Demand Response

A change in electricity consumption patterns in response to supply conditions, price signals, or explicit requests. Instead of only adjusting supply to meet demand (the traditional approach), demand is adjusted to match supply. One of the core mechanisms for implementing Flexibility.

The fundamental insight

The Electric Power Transmission system has no significant energy buffer — generation must match consumption in real time. Traditionally this was achieved entirely on the supply side: dispatching generators up or down. Demand response adds the other side of the equation: making demand itself adjustable.

This matters more as variable renewables grow, because supply becomes less controllable. If you can’t always adjust generation to meet demand, you must be able to adjust demand to meet generation.

Implicit vs explicit

This distinction is central to EU/Swedish flexibility strategy. The Clean Energy Package mandates both pathways in law: the Electricity Market Directive requires that consumers have access to dynamic pricing (Art. 11 — implicit), and that independent aggregators can participate in markets without supplier consent (Art. 13 — explicit). The EU legal definition of demand response (Directive Art. 2(20)) explicitly covers both: response to “market signals, including time-variable electricity prices or incentive payments” and bids “to sell demand reduction or increase at a price in an organised market.”

Contract types carrying the implicit signal

The Commission’s April 2026 retail report sets out four flexible retail contract types, differing in how much price risk they pass to the consumer:

Switching to a dynamic contract and actively managing consumption is estimated to save up to 40%. Dynamic contracts are available to households in 16 member states but exceed 5% penetration in only five — Finland, Latvia, the Netherlands, Sweden and Spain — with smart metering at ~60% across the EU-27 the binding enabler. The Commission’s emphasis falls on hybrid contracts as the way to reach consumers for whom full spot exposure is unsuitable. (Source - COM(2026)850 Retail Flexibility Report)

Multiple supply contracts per connection point. The amended Art. 4 of Directive 2019/944 lets a customer hold several simultaneous supply contracts behind one connection point, via separate metering/billing points or submeters — for example EV charging on a dynamic contract, the heat pump on time-of-use, and household base load on a fixed contract. This is the EU’s answer to the “all-or-nothing” problem: it exposes flexible loads to price signals while leaving the rest of consumption shielded, which matters because whole-household dynamic exposure is precisely what deters risk-averse households from implicit DR. (Source - COM(2026)850 Retail Flexibility Report)

The Network Code on Demand Response

Demand response is getting its own EU network code — the Network Code on Demand Response (NC DR), the first EU regulation specifically focused on demand-side market participation. The NC DR will standardize how DR resources register, qualify, and participate across EU markets, establish mandatory flexibility registers, and define rules for aggregation, baselining, and settlement. Key debates include the minimum bid size (0.1–1 MW — critical for whether household-level resources can participate directly) and baseline methodology. Entry into force is expected in 2026 — note however that as of May 2026, the Commission’s final text had not yet been published and the NC DR was listed as “delayed” on Svk’s market roadmap. (Source - NC DR Proposal (ENTSO-E and EU DSO Entity, 2024), Source - ACER Recommendation 01-2025 on NC DR, Source - Elmarknadsrådet Meeting 1 February 2026)

Swedish post-EIF obligations: after the NC DR enters into force, Svenska kraftnät and the DSOs must jointly develop and submit four sets of terms and conditions to Ei for approval. This triggers a legally defined but operationally tight development cycle:

1. FIS terms and conditions — flexibility information system registration and data exchange rules
2. TSO-DSO and DSO-DSO coordination framework — formal grid prequalification procedures, temporary limits, and multi-level coordination architecture
3. Market-based procurement terms — LFM-h/p/e product specifications, bid formats, merit-order rules
4. Near-real-time activation terms — baseline methodology, activation protocols, settlement

The timeline for developing these four deliverables is described as “tight” given the complexity of the coordination across 168 Swedish DSOs and Svk. Industry broadly supports standardization and market-based procurement as a principle; concerns focus on IT/information exchange complexity. (Source - Elmarknadsrådet Meeting 1 February 2026)

Parallel track — NC DC 2.0: The Network Code on Demand Connection (NC DC, EU 2016/1388) is being simultaneously amended via ACER Recommendation 03-2023. While NC DR governs how demand-side resources participate in markets, NC DC governs the connection requirements for demand facilities. NC DC 2.0 explicitly brings EVs, EVSE, heat pumps, and power-to-gas under harmonized EU connection requirements for the first time — creating the connection-side regulatory foundation that NC DR then builds on for market participation. (Source - ACER Recommendation 03-2023 NC RfG DC (2023))

Three product categories

1. Emergency DR — activated to prevent blackouts during supply scarcity. Last resort.
2. Economic DR — activated when market price exceeds value of consumption. Continuous optimization.
3. Ancillary services DR — demand-side resources providing grid services: frequency regulation (FCR, aFRR, mFRR), contingency reserves. Competes directly with generator-provided services.

