Flexibility Market

Flexibility markets address local, distribution-level needs — primarily Congestion Management and voltage quality — a different layer from the system-wide wholesale market or balancing covered elsewhere in this wiki. See Swedish Flexibility Market Landscape for the operational history, market inventory, and Nordic comparison.

Market cycle

Why flexibility markets exist

The Electric Power Distribution grid is shifting from passive one-way delivery to an active bidirectional network. DSOs face congestion from:

• EV charging, heat pumps, and electrification adding large new loads
• Distributed solar and batteries creating reverse power flows
• Growing demand concentrated in specific grid areas

The Clean Energy Package requires DSOs to solve these problems through market-based procurement (Directive Art. 32(1)), rather than simply overbuilding the grid or relying solely on rules-based mechanisms like Villkorade Avtal.

How they work

The DSO’s published call (see the cycle above) states the required flexibility volume, location, time window, and delivery period — e.g., a specific neighborhood tomorrow afternoon. Aggregators, direct resource owners, and Virtual Power Plants bid to reduce consumption or increase generation at that location; lowest-cost bids matching the need clear the market.

Products can include:

• Energy-only payments — per MWh actually delivered
• Capacity payments — for availability/reservation, independent of activation
• Combinations — availability fee plus activation payment

Both sides of the market depend on load forecasting: DSOs trigger procurement from congestion forecasts; FSPs construct bids as the difference between expected and committed consumption — making forecasting quality a direct determinant of settlement accuracy. See Baseline Methods for how delivery is verified. (Source - Load Forecasting Methods Survey (2025))

Relationship to other market mechanisms

Flexibility markets and villkorade avtal are complementary. In the Swedish model (as described by E.ON Energidistribution), the DSO first tries to resolve congestion through the flexibility market; villkorade avtal are activated only if market-based flexibility is insufficient. (Source - E.ON Guide villkorade avtal (2025))

EU regulatory framework

The Network Code on Demand Response (NC DR) will standardize flexibility markets across the EU. The near-final regulation text (ACER Annex 1) specifies:

• Market-based procurement is the default (Art. 29 §2); non-market derogations require NRA approval, max 2 years per derogation, except voltage control with reactive power (may be longer). Derogation must specify which parts of the system, voltage levels, time periods, and products it covers. NRA notifies ACER and the Commission.
• Flexible connection agreements (Villkorade Avtal) must coordinate with market-based procurement; customers holding flexible CAs retain full rights to bid into local markets (NC DR Art. 31 §3).
• Transparency requirements (Art. 37): market results published within 1 day of service procurement; indicative future needs published at least as often as network development plans; all information accessible from a single national access point.
• Product harmonization (Art. 38): 14 mandatory attributes for all active power products. Under Art. 39, SOs must standardize local products and avoid fragmentation.
• DNDP integration (Art. 44): DSOs must include a quantified local services assessment in network development plans — forecasted needs, cost-effectiveness methodology, and medium/long-term estimates with locational granularity. This is a mandatory DNDP component, not optional. ACER/CEER (2025) confirmed that DNDPs are “the primary source of DSOs’ data and analyses” for the FNA, and that both documents should use the same FNAM Tabell 15 data format. (Source - ACER CEER DNDP Guidance (2025))
• 3-year harmonization mandate: ENTSO-E and EU DSO Entity will develop a Union-wide procurement harmonization methodology within 3 years of entry into force.

(Source - NC DR Amended Text (ACER Recommendation 01-2025 Annex 1), Source - NC DR Proposal (ENTSO-E and EU DSO Entity, 2024))

DSO mechanism co-design — the interaction challenge

Local flexibility markets do not operate in isolation. DSOs simultaneously deploy network tariffs, flexible connection agreements (Villkorade Avtal in Sweden), and local markets — three mechanisms designed independently but coexisting in practice. When their design choices overlap, customers receive double economic signals, which reduces economic efficiency and distorts behaviour.

A structured pairwise interaction analysis (Source - DSO Service Acquisition Interaction Comillas (2024)) identifies three interaction conditions for any pair of design dimensions across mechanisms:

• Green: simultaneous use causes no loss of economic efficiency
• Orange: potential loss; requires contextual analysis before combined deployment
• Red: definite misalignment or infeasibility; simultaneous use should be avoided

Network tariffs + Local markets (orange risks): When both have temporal granularity for the same period and area, customers receive the same congestion signal twice — double rewarding. Measurement granularity mismatch (daily tariff meter vs. hourly LFM bids) can create technical infeasibility.

Flexible connection agreements + Local markets (critical red risks):

• Ex-post curtailment notification in FCAs blocks LFM day-ahead participation — customers cannot bid into a market if they don’t know whether they will be curtailed
• Emergency activation makes combined use infeasible — customers with outstanding LFM bids cannot adjust for unannounced curtailment
• LIFO access principle in FCAs undermines LFM bidding reliability

The E.ON model as a green-condition design: E.ON Energidistribution‘s sequential use (LFM first; villkorade avtal activate only if market procurement is insufficient) avoids the worst red-condition conflicts by design — FCAs and LFMs are not activated for the same event simultaneously.

