff built for households with one device, such as an electric car or a heat pump, sometimes called type of use; or an ordinary fixed or variable price plus a reward for letting the supplier steer a device. The forms can be combined: most British car tariffs, for instance, are aimed at car owners and also have a cheap night window.^[3]

On its own, a time-varying price rarely changes what households do: where large groups were moved onto such prices by default, in Spain and California, evaluations found little or no response.^{[4, 5]} The contracts that are growing, as in Britain and the Netherlands, are sold around a device, usually an electric car and sometimes a heat pump or home battery, and rely on automatic control of that device, whether the price is fixed or changes every hour. In Britain, car tariffs accounted for nearly nine-tenths of the increase in households on smart time-of-use tariffs between July 2024 and July 2025.^{[6, 7]} Simple price differences, such as fixed cheap hours, matter mainly where people shift their use themselves.

A time-varying price on its own changes little

Since 2015, Spanish households that never choose a supplier offer have stayed on a regulated default tariff whose energy price follows the hourly wholesale market.^{[4, 8]} At the end of 2025, 27.4% of households were on it.^[9] Since 2024, a growing part of its price has been based on electricity bought months ahead, which smooths out the hourly swings.^[8] A study found that households on this tariff reacted to price changes no differently from households on fixed prices.^[4] From 2019, California moved several million households by default to a regulated time-of-use price covering both energy and network costs; at the first utility, about a quarter did not know they had been moved, and measured peak use fell by 1.0 to 1.8%.^{[5, 10, 11, 12, 13]} A chosen contract does not guarantee a response either: in a Dutch survey, only 19% of heat-pump owners with a dynamic contract let the heat pump follow prices automatically.^[14]

When many households pay a price that follows the wholesale market, a sharp price rise can quickly become a political problem, as in Norway and Spain, and governments then step in to protect households.^{[8, 15]} How they do so decides whether households still have a reason to avoid expensive hours. Norway, where nearly all households pay the hourly spot price, first based its support during the 2021-2022 energy crisis on the monthly average price.^[15] That support did not depend on when a household used electricity, so moving use to cheaper hours still paid off. From September 2023 the support was based on each hour's price instead, which largely removed that reason.^[15] Since October 2025 households can also choose a flat state price, and by April 2026 about two-thirds of households in southern Norway had done so.^{[15, 16]} Ireland takes a different approach. Its energy regulator requires the five largest suppliers to offer a dynamic contract that keeps half-hourly prices but caps the part linked to the wholesale price at €0.50 per kWh.^{[17, 18]} From 2021 to 2023, a period that includes the 2022 price crisis, the wholesale price exceeded that level in only 0.6% of trading periods.^[17] The cap is also affordable for suppliers: above that level, Ireland's capacity market already pays them back the difference, so they are largely protected against such price spikes.^[17]

Automatic control does the work, whatever the price

Where flexible use has grown, the response mostly comes from devices that react on their own. The number of British households on smart time-of-use tariffs rose from 497,000 in July 2024 to 835,000 in July 2025; over that year car tariffs grew 84% and other smart tariffs 27%.^[6] In many car tariffs the supplier decides when the car charges: at the end of 2025, over 300,000 British households let their supplier steer a device, and by August 2026 one supplier alone did so for over half a million drivers.^{[3, 19]}

Software that steers a device can follow any price, so the price the household sees does not have to be simple. Dutch dynamic contracts often come with an app that steers a home battery or car on the hourly price; in other offers the household pays a fixed price and the software works in the background.^[20] A British car tariff gives the household one low night rate, while the supplier combines the cars of many customers and uses their flexibility in the electricity markets (see the box on Octopus).^{[21, 22]} A Finnish supplier offers heat-pump owners a cheaper fixed window only as long as its software partner is allowed to steer the heat pump; a large Dutch supplier pays customers on fixed and variable contracts for steering their home battery.^{[23, 24, 25]} Because the device responds without any effort from the household, the reward can be modest: in November 2025, energy in the Finnish contract's cheap window cost about 18% less than at other times of day.^{[26, 27]}

A few companies now sell the device, the steering and the contract together. The British supplier Octopus started from the contract and added the device: it designs and builds its own heat pump and sells it with a heat-pump tariff with cheap windows.^{[28, 29, 30]} The Dutch heat-pump maker Quatt went the other way: it had about 15,000 heat-pump systems running in Dutch homes in 2025 and added a home battery, its own energy management software and a dynamic electricity contract; the software steers the heat pump and the battery on the wholesale price.^{[31, 32]} We found few other companies that sell all three.

Simple prices matter most when people respond themselves

Contracts with simple, easy-to-understand price differences tend to be taken up faster. Simplicity matters mainly where people respond to the price themselves, not where software does it for them. With fixed cheap hours, a household knows in advance which hours are cheap and can set a charging timer or a thermostat schedule once to follow them. A British heat-pump tariff with three cheap windows a day and an expensive one from 4 to 7 pm halved measured evening use in 6,631 homes, averaged over all days, from about 0.9 to 0.45 kW, without raising daily use.^{[30, 33, 34]}

The evidence is thin. For simple tariffs and steering, almost all figures on steered devices, shifted consumption and savings come from the companies themselves, while regulators mainly count how many households are on each type of contract.^{[35, 36]} The only large measured effect comes from a study run by Octopus's own research arm on customers who chose a specific heat-pump tariff.^[33]

Why Flanders is behind the Netherlands and Britain

The share of Flemish households on a dynamic contract is rising fast from a very low base: 0.29% at the start of 2025, 0.89% in December and 1.36% in April 2026, against 8% in the Netherlands in July 2026.^{[35, 37]} Britain leads in device tariffs instead: 2.8% of households were on a smart time-of-use tariff in July 2025, 653,000 of them on a car tariff.^[6]

The examples in this chapter point to three reasons. First, 34 dynamic products were on offer in Flanders at the end of 2025, but in a study of 1,014 Flemish households a dynamic contract brought, on average, neither a clear gain nor a clear loss; for a household without a device to steer, not switching can therefore be a reasonable choice.^{[38, 39]} Second, a Belgian supplier can offer a discount only on the energy part of the price, while a British supplier sets one all-in price per kWh, network costs included: in Britain the supplier pays the network charges itself and is free to fold them into the price it sets.^{[40, 41, 42]} At night, the leading British car tariff charges 71% less than the capped standard rate; the reward of 1.5 euro cents per smart-charged kWh that two Belgian suppliers pay is about 4% of the price per kWh in a fixed contract in October 2026, before the capacity charge and fixed fees.^{[21, 42, 43, 44, 45, 46, 47]} Third, the suppliers that drove growth abroad sell the price together with software that does the steering: newer Dutch suppliers that pass on the wholesale price at cost for a fixed monthly fee, with an app that steers a battery or car, and British suppliers such as Octopus that run their own steering platform.^{[19, 20, 22, 48, 49]} Such suppliers have only a small Belgian market share, and two large Belgian suppliers chose fixed time blocks instead.^{[40, 41, 50, 51]} Dutch households also have a specific reason to look at such offers now: net metering, which lets solar-panel owners offset the electricity they feed into the grid against what they take from it, ends on 1 January 2027.^{[20, 52]}