In the Nordic Balancing Markets, category 3 is increasingly important. As inverter-based generation (solar, wind) replaces synchronous generators, mechanical inertia decreases and demand-side ancillary services become critical for frequency stability.

Technologies and enablers

• Smart meters — foundation for dynamic pricing and measurement/verification
• Building automation / HEMS — automated response without manual intervention
• EV smart charging — large flexible load; aggregated EVs as demand response resource
• Industrial process flexibility — aluminum smelters, data centers, cold storage. An Energiforsk study of Swedish data centres puts the share that could join reserve markets with limited technical measures at 75–180 MW, with UPS batteries and pausable HPC/crypto load as the main resources and co-location customer contracts as the main barrier (Source - Energiforsk 2025-1089 Datacenter som Flexibilitetskapacitet (2025)); see Data Centres and Grid Flexibility
• Aggregation platforms — aggregate many small resources into market-participant-sized portfolios
• Short-term load forecasting (STLF) — the operational data layer enabling market participation; BRPs cannot submit day-ahead plans and FSPs cannot construct bids without a baseline load forecast. Unknown demand = no bid. See Load Forecasting for the full method landscape and its role as an enabling condition for explicit DR.

Non-linear price effects

Small demand reductions create outsized price effects because peak generation is the most expensive:

• 5% peak demand reduction → estimated 50% price reduction during crisis periods
• 1% peak demand shift → 3.9% system cost savings (PJM study)
• 10–20% of total electricity costs driven by just ~100 peak hours per year

This makes demand response economically powerful even at modest participation levels.

A retrospective Swedish analysis of the sustained high-price period November 2022 – May 2023 found calendar- and temperature-corrected consumption fell by 7–8% per month relative to baseline (largest in elområde 4, where prices were highest) — empirical evidence that Swedish demand responds to sustained high prices, not just short spikes. The source report itself frames this only as evidence that households/businesses were able to react to price signals; the read-through to implicit vs. mandated DR is this wiki’s own inference. (Source - Energimyndigheten ER 2026-08 Energiomställningen (2026))

VRE integration costs and the DR value case

OIES EL36 (2019) provides a systematic decomposition of the costs that variable renewable energy imposes on the power system — and identifies which DR mechanisms address each: (Source - OIES EL36 Electricity Market Design for Decentralized Flexibility (2019))

This framing explains why the business case for DR strengthens as VRE penetration grows: DR doesn’t only provide ancillary services — it reduces the total system cost of VRE integration across all five categories.

Relationship to other flexibility mechanisms

Demand response is one tool in the broader Flexibility toolkit:

• Energy Storage — shifts energy in time (batteries, pumped hydro, thermal)
• Demand response — shifts or curtails consumption
• Distributed generation — local supply adjustment
• Grid reconfiguration — topology changes to manage congestion
• Cross-border trading — spatial flexibility via Electric Power Transmission interconnectors

These mechanisms complement each other. A Virtual Power Plant typically combines DR, storage, and DG into a single dispatchable portfolio.

Global economics of flexible demand — IEA (2026)

The IEA’s September 2026 electrification report (IEA Special Report on Electrification) quantifies the case at global scale. Negative-price hours in more than 60 markets rose from about 110 a year on average in 2019 to over 450 in 2025. Flexible operation could save a household up to USD 300 a year, 15–30% of the running cost of an EV, heat pump or electric water heater, if consumers can access lower wholesale prices; EVs offer the largest saving. In its High Electrification Scenario about 10% of average demand shifts towards high-renewables hours by 2035, and 15% of peak demand is controllable (EVs and heat pumps average about 450 GW but about 900 GW at peak), on the assumption that user acceptance, interoperable controls, incentives and market frameworks are in place. The report cites France, where about 15 million consumers are on time-of-use tariffs and the automated water-heater signal avoids more than 3 GW of evening peak.