NC DR Art. 31(3) preserves FCA holders’ rights to participate in LFMs. This right is only practically realisable if FCA notification timing, access principles, and compensation designs are made compatible with LFM participation through co-design. Sweden’s NC DR T&C development (12-month window after entry into force) must address these interactions explicitly.

Full design dimension taxonomy and the interaction matrix are at Flexible Connection Agreements.

European LFM landscape

Of 37 European LFM initiatives the European Commission examined in late 2025, only 9–10 were fully operational live markets — two of them Swedish (E.ON SWITCH, Effekthandel Väst), placing Sweden among the strongest LFM track records in Europe.

For the full landscape — TSO-DSO coordination models, pay-as-bid norms, international product design comparison, Portugal’s FIRMe market, and the participation barriers holding back most other EU initiatives — see European Local Flexibility Market Landscape.

Swedish flexibility market landscape

Sweden has the strongest LFM track record in Europe: 7 permanent (commercial) markets, more than any other Nordic country. Three markets are currently active (E.ON SWITCH — 12 areas, Effekthandel Väst, Kinnekulle Flex). Four are closed (CoordiNet, sthlmflex, UppFlex, JämtFlex). Vattenfall Eldistribution formally withdrew after the pilot phase; Ellevio has an intermediate stance.

For the full market inventory, DSO stances, CoordiNet/sthlmflex/E.ON/Kinnekulle operational data, FSP supply-side dynamics, and the emerging Skåne pipeline, see Swedish Flexibility Market Landscape.

The adoption gap in one official number: across local, regional, and transmission grid levels combined, Energimyndigheten’s 2026 indicator report finds only 7 Swedish grid companies report ever having actually called on a flexibility market for up- or down-regulation, in either 2023 or 2024 — a market-existence count of 7 permanent markets, but a market-usage count of 7 grid companies, coincidentally the same number but measuring different things. The same official data shows bilateral-agreement counts growing faster than flexibility-market call-offs over the same period (network-company↔producer agreements 22→32, network-company↔user agreements 233→393) — bilateral deals, not market participation, are where near-term growth is actually concentrated. (Source - Energiindikatorer 2026 (ER 2026-14))

LFM-h / LFM-p / LFM-e — Ei-approved standardized products (December 2025)

Swedish DSOs submitted a standardization proposal to Ei; Ei approved the products in December 2025 (case 2025-102414, seven nätföretag). This was Ei’s first exercise of its approval authority under §10 Förordning (2022:585) (from 2027-01-01 the equivalent is 2 kap. 6–8 § of the elsystemförordning, where Ei approves DSO specifications and standardised products if they ensure effective and non-discriminatory participation — Source - Elsystemförordning (2026-1522)). The products were developed by Energiföretagen Sverige based on experience from CoordiNet, sthlmflex, E.ON markets, Effekthandel Väst, JämtFlex, and Vattenfall’s supplier dialogues. (Source - Ei Godkänner Marknadsprodukter Flexibilitetstjänster (2026))

Key design principles:

• All three products are upward regulation only (increased production or reduced consumption); 0.1 MW minimum
• LFM-h and LFM-p holders are obligated to participate in LFM-e (dispatch obligation); LFM-e can also be used standalone
• The products directly correspond to SWITCH‘s TO/ST/DO product family (and NODES analogues)

Pricing distinction: For LFM-h and LFM-p, market data reports the DSO-offered availability price — what the DSO posts per MWh or MW of reserved capacity. Under Model A this is DSO-set; under Model B it is the competitive clearing price. The LFM-e activation price is separately determined by FSP energy bids at time of activation.

Full specification: Source - Energiföretagen Förteckning Standardiserade Marknadsprodukter (2025). For Model A vs B design recommendations per product (LFM-h/p/e), see LFM Standard Product Design — Model A vs B Recommendations for DSOs.

Production-side flexibility markets

All pilots above address consumption-side congestion. Summer 2025, E.ON Energidistribution launched Sweden’s first local flexibility market focused on production load (produktionslast) — Projekt Halland in SW Sweden. (Source - E.ON Projekt Halland (web, 2025))

The problem it solves is different: in summer, high solar and wind generation combined with low consumption creates overloading in the production direction. The market procures either downward regulation of production or upward adjustment of consumption during peak production hours.