What this means for Belgium

• Suppliers could make steering itself the product: a low fixed price or a cheap window in return for permission to steer the car, battery or heat pump, building on today's smart-charging rewards.^{[43, 44, 45]} Under the Flemish capacity tariff, such steering may also need to limit charging power, so that it does not raise the household's monthly peak.^[53]
• Manufacturers and installers could make price-following control standard and, when they install a heat pump, set a schedule for fixed cheap windows.
• Regulators could extend the monthly count of fixed, variable and dynamic contracts to time-of-use and steering contracts, and support studies of how newer types of contract affect actual consumption profiles.^[36] Their price comparison tools, such as the Flemish V-test, could likewise include time-of-use contracts.^[54]
• Governments and regulators may expect little from moving households onto hourly prices by default. Before the Flemish duty to offer a dynamic contract reaches all suppliers in 2029, they could design crisis protection that still gives households a reason to avoid expensive hours, such as support based on the monthly average price, or a cap like Ireland's.^{[17, 55]}

Peak events are short periods, announced in advance, when electricity is scarce or the grid is close to its limit. Several countries pay households to cut their use during such events, which makes these schemes a direct test of how much a home can deliver when flexibility matters most. They take different forms: Britain's system operator pays households through their suppliers, North American utilities pay bill credits or a fee per device, and a Californian state agency pays aggregators for home batteries.^{[1, 2, 3, 4, 5]} France uses the price instead: households on its regulated tariff can choose a variant in which electricity in peak hours costs over four times as much on 22 'red' winter days.^{[6, 7]}

What a household delivers depends above all on who responds during an event: the household itself or a device. Where a person has to act, the effect measured against a control group in Britain and California is about 0.01 to 0.25 kW per household per event; where a device acts automatically, it is about 1 to 5 kW (Figure 3.1).^{[3, 4, 8, 9, 10, 11, 12]} In California, signing up about four million households automatically, without asking them, added many participants but little response, because they still had to act themselves.^{[2, 9]} Schemes also differ in how they measure what a home delivered and in what they pay for it. Some are now ending as their budgets run out; others are taking on new roles.^{[2, 13, 14]}

Who acts matters more than who is enrolled

Québec offers the clearest comparison: most homes there heat with electricity, and one utility runs both kinds of scheme in the same winters (Figure 3.1).^[3] Households on a peak-event rate or bill credit, who must act themselves, cut about 0.8 kW per event; households whose thermostat turns the heating down automatically cut about 2.9 kW.^{[3, 15]} In a field experiment at a Canadian utility, households with automatic control cut about five times more than those that had to act themselves, and a smart device without automation did not help: those households cut no more than households acting by hand.^[16] Devices, climates and measurement methods differ between countries, so the exact figures differ too, but every comparison in this chapter points the same way.

Signing households up automatically is no substitute for automatic response. California signed up about four million households automatically for a scheme that paid $2 for every kWh they saved at peak times.^{[2, 9]} At the largest participating utility they cut about 0.03 kW each, no more than they already cut in response to the state's public appeals to save electricity, while customers who had signed up themselves cut about eight times more.^{[9, 17]} Schemes that people must join themselves deliver more per home but tend to reach few homes: about 9% of customers at an Arizona utility signed up their thermostat, and about 5% of French households on the regulated tariff chose its red-day variant.^{[4, 18, 19, 20]} Offers can reach many more homes when a steered device comes with an electricity contract that customers choose anyway. A Texan supplier, for example, installs a free thermostat with certain electricity plans, and 70–80% of customers take part when the device is free and steering is part of the plan.^{[21, 22]}

How delivery is measured decides what is paid for

Britain and California paid households for each kWh they saved, measured against a baseline: an estimate of what each home would normally have used.^{[8, 9]} Because a household's use goes up and down from day to day anyway, such a baseline can reward these ordinary ups and downs as if they were effort. In 2022 the largest Californian utility paid out more than $55 million in bill credits, mostly for chance dips below the estimate.^{[9, 23]} Home batteries avoid this problem, because a battery's own meter records exactly what it discharged. New England's utilities pay battery owners per kW of average discharge over all events of a summer, and count a missed event as zero.^[24] For thermostats, heat pumps and whole homes, which have no such meter of their own, the most reliable way to know what was delivered is to compare participants with a similar group of households that did not take part, a so-called control group.

The price matters as much as the measurement. When Britain replaced the high fixed payment of its first two winters with competitive bids from suppliers and aggregators, the average accepted price fell from £3.10 to £0.21 per kWh, although each event then delivered less, about 89 MWh instead of 235 MWh.^{[8, 25, 26]}

What a kW is worth depends on what it must deliver

Schemes pay between about €17 and €350 per kW per year (Figure 3.2).^[27] The gap is less surprising than it looks, because 'a kW' means something different in each scheme. Arizona's thermostats earn about €17 per kW a year for six or seven short events on the hottest afternoons of a summer.^{[4, 28, 29]} New England pays battery owners €195–350 per kW each summer for up to 60 events of two to three hours, measured on the battery, with a missed event counted as zero.^{[24, 28, 30]} The more often, the longer and the more reliably a kW must be delivered, the more a scheme tends to pay for it. For comparison, Belgium's capacity auctions of 2025 paid on average about €14 to €27 per derated kW per year, mostly to power plants, battery parks and industrial demand response.^{[31, 32]}

What households earn follows the same logic. People who must act themselves earn little: well under £1 per event in Britain in 2023-24, and €16–39 over a winter on Québec's bill credit.^{[3, 8, 28, 33]} A Massachusetts home whose battery took part earned about €900 for summer 2025.^{[11, 28, 34]} France's red-day variant works differently, because it is a tariff rather than a reward: in the 352 peak hours of the red days, electricity costs €0.56 per kWh more than on ordinary blue days, while on most other days it is cheaper than the standard regulated price.^{[6, 35]} It therefore tends to attract households that expect to manage on red days, for example by turning electric heating down or switching to another heat source.^[6]

Peak events keep a role for rare moments of scarcity

Do separate peak-event schemes still make sense once devices can easily follow hourly prices all year round? Several signs suggest that their role is changing, and in places shrinking. Britain's scheme has become a year-round balancing tool: it also pays people to use more electricity when there is a surplus, and from October 2026 it helps where the grid is congested.^[14] In France, the 22 red days are a fixed quota for each winter, and in 2025-26 they no longer matched the days when electricity was really scarce: by the end of February only 9 had been used, so the remaining 13 fell in a mild March.^[18] Budgets also run out: California stopped its household rewards after 2025, and its battery programme is expected to run out of money by the end of 2026.^{[2, 13]} Yet peak events still have a role where they deliver something that prices alone do not. In California's 2025 battery test, an independent analysis found that most of the 535 MW came on top of what the batteries would have done anyway: batteries that simply follow their owner's consumption or a time-of-use price would not have sent power to the grid at the hour when it was most needed.^[10] And Octopus Energy's research arm estimated that, at the high prices of the early winters, each £1 spent on Britain's scheme was worth only about £0.63 if the saved electricity is valued at what the system operator would otherwise have paid for balancing, but about £3 if each saved kWh is counted as a blackout avoided.^[8]

Peak events are therefore best seen as a form of insurance for the rare moments when electricity is really scarce. Everyday flexibility comes from network tariffs and supplier contracts (see Chapters 1 and 2). Where countries keep peak events, the examples in this chapter point to three design features: a device responds on its own, payment is based on what that device measurably delivered, and, to reach many homes, steering is switched on from the start, with an easy way for the household to override it. Automatic control already works at scale where a law or a grid operator required it, as for French water heaters (see Chapter 5), or where a supplier sold it in a simple contract, as to more than 500,000 British car owners (see Chapter 2).^{[36, 37]}