Demand flexibility as a system necessity — LMA2024 finding

LMA2024 provides the strongest quantitative case for demand response as a structural system necessity rather than a market supplement. In Svk’s high-electrification scenarios (EP: ~343 TWh/year with new nuclear; EF: ~342 TWh/year with large-scale renewables — both by 2045):

• Without flexible EV charging and hydrogen electrolyzer dispatch, the system accumulates hundreds to over a thousand shortage hours annually by 2045 — system adequacy fails
• With active flexibility (EVs charging off-peak, electrolyzers providing virtual battery dispatch via H2 storage), shortage hours drop to manageable levels
• The difference is not marginal — flexibility is a binary requirement for adequacy in high-demand pathways

The electrolysis-hydrogen pathway is particularly significant: large-scale electrolyzers operating as dispatchable loads can absorb surplus variable renewable energy and respond to system needs, functioning as multi-GWh virtual batteries via the hydrogen storage buffer.

The finding contextualizes why Svk explicitly includes demand flexibility in its system capability requirements and why the Balancing Markets › Strategic reserve — first procurement failure, then success (2025–2026) and BSP framework development are not just market design refinements — they are prerequisites for the 2045 scenarios that underpin Sweden’s electrification strategy.

Demand response in Finland’s draft national FNA

The draft Finnish national Flexibility Need Assessment (prepared by Fingrid, consulted on in summer 2026) leaves demand response out of the flexible resources it counts, citing lack of data and uncertainty about availability and use, and assumes it would only participate in the day-ahead market. A sensitivity case reported in the draft’s summary indicates that, if the full demand response potential were available at all times, uncovered ramping needs would fall to nearly zero. The industry association Energiateollisuus argues that the exclusion may overstate flexibility needs and asks for the conclusion on additional capacity to be removed or qualified. The draft is not public; these points come from the association’s quotations of it (Source - Energiateollisuus Statement on Draft Finnish FNA Report (2026)).

Swedish demand response

Sweden’s earliest working demand-flexibility mechanism predates “demand response” as a term: Rundstyrning (ripple control), widely deployed by the mid-1990s, remotely switched water boilers and street lighting via a signal on the distribution network, with potential to curtail up to 7–8% of peak load in smaller DSO networks, before being largely phased out around 2000 — CoordiNet ties this to the absence of delivery responsibility in the no longer vertically integrated utilities after deregulation.

Swedish DR potentials to 2030

FlexAbility (2025) quantifies realistic technical maximum potentials for Swedish demand response resources at hourly timescale for 2030:

The heat pump gap is the most striking: only 300 MW prequalified today vs 5,750 MW potential — a 19× gap driven primarily by the absence of smart control hardware at the household level (58 SEK/MWh cost; 2.5M units assumed by 2030). Industry’s 1,300 MW splits into three cost tiers (100 / 2,000 / 4,000 SEK/MWh) and must not disrupt core process; light EVs assume 85% non-public smart charging reaching 100% by 2030 (upward) and 20% of the fleet simultaneously connected (downward); heavy EVs assume 20% of trucks and 50% of buses electrified with depot night-charging; electric boilers are policy-blocked — the energy tax eliminates the economic incentive entirely, and the 975 MW figure assumes the tax is reduced by 2030 (see the district-heating elpannor discussion below and Data gaps for where that stands).

Heat pump flexibility: temperature dependence

Field data from the E.ON Simris microgrid pilot (2015–2018) provides the most operationally concrete description of heat pump flexibility availability as a function of outdoor temperature (Source - InterFlex Simris Microgrid (2018)):

The coldest periods — when grid stress is highest — are precisely when heat pumps are at maximum output and cannot be further increased: they can only be curtailed (downward). Flexibility in the −10 to 0°C range is bidirectional and most abundant. Control systems should implement an indoor comfort boundary: DSR is disabled if indoor temperature deviates by more than ±1°C from the customer-set setpoint.

The Simris DSR platform issued steering signals as a percentage of maximum capacity (−100% to +100%), derived from the central battery’s state of charge — not in kW — allowing the platform to adapt the setpoint without knowing each heat pump’s nameplate capacity.

Electric boilers represent an acute policy failure: 975 MW of technically available, cost-competitive demand response sitting idle because the energy tax structure eliminates the incentive. The analysis explicitly assumes the tax will be reformed by 2030 — without that, the potential is effectively zero.