Halland market design choices: direct orders only (no availability component); 50% delivery validation cutoff — lowered to accommodate intermittent production resources; 32.5 MW qualified at launch. The three-factor congestion mechanism (high solar/wind production, low summer consumption, reduced overhead line thermal capacity in hot weather) makes this seasonally distinct from winter congestion. This extends the flexibility market concept to cover both directions of grid stress. (Source - BeFlexible D5.2 Demo Planning and Deployment 2 (2025))

DSO flexibility needs

Ei PM2025:03 synthesised 122–127 of 155 DNDP submissions: aggregate flex needs grow from 277–1,030 MW (0–2yr) to 1,387–2,523 MW (6–10yr) — a 2.5–5× increase over the decade (low end 5.0×, high end 2.45×). Full data, methodology caveats, and direction-separated figures at Flexibility Need Assessment › DNDP-aggregated DSO flexibility needs (pre-FNA benchmark); DSO size breakdown and tool mix at Distribution Network Development Plan › First-round synthesis — Ei PM2025:03 (March 2025). (Source - Ei PM2025-03 DNDP Sammanställning (2025))

Among companies reporting tool choices, ~15% are considering creating or participating in a flexibility market — the first system-wide measure of Swedish DSO market interest. Ei R2026:02 independently confirms that only 15 DSOs used flexibility services (bilateral and/or market-based) in 2023–2024. (Source - Ei R2026-02 Utvecklingen av Smarta Elnät (2025))

DSO procurement economics

DSO willingness to pay — quantified value cases

FlexAbility (2025) provides three quantified DSO value cases from Ellevio’s network: (Source - FlexAbility Delrapport 3 (2025))

Utnyttjandegrad’s average masks a wide 0–40,000 SEK/MWh range, since only hours affecting the four highest daily peaks have value; a fourth channel, alternativkostnad (grid upgrade deferral), doesn’t reduce to a per-MWh figure but produced roughly a 2× NPV advantage in a bus-depot case study using the report’s own revised/realistic flexibility-cost estimate (a naive calculation implies ~17:1, but the report itself revises the flexibility cost upward once transformer overload tolerance is factored in) (full detail at Congestion Management › Quantified economic value of DSO flexibility procurement). These figures imply that DSO willingness to pay — when the right use case is active — is far above the 2,900–3,800 SEK/MWh typical range seen in market data (with outliers to 16,000 SEK/MWh at persistently congested points like Hässleholm — full breakdown at DSO Flexibility Valuation — Methods and Swedish Evidence › Market prices as observed willingness to pay). The gap reflects the CAPEX bias that makes grid investment structurally preferred, the availability of Svk’s temporary subscription as a lower-cost alternative, and imperfect forecasting. Rule of thumb: 1 MW of grid upgrade capacity ≈ 100–200 hours of flexibility at market prices — if a constraint occurs fewer hours than this, flexibility deferral is almost certainly cheaper.

The “charity” problem — revenue regulation as participation barrier

FlexAbility Delrapport 5 (2025) documents that every DSO interviewed cites intäktsreglering as a barrier to running flex markets. DSOs describe procurement cost as “välgörenhet” (charity): they receive 1:1 cost coverage under current regulation but earn no regulated return on capital. Under CAPEX-biased regulation, grid investment generates a return for 40+ years; flex procurement generates nothing — and is subject to Ei’s opex efficiency benchmarking.

Ei’s TOTEX reform (RP5, 2028–2031) is viewed positively by market actors — the right structural fix. Until 2028, the misaligned incentive remains operative. (Source - FlexAbility Delrapport 5 (2025))

Power tariff perverse incentive

Power-based grid tariffs (designed to enable implicit DR) partially undermine explicit LFM participation: a resource delivering a 2-hour activation must compensate by running at elevated power before/after to maintain thermal comfort or state-of-charge, creating higher peaks and incurring additional effektabonnemang costs that erode activation revenue. Most acute for heat pumps and batteries. Not yet addressed in NC DR or Swedish product standardization. (Source - Nordic Energy Research 2025-03 Current Utilisation of Flexibility in the Nordics)

Connection queue and placement mismatch

E.ON Energidistribution alone reports 17 GW of battery storage in its connection queue. The structural problem is a placement mismatch — batteries seeking connections often locate where real estate is cheap or solar resources are favorable, not where grid congestion exists.

Simultaneously, a Catch-22 affects existing customers: industrial customers with large grid subscriptions cannot easily reduce their subscription to reflect actual maximum demand, because they may not be able to restore it when production expands. Each party’s risk aversion blocks the efficient outcome. (Source - FlexAbility Delrapport 5 (2025))

VCG auction — a thin-market research finding

Energiforsk 2026-1151 (Source - Energiforsk 2026-1151 Effektauktioner med Värmepumpar (2026)) tests the VCG (Vickrey-Clarke-Groves) auction algorithm for procuring heat pump demand response — the first Swedish research application to DSO local flexibility procurement. VCG pays each bidder based on their social contribution rather than the clearing price, giving participants a dominant strategy of truthful cost revelation. This is suited to thin markets where pay-as-bid creates strategic bidding incentives.

Simulation results (137 heat pumps, Kristianstad) yield VCG prices of 0.8–1.6 SEK/kW at a 50 kW flexibility need; scaled to the full Kristianstad DSO flexibility need (2–10 MW), total annual payouts come to 1,600–16,000 SEK/year. The fundamental constraint: these payout levels provide no commercial aggregator incentive. The national heat pump flexibility potential is 5.75 GW by 2030, making mechanism design significant even if this specific implementation has limitations. VCG settlement is not currently supported by SWITCH or NODES.