What this means for Belgium

• The federal regulator and Elia could publish each year, in aggregate and within the confidentiality rules of the capacity mechanism, how much of the contracted capacity comes from household devices, and Elia and the federal government could consider using household devices, such as home batteries, as emergency capacity. Flanders alone had about 189,000 registered home batteries in September 2026, more than the number of batteries California discharged together in its 2025 test.^{[10, 38, 39]} There is no public information that home batteries take part in Belgium's capacity mechanism, whose contracted volume comes mostly from power plants, battery parks and industrial demand response.^[31]
• Elia and the regulators, if they design a peak-event product, could pay per kW measured on the device, use competitive bids from the start, and require a control group wherever a household baseline cannot be avoided.
• Suppliers and aggregators could sell thermostats and other devices together with the service that steers them, switched on by default in a contract the customer chooses, with clear terms at signing and an easy way to override the steering.
• Regulators offering an optional tariff, such as Wallonia's network tariff with five time blocks, face a trade-off.^[40] A tariff that households must choose themselves imposes nothing on anyone, but abroad such tariffs and schemes reached between a few per cent and a tenth of customers, and their effect was small where people had to respond by hand.^{[4, 18, 19, 41]}

When a cable or substation of the local grid is close to its limit at busy times, the grid is said to be congested. The grid operator can then reinforce the grid, or it can buy flexibility: pay customers to use less electricity at the busiest moments, so that reinforcement can wait. That matters for households: heat pumps and electric-car chargers add to the evening peak on local grids, but like home batteries they can shift their use by an hour or two, and grid operators can pay for that flexibility.

Britain has done this for years and at scale.^[1] Every British distribution grid operator buys flexibility in tenders and auctions, and together they had about 9 GW under contract in 2024.^[2] Households supply a growing share: 23% of the flexible capacity at the largest local market, in London and the South East, in 2024/25.^[3] Elsewhere, buying flexibility from households is still at the trial stage or has only just begun, so this chapter looks mainly at Britain. There, far more is contracted than used, and what a household kilowatt earns depends on how the grid operator pays. Under the shared British method, flexibility is worth buying only while it costs less each year than what postponing reinforcement saves, so flexibility buys time before reinforcement rather than replacing it.^[4] Heat pumps can help at short winter peaks, but how much they can help in a freeze lasting several days has not been measured.^{[5, 6]}

Capacity under contract is far larger than the flexibility used

British grid operators report how many gigawatts of flexibility they have bought. Most of that is capacity under contract rather than flexibility actually used: about 9 GW was under contract in 2024, but only 22 GWh was called upon that year, the equivalent of using the contracted capacity at full power for about two and a half hours in the whole year.^{[2, 7]} In 2021/22, about three quarters of the volume tendered was for services that are called upon only after a fault on the grid.^{[1, 8]}

We found few reports that show four figures separately: the capacity under contract, the energy actually used, the price paid per kW and the share that comes from households. The national British figures do not show what households supply.^[2] The operators that do publish it count it differently, as a share of capacity or of new registrations, and prices are stated per MWh or per MW per hour rather than per kW per year, which makes them hard to compare with other schemes.^{[3, 9, 10]}

What a household kilowatt earns depends on how the grid operator pays

British operators pay mostly per MWh delivered when called upon, sometimes with a small fee for standing by, at prices set in tenders and auctions.^{[9, 10]} Averaged over all operators and products, a kilowatt was forecast to earn about £33 (€38) a year in 2023-24, paid to the aggregator or supplier, which keeps a share before anything reaches the household.^{[11, 12, 13]}

The Netherlands, where three grid operators start buying household flexibility in November 2026, chose a simpler design: a fixed, published price paid for being available rather than per use.^{[14, 15, 16]} It is €60 per kW per year for devices that can hold back for two hours, €90 for four hours and €120 for six (Figure 4.1).^[16] For comparison, Belgium's capacity auctions in 2025 paid on average about €14 to €27 per derated kW per year, mostly to power plants, battery parks and industrial demand response.^{[17, 18]} Recruiting households through suppliers and aggregators proved slow, though: a first, smaller phase, open to about 35,000 households, had drawn about 2,200 car chargers, 85 home batteries and 500 hybrid heat pumps by January 2026.^{[19, 20]}

Flexibility is worth what postponing reinforcement saves

Regulators often let grid operators earn a return on the cables and substations they own, but not on the services they buy from others.^{[21, 22]} That gives operators a reason to build rather than buy flexibility services. Ofgem, the British energy regulator, weakens that bias by assessing both kinds of spending together, as one total.^[23] It also makes every operator publish where and why it buys flexibility, using one shared method to compare it with reinforcement.^{[4, 24]} Postponing a reinforcement by a year does not avoid its cost; it mainly saves the cost of tying up the capital for that year.^[4] Under the shared method, flexibility is therefore worth buying only while it costs less each year than that saving, which puts the ceiling well below the cost of the reinforcement itself.^[4]

In other words, flexibility mainly buys time. It can be most valuable where it is still unclear whether reinforcement will be needed at all, because waiting then avoids building grid capacity that may never be used. From 2028, Ofgem expects operators to weigh flexibility before committing to reinforcement, and will fund reinforcement whose need is less certain only once that need is confirmed.^[23]

Households join through aggregators, and Britain is making their devices easier to register

A typical home offers only a few kilowatts, less than the minimum offer of 10 kW or more per location that British grid operators ask, so aggregators and suppliers pool many homes into one offer.^[10] That route works: at one operator, 99% of new registrations in summer 2025 were household devices, mostly car chargers and heat pumps.^[9]

So far, each British flexibility market has had its own sign-up, so an aggregator that offers a heat pump to both its local grid operator and the national system operator registers it twice.^[25] From 2027, a shared register is due to let an aggregator sign a device up once for both local and national markets.^{[25, 26]} That matters most for households, because each home adds only a few kilowatts and every sign-up cost weighs on what it earns.

Heat pumps help at short winter peaks; a long freeze has not been measured

Over three winters, a British grid operator paid more than 1,000 heat pump households to turn their heating down in two-hour peak events on winter evenings.^{[5, 27]} The measured response grew as it got colder, from 0.4 kW per participating home above 7°C to 1.1 kW below 3°C, and 85% noticed no change in comfort or only a slight one, even in the coldest events.^[5] On an average event, 47% of participants turned their heating down.^[5] The trial never observed a severe winter, and a separate modelling study suggests that flexibility would barely reduce the network peak in a once-in-twenty-years winter (see the box 'Heat pumps in a long cold spell').^{[6, 27]} Heat pumps can thus be counted on for short peaks on cold evenings, but not yet for a freeze lasting several days, which is what determines how much grid capacity is needed.