This resource is concentrated in district-heating (fjärrvärme) elpannor — Energiföretagen puts the figure at ~1.2 GW of largely unused capacity, broadly corroborating FlexAbility’s independent estimate. The mechanism differs structurally from individual building heat pumps, for two concrete reasons: DH networks can draw on thermal storage to shift consumption over relatively long time horizons, and can fall back on bioeldade reservpannor (biofuel-fired backup boilers) that take over production when electricity prices are high — neither option is economic at single-building scale. So running a DH elpanna as flexible load does not require accepting higher electricity draw at winter’s tightest moments — avoiding the exact failure mode that limits building-level heat-pump DR (downward-only exactly when grid stress is highest, above). Nordic neighbours already apply the EU minimum tax rate to district heating’s electricity use on this systemic-benefit logic; Energiföretagen continues to press for the same targeted (not general) tax cut in Sweden, most recently in April 2026. On 1 October 2026 Energimyndigheten proposed that the government prepare a time-limited, limited cut in the energy tax on electricity used in district-heating heat pumps and electric boilers, without a tax level, legal text or cost estimate; its modelling shows mainly a shift in the production mix, not higher heat demand (Source - Energimyndigheten ER 2026-23 Fjärr- och Kraftvärmens Roll (2026)). The cut is disputed by critics as protection for district heating’s business model rather than a genuine system-flexibility argument, since the same substitutability logic would apply to electricity used directly by household heat pumps. (Source - Second Opinion Fjärrvärme Elpannor Flexibilitetsresurs (2026))

Industrial demand response has a structured cost profile: a first tranche (~350 MW) at 100 SEK/MWh reflects easy-to-shift loads; a second tranche (~850 MW) at 2,000 SEK/MWh requires process adjustments; a third tranche (~100 MW) at 4,000 SEK/MWh represents near-core-process flexibility. (Source - FlexAbility Delrapport 1 (2025))

Industrial demand response — the 2025 interview study

Energimyndigheten interviewed 24 large industrial electricity users (autumn 2024, 30–60 minute qualitative interviews with energy managers), run jointly with Power Circle’s parallel FlexAbility project on the same companies to avoid duplicate burden — FlexAbility supplies the aggregate point-estimate industry number above; this study supplies the qualitative and per-branch detail. (Source - Energimyndigheten ER 2025-20 Flexibilitet Målgruppsanpassad Information (2025))

Headline finding: industry could flex roughly 5–15% of its electricity use near-term without major investment — but almost none of that potential is currently used to relieve grid capacity shortage. Only 1 of 24 firms had serious plans to join a local flexibility market. Being flexible always carries a cost — either lost production or built-in overcapacity somewhere in the process.

Per-branch picture: papper/massa (38% of industrial electricity use) is already substantially flexible and market-exposed, trading both production and consumption bids on day-ahead/intraday. Järn/stål has ~900 MW assessed flexible (Jernkontoret 2020, ~15% of subscribed effect), of which >75% is already used flexibly — but not for grid-capacity relief. Verkstadsindustri (dominated by micro/small firms) is not currently flexible at all; interviewed firms estimate 10–15% potential, contingent on buffer capacity for intermediate products. Kemiindustri has low potential given continuous, costly-to-halt processes, and poorly designed flexibility there could paradoxically increase emissions (e.g. gas flaring). Trävaruindustri/sågverk’s largest identified opportunity is drying-fan electricity use (~500 GWh/år), suited to short-duration balancing-type flexibility (RISE’s parallel SågFlex project).

Hydrogen — a corrective finding: earlier literature (Power Circle 2022) flagged hydrogen electrolysis as potentially the single largest industrial flex source (1,233 MW for Hybrit alone by 2045). A 2023/2024 Sweco survey of Swedish hydrogen projects (22 then 16 interviews) found almost none are actually designed for flexibility: most integrated processes target only a minimum 1–2 hour hydrogen buffer, and most e-fuel projects that originally planned flexible electrolyser operation have since abandoned that plan, prioritising electrolyser cost-recovery instead. Modelling suggests hydrogen flexibility may not meaningfully enter the system until around 2035, first on the west coast — a substantially more pessimistic near-term read than the 2022 estimate, and consistent with FlexAbility’s own later (Oct 2025) downward revision of hydrogen’s 2030 potential (see Swedish DR potentials to 2030 above).

Swedish household demand response

Swedish household DR adoption is characterised by high informal willingness to act but very low formal market participation — the 42% → 2.8% conversion gap identified by Ramboll (2024). Across all surveys, economic incentives dominate: aggregator delegation is driven by earning potential, not awareness. Lack of knowledge is not a statistically significant barrier (FlexAbility 2025). The primary binding constraint is structural — tariff fragmentation, absent standardised service interfaces, and the underdeveloped BSP/BRP market. Only ~12–13% of households face actual hourly price signals despite nominally higher timprisavtal penetration rates.

For the full analysis — aggregator delegation surveys (FlexAbility, n=2,872), adoption baselines (IVL, n=10,328; Ramboll, n=1,173), consumer service landscape (AFRY: 44 services, 172 actors), and the 2024 snapshot on EV smart charging, effektavgift knowledge, and market penetration — see Swedish Household Demand Response — Consumer Adoption and Barriers.

Effekttariffer — the double-edged price signal

Capacity-based effekttariffer (demand tariffs) were mandated for all Swedish DSOs by January 2027 under EIFS 2022:1 — but the government has since tasked Ei to repeal EIFS 2022:1 by 30 June 2026 and develop a new effektavgift model (proposal due 12 April 2027). Effektavgifter remain permissible after repeal under Art. 18 EU Electricity Market Regulation and ellagen, but are no longer mandatory. (Source - Ei Effektavgifter webb (2026))

Construction diversity: The Elmarknadshandbok §9.1.4 confirms the range of constructions deployed in practice: measured monthly peak; mean of the highest N measurements in a month or year; time-varying rates by hour or season; and an additional högbelastningsavgift applicable on weekdays November–March. This diversity is precisely what Ei has identified as the obstacle to standardized automated steering services — each DSO’s unique construction requires bespoke integration by any aggregator or building management platform. (Source - Svensk Elmarknadshandbok 26A (2026))

These tariffs correctly incentivize customers to flatten their demand profiles and avoid expensive peaks. But they create a structural conflict with spot price signals:

When spot prices are low (e.g., midday solar peak), the economically correct signal is to charge EVs and batteries — load is cheap and beneficial for the system. But the demand tariff still penalizes any peak demand event, regardless of what the spot price is doing. The two signals point in opposite directions.

This double-edge undermines the coordination between implicit DR (responding to price) and capacity management (avoiding tariff peaks). Göteborg Energi Nät is testing a dual-tariff model to separate the two incentive structures. (Source - FlexAbility Delrapport 5 (2025)) The double edge is one instance of a more general structural problem — a single DER receiving multiple uncoordinated price signals with no defined arbitration — analysed in The Signal Stack — Price Signal Collisions at the Customer DER.

Simulation evidence (Energiforsk 2026): a Sweco/Merlin & Metis study of four effektavgift designs on 200 battery-equipped villas (real 2025 prices) found that demand charges change customer behaviour strongly but deliver limited benefit to the grid — little reduction in the grid’s dimensioning need once sammanlagring (coincidence across customers) is accounted for — and that they reduce customers’ incentive to act on the spot market and can even create new peaks (synchronised response). Conclusion: economic incentives should be more precise in both time and space, and the network tariff cannot do the job alone. The companion UniFlex study proposes a “unison” hourly capacity tariff reflecting both grid and market value, and shows the locational tension — pricing on individual nätstation capacity gives sharp, dispersed spikes, while a single grid-wide price reads as unfair to customers with no local shortage. (Source - Energiforsk 2026-1197 Konkurrensen om Efterfrågeflexibilitet Simulering (2026), Source - Energiforsk 2026-1193 Unison Prissignal Timeffektavgift (2026))

Deployment status — Ei R2026:02 (2024)

Ei‘s first biennial smart grid monitoring report (Ei R2026:02, December 2025) confirms national deployment as of 2024: several DSOs have deployed time-differentiated tariffs but many customers are still not covered. No significant change between 2023 and 2024. All DSOs are legally obliged to time-differentiate their tariffs by 1 January 2027 — Ei expects the indicator to reach 100% at the 2028 reporting cycle. (Source - Ei R2026-02 Utvecklingen av Smarta Elnät (2025))

Ei’s SGI microdata (Sh_63A_tdtariffs, 2024, n=111 REL reporters) provides company-level granularity:

• System average: 18.2% of customers ≤63A have a time-differentiated grid tariff
• 37 of 111 companies report any coverage (67% of lokalnät companies have none at all)
• 11 companies at 100%: Falkenberg Energi, Skövde Elnät, Skånska Energi, Sollentuna Energi, Växjö Energi Elnät, Västra Orusts Kraft, Kraftringen Nät, Telge Nät, Kungälv Energi, Trelleborgs Energi, Jukkasjärvi

For RER/RET reporters: Öresundskraft, Svk, and Skellefteå Kraft are at 100%; E.ON at 72%; remaining companies at 0%. (Source - Ei SGI Data 2023-2024)

Tidsindelade effektavgifter — first behavioral evidence

Göteborg Energi Nät introduced tidsindelade effektavgifter (time-divided demand tariffs) on a voluntary basis from 5 February 2025. As of June 2025, more than 1,100 customers had enrolled. First-season behavioral outcomes: (Source - Göteborg Energi Elektrifieringsrapporten nr 1 (2025))

The +16% rebound at 20:00 is non-negligible — DSOs planning tidsindelade effektavgifter must model both effects, as the rebound may stress transformer capacity at evening transition.