What this means for Belgium

• Regulators and grid operators could report contracted capacity, energy used, price per kW and the household share separately. The Flemish regulator already reports the energy delivered in Fluvius's test market.^[28]
• Regulators in all three regions could ask grid operators to publish, for each congested part of the grid and with one shared method, the price up to which flexibility is cheaper than reinforcement: the yearly value of postponing the investment.
• Grid operators that want household flexibility could consider, alongside auctions such as those in Fluvius's test market, a published price per kW per year for being available, offered through suppliers and aggregators, and plan recruitment from the start.
• Grid operators and Elia already share FlexHub, which records which provider serves which connection for the services Elia buys and which they describe as the embryo of a Belgian flexibility information system.^{[29, 30, 31]} They plan to open FlexHub to several requesting parties and all flexibility products^{[31, 32]}, congestion services included; completing that step could let a household sign a device up once and change provider much as it changes supplier.
• Grid operators and Elia could count on heat pump turn-downs for short evening peaks on cold days, as long as they allow for the fact that only some households take part in each peak event. For a freeze lasting several days, the quarter-hourly meter data that Fluvius has read as standard since 2026 could show how large the heat pump peak is.^[33]

Much household flexibility is organised one household at a time, through a contract with a supplier or aggregator. A law, a network tariff or a product rule can instead make appliances steerable in bulk. Some countries use such rules; others leave flexibility to contracts. The choice reflects different views of how far public rules should reach into people's homes, and may well follow political dividing lines. The examples in this chapter differ on three questions: who holds the switch, what happens by default, and whether the household can opt out and is paid for taking part (Figure 5.1).

Such rules work at scale where they can build on infrastructure that already exists. France is moving part of the cheap hours of more than 11 million households from the night to the afternoon by regulatory decision, and water heaters wired to a switch in the smart meter follow automatically.^{[1, 2]} Since 2024, German grid operators can dim new heat pumps, home chargers and home batteries during moments of grid stress, but the smart meters needed to do this remotely are still largely missing.^{[3, 4]} Britain has made every new home charger avoid the peak by default since 2022.^[5] Much of the older central control was set up to run appliances at night, when electricity used to be cheapest; with rooftop solar, the middle of the day is now often the cheapest time, so that control stays useful only if its hours move with it.^{[1, 6]} And when many appliances respond to the same signal at the same moment, they risk creating a new peak, which is why the countries that switch centrally spread the moment at which appliances switch on.^{[7, 8]} How much flexibility these rules actually deliver has rarely been measured.

Most rules come with a payment or a way out

Even where devices must be steerable, the requirement rarely stands alone. German grid operators can turn down any new heat pump, home charger or home battery above 4.2 kW when the local grid is close to its limit, but never below that level, and households cannot opt out.^[3] In return, the grid operator can no longer refuse or delay the connection, and the household pays €110 to €190 a year less in network charges.^[3] Switzerland is moving from imposed to paid control: under a law approved by referendum in 2024, the grid operator can use a household's flexibility only with the household's consent and against a published payment, except to avert a serious threat to the grid.^{[9, 10, 11]} Where nothing is paid, there is a way out. Every new British home charger leaves the factory set to charge outside the weekday peaks, but the owner can override those hours at any time.^[5]

Rules scale where the wiring is already there

France can re-time millions of water heaters with one regulatory decision because three things were in place: the cheap off-peak hours sit in a single national network tariff, one grid operator runs 95% of the distribution network, and about 7.8 million water heaters are wired to a switch in the smart meter that turns them on when those hours begin.^{[1, 12, 13]} The speed has a cost: households are informed rather than asked, and those whose water heater runs on its own timer must reset it or risk heating at peak prices.^{[1, 14]} Germany shows the reverse: by mid-2026 only 5.9% of its metering points had the smart meter that remote dimming depends on.^[4]

Control designed for the night must move to midday, or it is lost

Many of these central control systems are decades old.^{[6, 15]} They were set up to run water heaters and storage heaters at night, when demand was low and electricity was cheapest, and the cheap hours in tariffs were placed at night for the same reason.^{[1, 6, 8]} Since then, rooftop solar has changed the daily pattern: on sunny days there is often more electricity around midday than the grid needs, and the middle of the day has become the cheapest time in many countries (see Chapter 6).^{[1, 16]} Control that still switches appliances on at night therefore misses the hours in which their flexibility is now worth most. Where the control is re-timed, it stays useful. France now lets up to three of its eight off-peak hours move to between 11 am and 5 pm, and Australian grid operators are moving the windows of separately metered water-heater circuits into solar hours.^{[1, 6, 17]}

Where control no longer fits the system, it is abandoned. In Switzerland, Winterthur's municipal utility will switch off its control signal at the end of 2027 because running the system is no longer economic.^{[18, 19]} In Australia, many solar owners have taken their water heater off the controlled circuit to run it on their own panels, often on their installer's advice: a 2023 assessment found 20–25% of the controlled load in South Australia inactive or disconnected, and about one in three solar installers in Queensland advising customers to make that change.^{[6, 16]} Whether flexibility is kept or lost is decided at installation as much as in the choice of contract.

A common signal needs a staggered start

When many devices respond to the same signal at once, they risk creating a new peak. Britain added its charger rules after a trial observed a surge in demand at 10 pm, when many drivers had set charging to start when a cheaper period began; every new home charger must now start each charge after a random delay of up to ten minutes.^{[7, 20]} Finnish grid operators switch on night-time loads in stages over at least an hour, as the national transmission system operator advised.^[8] Fixed time blocks in network tariffs or supplier contracts can carry the same risk (see Chapters 1 and 2).

Measured effects are scarce

Only one rule in this chapter has a measured effect at system level: Dutch grid operators have public chargers in congested areas turned down on weekday evenings by default.^[21] In Utrecht province, with 3,500 such charge points, this cut the 7 pm charging load to about half its expected level by late February 2026: 5.8 MW instead of 11.5 MW (Figure 5.2).^{[22, 23]} Two smaller tests also measured a shift. In a supplier's test with 237 French homes, water-heater use at 7 pm fell by 20%, about 0.3 kW per home, and in an Australian grid operator's trial an average 28% of daily water-heating load moved into solar hours.^{[13, 17]} For Germany's dimming, France's re-timed hours and Britain's charger defaults, no measured result has been published; for France there is only the grid operator's forecast that about 5 GW of consumption will move to the afternoon in the sunniest months.^{[2, 24]}

What this means for Belgium

• Governments and regulators that want a safety net under Belgium's market-based approach could study Germany's package: a right to dim large new appliances with a guaranteed minimum, a guaranteed connection, a lower network charge and published interventions.^{[3, 25]} Such a rule may be easier to introduce before congestion becomes widespread.
• Governments could attach default behaviour to future incentives for devices. Belgium's federal tax reduction for home chargers from 2021 to 2024 required a charger that could be steered, but no default behaviour; Britain built default off-peak hours and a random start delay into every new charger, at an estimated £40 (€47) of extra manufacturing cost per device.^{[5, 20, 26, 27, 28]} For heat pumps, regional premiums could likewise require domestic hot water to be heated in the middle of the day, when solar power is plentiful.
• Regulators and grid operators in Flanders, Brussels and Wallonia could follow what replaces the exclusive-night circuits, which have lost or are losing their tariff advantage in all three regions: whether their appliances move to the solar hours, stay at night on a clock, or are no longer steered at all.^{[29, 30, 31, 32, 33, 34, 35, 36, 37, 38]} Switzerland shows that a working central channel can disappear before a market replacement exists.^[19]
• Regulators, suppliers and aggregators that design the time blocks now appearing in Belgian network tariffs and supplier contracts could build in a staggered start from the outset, as Britain does per device and Finland per group of customers.^{[7, 8, 39, 40, 41, 42]} Flemish and Walloon exclusive-night circuits are already switched on at different moments.^{[35, 43]}
• Manufacturers and installers often decide whether a heat pump, water heater or charger stays steerable. Flexibility policy in all three regions could involve them from the start, as Flanders does in its public catalogue of energy managers, which the electrical sector's knowledge centre helps run.^[44] They could also set new heat pumps to heat domestic hot water in the solar hours by default.