For demand response’s role as the named-but-undelivered adequacy mitigation — and why the strategic reserve’s CONE cap was benchmarked to household DR — see Capacity Adequacy and Flexibility as the Missing Reserve. The pattern recurs in real time: when a two-fault disturbance exhausted the SE3/SE4 mFRR bid stack on 8 June 2026, the fast firm capacity that answered was gas turbines and Baltic imports — demand response was absent from the response. (Source - Svk Driftstörningar 8 Juni 2026)

The effektavgift complaint surge (Ei konsekvensutredning, 2026)

The impact assessment behind EIFS 2026:8 quantifies the consumer reaction to the effektavgift rollout. Complaints/questions to Ei about the grid (elnät) jumped from 67% of all complaints in 2024 to 80% in 2025 (2,426 of 3,053); of those 2025 elnät complaints, 53% (1,309) concerned elnätsavgifter specifically, and of that subset, 64% (837) were specifically about tariff design / effektavgifter. As of spring 2025, ~13% of households had received an effektavgift, and by early 2026 drygt 30 DSOs applied one to customers with säkring up to 25 A. Ei names the core comprehension problem directly: users cannot reconcile the effektavgift (grid) signal with the spotprice (energy) signal — the two are separate and not necessarily aligned, which is the double-edge above experienced from the consumer side. (Source - EIFS 2026-8 Nätföretags Information till Elanvändare (2026))

Household voices — the case for and against static effektavgifter

Two DEBATT pieces published either side of the March 2026 EIFS 2022:1 repeal decision give qualitative texture to the complaint-surge statistics above, arguing past each other on what should replace today’s designs.

The critique (Gunnar Rodin): using his own experience with Nacka Energi’s design (average of the three highest hourly-average values per month, 56 kr/kW + moms, applied year-round including nights and summer) as a case study, Rodin argues static effektavgifter impose pointless behavioural work on households — what matters for grid load is correlated demand across many customers (e.g. simultaneous cooking or EV charging), which only the DSO can observe and steer, not any single household’s own peak-timing history shown on their invoice. He also flags an equity problem: households with non-inverter (on/off) heat pumps see roughly the same monthly effektavgift year-round (whenever the unit runs at all) regardless of how much their actual energy use varies, since the unit cycles between zero and full power rather than modulating. His proposed fix is a time-of-use energy tariff instead of a capacity tariff — echoed in a comment thread naming the underlying phenomenon as sammanlagring (load diversity/coincidence), the same mechanism the Energiforsk 2026:1197 simulation (above) found limits demand charges’ actual grid benefit. (Source - Second Opinion Effekttariffer Rodin Kritik (2026))

The counter-vision (Anders Kjellström): argues the fix is dynamic, not abolition — falling smart-home hardware costs (a sub-100-SEK IKEA temperature sensor cited as illustrative) and DSOs’ own nätstation-level meters (installed during the AMI rollout) make it feasible for the DSO to act as an active “lastbalanserare” sending occasional steering signals precisely when local peaks (or voltage-affecting troughs) actually form — a phenomenon he locates specifically at the low-voltage/street level, driven partly by correlated neighbour behaviour (“granneffekt”). Points to the emerging Matter smart-home standard as the interoperability layer that would make such signalling cheap to deploy. This directionally aligns with the Energiforsk 2026:1193 “unison” locational timeffektavgift work above, from a device/protocol angle rather than a tariff-methodology one. (Source - Second Opinion Effekttariffer Kjellström Vision (2026))

Read together, both pieces target the same design flaw — a flat, non-time-differentiated capacity signal — but propose opposite structural fixes (drop the capacity charge vs. make it dynamic and locational), a live tension the April 2027 new-model process (see Swedish DSO Tariff Reform — Three Parallel Tracks (2025–2027) › Track 2 — Effektavgift redesign) will have to resolve.

Regulatory push for consumer DR — EIFS 2026:8 (in force 2027-01-01)

Ei‘s EIFS 2026:8 (nätföretags information till elanvändare, decided 2026-05-21, in force 1 January 2027) turns consumer-side DR awareness into a legal obligation on DSOs — the DSO counterpart to the supplier-side EIFS 2024:2. From 2027, every DSO must (4 kap.):

• inform users (website/app) about flexible electricity use via manual control and via automated control, and that there are market services on the electricity market for this — the first explicit regulatory requirement to tell households that automated steering/aggregation services exist;
• place a mandatory link to Ei’s efterfrågeflexibilitet portal ei.se/kundflex on the invoice and website (and to Energimyndigheten’s energiochklimatradgivningen.se);
• publish the meter’s öppet kundgränssnitt (HAN-port-type interface) and supported dataprotokoll, and show on mina sidor whether the interface is active — enabling third-party realtidsmätare (see Submetering);
• if the DSO trades on a local flexibility market, inform affected users in the trading area on mina sidor and explain how to participate — naming the market only if it actually carries a designation used toward market actors — but may not name or recommend specific services or providers (DSO neutrality). This is a recruitment channel into SWITCH, Effekthandel Väst, and similar markets.