Household solar panels produce most around midday, when demand is often low. Where many are installed, sunny middays can bring more power than the electricity system can use: wholesale prices turn negative, meaning that producers pay to sell their power, and local grids reach their limits. Households can respond in two ways: batteries, electric cars and heat pumps can shift their use into those hours, and solar inverters can turn their output down. Germany and the Netherlands had negative wholesale prices in more than 570 hours in 2025, and Belgium in only slightly fewer (Figure 6.1).^{[1, 2, 3]} This chapter draws heavily on Australia, where the surplus is already much larger and states have been setting rules for household solar since 2020.^[4] In the last quarter of 2025, prices in South Australia were negative in 48% of all five-minute intervals, and at one point rooftop panels produced more than the whole state was using: the demand that the state's grid had to supply fell to a record minus 263 MW.^[5]

Countries have found four ways to deal with the midday surplus. Three act directly on the inverter: a fixed cap on how much of its capacity a new system is allowed to export (Germany), a variable export limit that the grid operator lowers only when the local grid is close to its limit (South Australia), and an emergency switch that the system operator can use as a last resort (several Australian states).^{[4, 6, 7, 8, 9]} The fourth works through prices that make midday exports worth less, as in Germany, Australia and the Netherlands.^{[6, 10, 11]} The limits and switches are built into new installations rather than imposed on existing ones, and when designed well they cost households little. For price signals aimed at households' midday exports, no effect has been measured so far: every measured effect on household exports in this chapter comes from direct control of inverters.^{[12, 13]}

Existing owners keep what they counted on

Germany's rules cover only new rooftop systems. Since February 2025, a new system is allowed to export at most 60% of its capacity until a smart meter and a control box let the grid operator turn it down.^[6] Once that hardware is in place, the system gets no feed-in payment when the wholesale price is negative, and the lost hours are added to the end of its 20-year support period.^[6] Existing owners can opt in, in return for a slightly higher feed-in tariff.^[6] South Australia's variable limit and emergency switch likewise apply only to new and replaced inverters, so nobody loses what they already had.^{[4, 14]} In the Netherlands, a change does reach existing owners, but with two years' notice. Under net metering, every kWh a household exports is subtracted from the kWh it buys, so its exports are in effect paid at the full retail price.^[11] Net metering ends on 1 January 2027; until 2030, suppliers must then pay at least half of their own electricity price, before taxes, for exported power.^[11]

Well designed, the limits cost households little

South Australia has used its emergency switch once since 2020, for about an hour, and Western Australia puts the cost of one activation at $1–2 (about €0.60–1.20) per household.^{[4, 8, 15, 16]} In the trial of South Australia's variable export limit, the limit stood at its maximum of 10 kW for 99.4% of the time, so exports had to be restricted in only a few hours.^[13] The German rule on negative prices costs more: on 2024 prices, a typical new system with a battery loses about €130 a year, a quarter of its feed-in income.^{[17, 18]} A battery that starts charging first thing in the morning can be full before midday, when negative prices are most common; a battery that waits and charges at the midday solar peak recovers almost all of that loss, so the cost falls mainly on systems that do not respond to prices.^[17]

One capability, used voluntarily or in an emergency

In South Australia, the variable export limit became the norm once the state required every new inverter to be able to receive it.^{[13, 14]} During the trial, about a third of new solar customers chose the variable limit; after the requirement, nearly nine in ten did.^{[13, 19]} The same inverters must also be able to be switched off in an emergency, a requirement since 2020, and the emergency signal can travel through the network operator's flexible-export system, so the same equipment serves both.^[4] Voluntary curtailment and a forced switch-off are technically the same action, an inverter turning down its output on an external signal; what separates them is who decides. The more households curtail voluntarily, the less often an emergency switch would be needed.

No measured effect from price signals

Germany has published no estimate of how much midday feed-in its rule on negative prices removed, and its negative-price hours rose from 457 in 2024 to 573 in 2025.^[1] In Australia, network operators in Sydney and South Australia charge a little for midday exports, and in Sydney the network operator also pays a little for evening ones.^{[10, 20]} The charge is deliberately small, an estimated €11 a year for an average South Australian household, and it is billed to the supplier, so it reaches households only as far as suppliers pass it on.^{[10, 15, 20, 21]} Since July 2026, a federal rule has also required suppliers in three Australian states to offer a contract with three free midday hours, and Victoria started a similar scheme of its own on 1 October 2026; no figures have yet been published on how much consumption these hours shift.^{[22, 23, 24]}

What this means for Belgium

• The federal government and Elia could look to Australia's design if they pursue an emergency switch for rooftop solar: new and replaced inverters only, so that existing owners keep the terms they invested under; households only after the large wind and solar farms that Elia can already curtail; and one announced test a year.^{[4, 25, 26]}
• Governments and grid operators could require every new inverter to be able to receive an external export limit through an open communication standard, so that the same equipment serves voluntary curtailment, a variable export limit and, if ever needed, an emergency switch.
• Distribution grid operators in all three regions, if they extend flexible connections to households, could make a variable export limit the attractive alternative to a low fixed cap. The Flemish framework for flexible connections, adopted in December 2025, is so far only used for larger connections.^{[27, 28]}
• Regulators could ask suppliers to report how much consumption their midday offers shift and how much solar output their curtailment services turn down. If export payments keep falling, as the best offer in Brussels did by almost 30% in 2025, a minimum payment for exported power and export charges limited to real costs, as in the Netherlands, could be options to consider.^{[11, 29]}

Home batteries, heat pumps and electric-car chargers can create value in three places. Behind the meter, they lower the household's own bill by shifting its use to cheaper hours or storing its solar power. Locally, they can relieve a congested distribution grid (see Chapter 4). On national markets, a supplier or an independent aggregator pools many devices and sells their flexibility on the wholesale market or as reserves, capacity that the transmission system operator keeps on standby to balance supply and demand. Many offers for households also steer devices in real time against the imbalance price, the price at which the transmission system operator settles the remaining differences between supply and demand.^[1] What these national markets pay, and how reliably, shapes which offers suppliers and aggregators can build around household devices; this chapter weighs that income against the value behind the meter.

Opening these markets to households has proved easier on paper than in practice. Five years after the United States ordered its wholesale markets to accept pooled home devices, those devices supplied only tens of megawatts.^[2] The American experience suggests that volume follows only once metering, the role of the local grid operator and the settlement with the household's supplier work in practice for small devices.^[2] Where households do get in, the income can shrink quickly. Reserve markets are small by design: the transmission system operator buys only as much reserve as it needs to keep supply and demand in balance, so a few hundred megawatts of batteries can fill one. In Sweden, batteries rushed in when reserve prices were exceptionally high around 2022, and within three years those prices fell by 80 to 90%.^{[3, 4]} Imbalance prices largely follow what it costs to activate those reserves, so earnings from steering devices against them can shrink in the same way, as a Dutch supplier found.^{[1, 5]} In Germany and Australia, most home batteries simply store the household's own solar power for the evening. That alone can lower the evening peak on sunny days, and any income from the national markets comes on top of it as a volatile extra. Offers that require fitting equipment in hundreds of thousands of homes are hard to finance on such income; in France, a payment guaranteed for ten years made such an offer possible.^[6]

Permission alone produced little volume

In 2020 the American federal energy regulator ordered the regional wholesale markets to accept pooled home devices such as batteries and car chargers.^[2] By early 2025 only two of the six markets had fully implemented the order, and volumes were small: 20 MW from about 5,000 home solar-and-battery systems in New England.^[2] A study by Lawrence Berkeley National Laboratory, one of the US government's national research laboratories, pointed to practical hurdles: rules meant to stop a device from being paid twice, by a utility programme and by the wholesale market; the local utility's right to review each registration, which in practice works as a veto; and metering that is costly relative to what a small device earns.^[2]

Who pays the supplier decides who keeps the value

A supplier buys electricity in advance for what it expects its customers to use. When an independent aggregator, a company other than the household's supplier, discharges a household's battery to sell that flexibility on the market, the household takes less power from the grid than its supplier bought for it; when the aggregator turns up a heat pump, the household takes more. Someone has to settle that difference with the supplier, and who pays, and at what price, shapes the business case of every independent aggregator.

Since November 2024, Britain has let independent aggregators sell households' flexibility on the wholesale market without the supplier's consent.^[7] The supplier is compensated at a regulated price from a pot shared by all suppliers, and so in the end by all bill payers.^[7] That made entry cheap for aggregators, but large generators, for which the route was never intended, used it too: about £19 million was paid out of the pot in six months, and in August 2026 Ofgem, the British energy regulator, closed the route to generators above 10 MW.^{[8, 9, 10]} Britain is now assessing direct payment by the aggregator, which would protect suppliers but cut into aggregators' margins.^[11]

Reserve markets are small and fill up fast

Reserves come in several products, which differ mainly in how fast they must respond, and for each product the transmission system operator buys only as much as it needs to keep supply and demand in balance, sized for some products on the largest sudden outage: in Sweden, a few hundred megawatts per product.^[3] When reserve prices were exceptionally high around 2022, battery parks and pooled home batteries rushed in.^[3] By late 2025 the capacity approved to provide these reserves was seven to nine times what the Swedish operator buys, and the price of its main reserve against sudden disturbances had fallen from roughly €120 to €20 per MW per hour (see Figure 7.1; for comparison, Belgian prices for frequency containment and automatic reserves fell by 60 to 72% between 2024 and 2025).^{[3, 12, 13, 14]}

For the companies that pool home batteries, a market that fills up means less income per battery. The home batteries of a Swedish aggregator, some 15,000 of them, earned more than a third less per kilowatt in 2024 than in earlier years.^{[15, 16, 17]} The aggregator expanded into Finland, where in the first half of 2025 a home battery that combined reserves with charging and discharging on hourly price differences earned about four times as much as one used only to store its owner's solar power.^{[18, 19]} A Dutch supplier steered its customers' home batteries in real time against the imbalance price, which settles real-time differences between supply and demand; earnings per battery peaked in August 2024 and then fell, as fast-growing flexible capacity competed for a small market.^[5] The supplier then added frequency reserves, day-ahead and intraday trading.^[1] Both companies responded by combining several sources of income for the same batteries.

Batteries that serve their own household can already help the system

Where home batteries are most common, most of them simply serve their own household: they store rooftop solar power during the day and release it in the evening. Germany has about two million, or 48 per 1,000 households (for comparison, Flanders has about 63; see Figure 7.2), and nearly all are used in this way.^{[20, 21, 22, 23, 24, 25]} Grid electricity is heavily taxed in Germany, so buying less of it is the main way a battery pays for itself. In Australia, only one in ten to one in four battery owners has joined a virtual power plant, yet the market operator measured that battery homes drew on average 0.7 kW less from the grid at the evening peak than comparable solar-only homes, almost three quarters less.^{[26, 27, 28]} The evening, when these batteries release their stored solar power, is also when demand on the system is highest. The effect depends on a sunny day before the peak. On cold winter evenings, when the system is under most pressure and there is little solar power to store, a battery helps only if it charges from the grid in cheaper hours beforehand. A battery that follows a dynamic contract does this on its own, without an aggregator; one that only stores its household's solar power, as most do today, does not.^{[20, 28]}

A long, predictable payment can finance equipment in many homes

A French aggregator fits free control boxes on households' electric radiators and water heaters and switches them off for short periods when the power system is under strain.^{[6, 29]} In 2022 it won 721 MW in a government tender for demand response, with payments guaranteed for ten years, and committed to equipping 450,000 homes; households keep whatever they save on their own bill.^{[6, 30]} Because the payment is guaranteed for so long, the company can finance one standard box and its installation in hundreds of thousands of homes; reserve markets that fill up quickly do not offer that kind of certainty.^[6] Household devices can be steered in two main ways: through an extra control box fitted in the home, or through the manufacturer's own online platform (cloud-to-cloud), which needs no home visit. The French case suggests that the choice between them may depend less on the technology than on how secure the income is.

The first commercial offers for vehicle-to-grid, in which an electric car also feeds power from its battery back to the grid, likewise turn uncertain market income into a predictable reward for the household.^{[31, 32, 33]} They combine a bidirectional charger and an electricity contract for one car maker's models (in Britain together with a leased car), offer free home charging or a fixed payment for each hour the car is plugged in (24 cents in Germany, up to €720 a year), and leave the market risk with the company (see the box on vehicle-to-grid below).^{[31, 32, 33, 34, 35]}

What this means for Belgium

• Suppliers and aggregators, some of which already steer customers' home batteries in Belgium, such as Trevion and Bolt with the aggregator Powernaut, and Frank Energie, could base home-battery offers on several sources of income, with the savings behind the meter as the foundation.^{[36, 37, 38]} They could present reserve and imbalance income as volatile rather than as a promised payback, and show what their steering adds to a battery that already makes the most of the price signals the household is directly exposed to.
• Governments and regulators may find that giving households a sensible price signal matters more than requiring household devices to be pooled for national reserve markets. Belgium's power system is under most pressure on cold winter evenings, when there is little solar power to store, and a home battery helps then only if it charges from the grid in cheaper hours beforehand, which a battery that follows a dynamic contract does on its own, without an aggregator. Belgian rules already make the aggregator pay the supplier directly, the approach Britain is now assessing; now that these settlement rules also apply to low-voltage connections for Elia's reserves, workable metering and that settlement may well decide how much household volume follows.^{[11, 39, 40, 41, 42]} There is no public information that home batteries take part in the capacity remuneration mechanism, which already pays for available capacity; it may be worth understanding why before designing a separate long-term payment for them.^[43]
• Distribution grid operators may find household devices available, and possibly cheaper, for local congestion management as national reserve markets fill up; large batteries connected to the transmission grid cannot relieve congestion on the local grid (see Chapter 4).
• Governments, regulators and grid operators that see potential in vehicle-to-grid may want to look at how Belgian tariffs treat electricity that passes through a car battery. Households pay no network tariff, levies or VAT on what they export, but pay them in full on what they draw to charge the car, also on the part they later feed back; since 2026, Germany charges grid fees only once on electricity that is stored and fed back.^{[44, 45, 46]} Shared and fleet cars, which park at known charging points, may be a practical place to gain first experience, as in Utrecht.^{[47, 48]}

A supplier can reward a household for using electricity at cheaper hours only if a meter records when it was used and those values reach the supplier. A heat pump or car charger can follow a price only if it can read that price. Likewise, a home energy manager, the box or app that coordinates a household's devices, can steer devices of different brands only if they share a common communication protocol. This chapter is about that groundwork: meter data, machine-readable prices and common protocols for devices.