The föreskrift also forces effektavgift transparency (purpose/design explained; effektavgiftsgrundande mätvärden shown on mina sidor with a calculation explanation; weighted-average pricing on invoices for dynamic per-kvart designs). Read alongside the Tommy Johansson automation-barrier statement, EIFS 2026:8 attacks the information barrier to consumer DR while the effektavgift redesign attacks the tariff-fragmentation barrier. (Source - EIFS 2026-8 Nätföretags Information till Elanvändare (2026))

Grid risks of demand response at scale

Implicit DR — households and devices responding to the same price signal simultaneously — creates a systemic balancing risk when participation is large enough. When many resources respond at once, BRPs cannot forecast the aggregate effect accurately and Svenska kraftnät faces large, unpredictable imbalances. A 2013 Elforsk study tested three points — 10,000 active households (limited impact), 100,000 (significant impact), and 700,000 (significant impact) — placing the true breakpoint somewhere between 10,000 and 100,000. Sweden is approaching this range as smart metering and time-of-use pricing scale up. (Source - FlexAbility Delrapport 5 (2025))

Ei’s 2026 supplier survey found near-total coordination absence among the minority of suppliers already steering customer load: of the 14 (of 33 surveyed) offering steering services, only 7% coordinate with Svenska kraftnät, and 0% coordinate with local grid companies, regional grid companies, aggregation-service providers, or other flexibility deliverers — meaning the local-congestion-risk side of this problem is currently entirely uncoordinated in practice, not just theoretically possible. (Source - Ei Flexläget 2026 (PM2026-02))

15-minute pricing and synchronisation patterns

The EU Single Day-Ahead Coupling transitioned to 15-minute market time units on September 30, 2025 (96 price points per day vs. 24 previously, by simple arithmetic); the wiki reads this as finer price signals for flexible loads, though the announcement itself does not mention demand response. The effect on synchronisation is not yet known: finer intervals may soften abrupt simultaneous starts, or may create new synchronisation patterns. Explicit monitoring is flagged as necessary. (Source - EC 15-Min MTU Day-Ahead Market (2025), Source - Energimyndigheten ER 2025-35 Förbättra Flexibiliteten (2025))

Random startup delay

A technical mitigation for EV charging synchronisation: a short random delay (typically 0–100 seconds) applied before a charger starts, distributing aggregate load across time. UK regulation (Electric Vehicles (Smart Charge Points) Regulations 2021) mandates delays up to 600 seconds for all private charge points sold after June 2022.

Compatibility requirement (critical): random delay must be opt-out compatible for grid balancing service participation. Svenska kraftnät requires activation within minutes for FCR/FFR — a charge point dispatched for FCR cannot apply a delay that prevents immediate response. Any Swedish mandate would need the same carve-out. No Nordic country has yet mandated random startup delay.

Staggered activation (Energimyndigheten’s reading of NC DR)

Energimyndigheten’s ER 2025:35 says the proposed Network Code on Demand Response would bar TSOs and aggregators from sending a start command to all their controlled devices at the same time, to avoid a load peak when devices restart after a control action. That would be the DR system-level equivalent of random startup delay. The report’s only source for this is a personal communication (Nibe, 2025-10-02), and no such provision was found in the NC DR texts reviewed for this wiki, so treat it as unverified. (Source - Energimyndigheten ER 2025-35 Förbättra Flexibiliteten (2025)) Price-signal synchronization is the non-malicious twin of a coordinated DER cyberattack — both drive the same physics; see Security and Resilience of the Digitalized Flexible Grid.

Emerging solar+battery synchronisation risk

After the tax reduction for microproduction solar sales ended in Sweden (January 2026), many solar+battery systems may switch to self-consumption mode. When the spot price hits approximately 60 öre/kWh, large numbers of these systems may simultaneously stop exporting and start self-consuming or charging batteries — creating a large coordinated load shift whose grid impact is unknown.

EVs and Vehicle-to-Grid as demand response

Electric vehicles are among the largest and fastest-growing flexible demand resources in Sweden. An EV’s 60–90 kWh battery, drawing 7–22 kW when charging, can be a significant DR asset if the charging session timing is controllable.

Smart charging (G2V only): shifting or modulating the charging rate in response to price signals, grid operator dispatch, or aggregator control. FlexAbility estimates 1,600–1,700 MW upward and 5,200 MW downward smart charging potential from light EVs by 2030, assuming 85% non-public smart charging penetration. (Source - FlexAbility Delrapport 1 (2025))

Vehicle-to-Grid (V2G): bidirectional operation where the EV battery also discharges back to the grid. Adds up to 5,000 MW potential by 2030 — but largely theoretical due to regulatory, technical, and commercial barriers. See Vehicle-to-Grid for the complete picture.

Adoption gap: Flexläget 2026 (December 2024 data) shows only 29% of EV owners with home charging use smart charging services — and 81% of apartment EV chargers are on shared parking where smart charging services are underdeveloped.

Fleet trajectory and the apartment-charging cap: Power Circle’s June 2026 BEV forecast puts ~460,000 BEVs in traffic (2026) → 1 million during 2029 → 2 million during 2033 (base scenario), after Sweden stalled at 35–40% of new-car sales since 2022. The flexible-load base therefore scales materially only from the late 2020s. The binding structural limit is the same one that caps V2G: ~half of Swedes live in apartments without guaranteed home charging, where 70–80% of charging would otherwise occur — without charging-infrastructure measures this sets a ceiling on how much EV demand response is reachable, independent of adoption. (Source - Power Circle Elbilsprognos 2026-2035 (2026))

V2G as ancillary services DR: aggregated V2G fleets can in principle participate in FCR-N, FCR-D, aFRR, and mFRR through the BSP framework. The first Swedish V2G delivery to a local flexibility market was four Volvo Cars EVs delivering 111 kWh to Effekthandel Väst (March 2025) — a direct Göteborg Energi–Volvo Cars pilot, not an aggregator delivery. (Effekthandel Väst › V2G breakthrough (March 2025))

Key Swedish barriers specific to EV/V2G DR participation: double taxation (dubbelbeskattning) for cross-area discharge; Svenska kraftnät‘s physical address registration requirement; and classification ambiguity (EV as microproduction vs mobile injection point). (Source - Power Circle V2X Synthesis 2024, Source - KTH Thesis V2G Sweden 2024)

The two-market design

A theoretical market design proposed by Malcolm Keay (OIES EL17, 2016) and analysed by VTT (2016) offers a structural approach to embedding persistent DR incentives rather than relying on occasional price spikes. (Source - VTT-R-04621-16 Electricity Market Designs and Flexibility (2016))

Core idea: split electricity into two products:

• Firm electricity: available on demand; conventional dispatchable generators; higher price
• Non-firm electricity: available when generation conditions allow; intended in the first place for VRE (zero-marginal-cost) generators; lower price

In Keay’s retail model, consumers pay the lower non-firm price whenever non-firm generation exceeds demand and a share of the two prices otherwise, with hourly metering as a prerequisite. The authors argue this creates an everyday incentive to adapt demand to variable supply. (The imbalance-penalty mechanism belongs to the separate Wind System Operator thought experiment in the report, not to Keay’s basic model.)

VTT’s simplified simulation gave only indicative results: with consumer flexibility the firm market faces a lower or easier-to-follow residual demand, but the plant-economics results for the two-market cases were close to the spot-with-VRE case, and the authors call the model too simple to show the design’s features rigorously (no start/stop or ramping costs). The report does not claim the missing money problem is solved. The design has not been adopted in EU/Nordic policy. The LFM-h/p availability-based structure creates ongoing flexibility payments rather than event-only payments, which is a wiki observation, not a claim of the VTT report.

Data gaps

• Targeted energy tax reform for district-heating electric boilers — general electricity tax reduced 7.9 öre to 36.0 öre/kWh from January 2026, but the specific elpanna/värmepump targeted reduction has not been decided. Energiföretagen’s proposal (~1.2 GW flexibility, ~500 MSEK/yr cost; formal begäran om ändring March 2025; Source - Second Opinion Fjärrvärme Elpannor Flexibilitetsresurs (2026)) now has an agency counterpart: Energimyndigheten’s ER 2026:23 (1 Oct 2026) proposes government preparation of a time-limited cut, with level, duration, cost and state-aid questions open (Source - Energimyndigheten ER 2026-23 Fjärr- och Kraftvärmens Roll (2026)). Open: the government’s handling, including any remiss, and the eventual tax level
• Measured effect of 15-minute pricing (from September 30, 2025) on synchronisation patterns and grid stress