In most countries in this report the meter itself is no longer the bottleneck: smart meters are close to universal in the Nordic countries and Austria, and 96% of French homes have one (see Figure 8.1).^{[1, 2, 3, 4, 5]} What differs is whether data, prices and control signals flow by default. Britain is changing how suppliers are charged for their customers' electricity: every meter is moving to settlement on measured half-hourly use, so that a supplier gains when its customers shift their use to cheaper hours, whatever contract it sells them.^{[6, 7]} California publishes every time-varying rate in one public database that devices can read, and the Dutch grid operators have proposed a short list of five protocols that a home energy manager should speak.^{[8, 9, 10, 11]} Germany shows what can happen when the meter itself is made very demanding: ten years after it chose a heavily certified design, only about 6% of metering points have one.^{[12, 13]} None of these reforms has a measured effect on flexibility of its own; they are preconditions for the measures in the other chapters.

Data makes a difference where its use is the default

For a household's bill to reward it for shifting its use, four links must be in place: the smart meter itself; measurement of use per quarter-hour or half-hour; the use of those measured values in the settlement between suppliers; and their delivery to the supplier for billing. A link that works only on request tends to reach few households. Austria shows this for the second link: at the end of 2024, 97% of its metering points had a smart meter, but only 13% recorded quarter-hourly values.^[4] Austria is now making quarter-hourly recording the default.^[4]

Behind every household's bill sits a second calculation, the wholesale settlement, in which each supplier is charged for what its customers used. Until the current reform, British homes were settled on an assumed daily pattern of use rather than on what their meters measured.^[14] A supplier whose customers moved their use to cheap hours was therefore still charged as if they had not, and had little reason to offer them a time-of-use tariff^[6] or to help them shift in any other way. In 2021 Britain's energy regulator, Ofgem, decided that every meter would be settled on its measured half-hourly use.^[6] Moving the meters to the new arrangement began in October 2025, the date by which the original plan expected it to be finished, and is due to be complete by May 2027; about 20 million of some 34 million metering points had moved by September 2026.^{[6, 7, 15, 16, 17]}

Settlement on measured values gives the supplier a reason to help its customers shift, whatever contract it sells them: even with a fixed price per kWh, every kWh a customer moves to a cheaper hour lowers the supplier's costs, so steering services, cheap or free hours and smart tariffs start to pay for the supplier itself (see the box on settlement below).^{[6, 7]} Billing on measured values is a separate step, needed only for contracts that price by time, and it is what passes the gain on to the household directly. Norway, Denmark and Finland already do this: every household's hourly values reach its supplier through a central datahub, a national database for meter data, and households on contracts that follow the hourly spot price have been billed on them for years.^{[1, 2, 18, 19, 20, 21, 22]}

Devices need machine-readable prices and a short list of protocols

A heat pump or charger cannot read a tariff sheet or a bill: to follow a price automatically, it needs that price as data. Since 2023 California's state energy agency has required the large utilities, and the largest local public bodies that buy energy on residents' behalf, to publish every time-varying rate in one free public database.^{[8, 9]} Each rate, usually covering both energy and network costs, has a standard number, so a heat pump or charger that knows this number can fetch the exact hourly price and follow it automatically.^{[9, 23, 24]} Britain will require the same of its suppliers from February 2027.^{[25, 26]}

To steer a heat pump, a charger, a battery and a solar inverter, a home energy manager today has to speak at least ten different protocols.^[10] ElaadNL, the joint innovation centre of the Dutch distribution grid operators, has proposed a short list of five: one standard for signals coming into the home from outside, and four for communicating with the devices inside it, one of which is only for car chargers.^{[11, 27]} The grid operators cannot impose this list, so they are trying to steer the market towards it. A device maker needs to support just one of the four in-home standards, while any compatible energy manager speaks all five, so a household can combine devices of different brands.^[11] Test events, where manufacturers check that their products work together, and free open-source software support the choice; certification is planned for the end of 2026.^{[11, 28, 29]}

A heavily certified meter held back the rules built on it

In 2016 Germany chose not a simple smart meter but a separate, highly secured communication unit next to the meter, certified by the federal cyber-security agency; mass rollout could only start once devices from three independent manufacturers had been certified.^[12] Germany then built new rules on that unit: every supplier must offer a dynamic contract, network tariffs can vary by time of day, and grid operators can dim new heat pumps and chargers during moments of grid stress.^{[30, 31, 32]} In mid-2026 only 5.9% of metering points had the unit, so most households cannot use the dynamic contract their supplier must offer.^[13] In 2023 parliament restarted the rollout on new terms: units can now be installed first and have functions added later by software, and a household pays at most €20 a year.^[12]

Each new generation of meters, and any rule that devices must be controllable (see Chapter 5), faces the same choice: a separate certified box that first has to reach every home, or standard communication built into the device itself.

Preconditions for the mass market, set by public bodies

These reforms matter less for the first customers than for the mass market. Britain's large time-of-use tariffs (see Chapter 2) existed before its settlement reform: the suppliers that pioneered them chose to have those customers settled half-hourly, one customer at a time.^[33] The reform makes such tariffs worth offering to every household. In 2021 Ofgem estimated that the reform would bring consumers net benefits, after its cost, of £1.6–4.5 billion (about €1.9–5.2 billion) over 2021–2045, roughly £2–5 a year per metering point.^{[6, 16, 34, 35, 36]} In each example in this chapter, a regulator, a government or the grid operators laid this groundwork, not the market; suppliers and device makers build on it.

What this means for Belgium

• Regulators at federal and regional level could jointly require one machine-readable format for contract prices and network tariffs, as California does and Britain will from 2027.^{[8, 26]} Their own price comparison tools, such as the Flemish regulator's V-test, could be a starting point: to compare contracts, the regulators already collect the details of the offers they list, so publishing them in a machine-readable form would be a modest further step.^[37]
• Governments, regulators and grid operators could endorse the Dutch short list of protocols, since Belgium buys its devices on the same market. They could also take part in its test events and link subsidies or tariff benefits to devices that speak one of the four in-home standards.
• Governments and grid operators preparing the next generation of meters, which Fluvius plans from 2033, or any rule that devices must be controllable, could keep certification proportionate, let functions be added by software after installation, and prefer standards built into the devices.^[38]

Five patterns across the chapters

Britain leads in practice, but the Nordic countries came first on data. British suppliers sell tariffs built around a device: in July 2025, 835,000 households were on a smart time-of-use tariff, 653,000 of them on a car tariff (see Chapter 2). British grid operators buy flexibility routinely, with 9 GW under contract in 2024 and one shared method to weigh its cost against that of reinforcement (see Chapter 4). On data, Norway, Denmark and Finland came first: they have billed households on measured hourly values for years. British suppliers launched their car and smart tariffs before the regulator's settlement reform, by having those customers settled on measured half-hourly use one at a time. The reform, which does this for every meter, gives every supplier a reason to help its customers shift, whatever contract it sells them (see Chapter 8). Britain's lead also rests on a rule Belgium does not have: a British supplier pays the network charges itself and is free to fold them into one all-in price per kWh, so it can make all of it cheaper at night, whereas a Belgian supplier passes the regulated network charges on unchanged (see Chapter 2).

Imposing control or leaving it to the market: a spectrum. On one path, the law or the regulator requires devices to be steerable and decides who steers them. On the other, flexibility is left to contracts with suppliers and aggregators, which is broadly where Belgium stands. The choice reflects different views of how far public rules should reach into a household's appliances, and most countries combine the two (see Chapter 5). Germany allows grid operators to dim new heat pumps and chargers during moments of grid stress, but guarantees 4.2 kW and gives a network-charge discount; Britain makes new home chargers default to off-peak hours, which the owner can override. Such rules reach scale where the wiring already exists, as for French water heaters on the meter switch, and stall where it does not, as German dimming still waits for smart meters (see Chapters 5 and 8). On the market side, opening wholesale and reserve markets to aggregators produced little household volume by itself (see Chapter 7).

Automation delivers; simple prices help the people who respond themselves. Automatic control makes the largest difference. In Québec, where one utility runs both kinds of scheme in the same winters, homes that had to act themselves cut about 0.8 kW per peak event and homes with a steered thermostat about 2.9 kW (see Chapter 3). Where flexibility reached scale, a device acted on its own, set by a rule or sold in a contract (see Chapters 2, 3 and 5). Contracts with simple, easy-to-understand price differences can also change behaviour: the first 8,000 customers of a Belgian time-of-use contract used 45% of their electricity in the cheapest blocks, more than before they switched (see Chapter 2). That simplicity matters mainly where people respond to the price themselves, because steering software can follow an hourly price just as well as prices that change in fixed time blocks.

Politics steps in when bills rise sharply. Slovenia's parliament passed an emergency law within weeks after households with solar panels faced network-bill rises of more than 200%, and Sweden's government stopped its peak-charge obligation less than ten months before the date by which all grid companies would have had to introduce the charge (see Chapter 1). In Norway, where almost every household paid the hourly price, the government offered an optional flat state price from October 2025, after years of crisis support, and by April 2026 about two-thirds of households in the south had switched to it. Softer interventions keep the incentive in place: Ireland caps only the wholesale-linked part of mandatory dynamic offers, at a level exceeded in 0.6% of trading periods from 2021 to 2023 (see Chapter 2), and Germany and South Australia apply new solar rules only to new installations (see Chapter 6). A network tariff reform leaves a grid operator's capped revenue unchanged, yet public debate in parliament and the media often treated such reforms as a price rise, and analyses of who would pay more and who less were often missing (see Chapter 1).

Measured effects are scarce and smaller than forecasts. Where peak-based network tariffs were evaluated, peaks fell by only a few per cent, about 3% in Flanders; advance estimates for planned time-of-use network tariffs are higher, as is the 11% that the Dutch national grid-congestion programme expects (see Chapter 1). No measured result has been published for Germany's dimming, France's re-timed water heaters or Britain's charger defaults (see Chapter 5), for price signals on solar exports (see Chapter 6) or for the data reforms (see Chapter 8). The most reliable figures come from comparisons with a control group or from metering the device itself (see Chapter 3).

Recommendations

1. Regional regulators (Flemish, Walloon and Brussels) and the grid operators: before a new network tariff starts, publish who will pay more and who less, phase in the change, and evaluate it a few years later with meter data and a household survey, as Norway did (see Chapter 1).
2. Regional regulators (Flemish, Walloon and Brussels): when designing fixed time blocks, check whether new peaks appear at the start of cheap windows, consider combining the blocks with a peak charge, as Austria plans, and build in a staggered start, as Britain and Finland do (see Chapters 1 and 5).
3. Federal and regional governments and their regulators: before the Flemish duty to offer a dynamic contract reaches all suppliers in 2029, design crisis protection that still gives households a reason to avoid expensive hours, such as support based on the monthly average price or a cap like Ireland's (see Chapter 2).
4. Suppliers and aggregators: sell control as the product, such as a low fixed price or a cheap window in return for steering the car, battery or heat pump, on by default in a contract the customer chooses, with clear terms and an easy override. Under the Flemish capacity tariff, steering may also need to limit the charging power of electric cars (see Chapters 2 and 3).
5. Suppliers and aggregators: build home-battery offers on several sources of income, with the savings on the household's own bill as the foundation, present reserve and imbalance income as volatile, and show what steering adds to a battery that already makes the most of the price signals the household is directly exposed to (see Chapter 7).
6. Federal and regional governments: in any future product rule or subsidy for home chargers, require off-peak default hours and a random start delay as well as steerability; Britain's rule was estimated to add about £40 (€47) per device to manufacturing costs. For heat pumps, regional premiums could require the installer to schedule the heating of domestic hot water in the middle of the day, when solar power is plentiful, rather than in the morning or evening peak, when heating it brings the household no benefit (see Chapters 4 and 5).
7. Federal and regional governments: if a safety net under market-based flexibility is wanted, apply it to new and replaced equipment only, with a guaranteed minimum, a payment and published interventions, as in Germany, and households last in the order of measures, as in Australia (see Chapters 5 and 6).
8. Manufacturers and installers: make every new heat pump, charger and inverter able to receive an external signal over an open standard, such as those on the Dutch short list, and commission it with price-following control switched on and, for heat pumps, with domestic hot water heated in the middle of the day. Size heat pumps and set backup heaters with the cold-spell peak in mind (see Chapters 2, 4, 5, 6 and 8).
9. Regulators at federal and regional level: jointly require one machine-readable format for contract prices and network tariffs, so that a device can fetch the household's exact price, as California does and Britain will from 2027. The regulators already collect the details of the offers in their price comparison tools, so this would be a modest further step (see Chapter 8).
10. Fluvius and the other grid operators: publish per congestion point, with one shared method, the price up to which flexibility is cheaper than reinforcement: the yearly value of postponing it. For households, consider a published availability price per kW per year, sold through suppliers and aggregators with a recruitment plan, and, together with Elia, complete the planned extension of FlexHub, the platform that the grid operators and Elia already share to register which flexibility provider serves which connection, to all flexibility products, including the grid operators' own congestion services, so that a household signs up its devices once and can change provider as easily as it changes supplier (see Chapter 4).
11. The federal regulator and Elia: publish each year, in aggregate and within the confidentiality rules of the capacity mechanism, how much of the contracted capacity comes from household devices and how that changes, so that all Belgian stakeholders can follow the trend. For any household product at times of scarcity, Elia could pay per kW measured on the device, use competitive bids from the start and require a control group where a household baseline is unavoidable (see Chapters 3 and 7).
12. Regulators at federal and regional level: measure what moves. Track not only how many households have a fixed, variable or dynamic contract, but also how many have a time-of-use contract, a contract built around a device or another new type of offer. Include time-of-use contracts in the regulators' price comparison tools as well, such as the Flemish V-test, which in October 2026 compared only fixed, variable and dynamic contracts. Ask suppliers to report how much consumption their products actually shift, including time-of-use contracts and offers of free electricity in certain hours: shifting consumption is a policy goal with benefits for society as a whole, so progress deserves to be tracked publicly. Report grid operators' flexibility purchases as contracted capacity, energy used and euros per kW, with the household share (see Chapters 2, 4 and 6).