E.ON SWITCH Markets — Supply Liquidity and Growth Recommendations

Operational analysis of E.ON Energidistribution‘s SWITCH flexibility markets, focused on the FSP supply deficit and what can be done about it in the 2026/27 and 2027/28 seasons. Covers market structure, root causes of thin supply, and ranked recommendations. For broader strategic framing see E.ON SWITCH Three-Year Strategic Plan; for why Swedish markets are structurally thin see Why Swedish Local Flex Markets Are Thin — Structural Causes.

Starting position (end of V2025/26)

Empirical market state from Source - BeFlexible D5.2 Demo Planning and Deployment 2 (2025) and Source - SWITCH Marknadsdata (info.switchmarket.se, 2026):

• 12 active markets (11 winter + 1 summer pilot in Halland)
• 25.2 MW pre-qualified against 59.5 MW total stated DSO need — 42% fill ratio
• 10 FSPs, 19 assets registered: BESS, district heating, reserve generators, commercial EV chargers, heat pumps
• 6 of 11 winter markets cleared zero in V2025/26
• Södra Skåne remains the dominant market (1,711 MWh awarded, 13.2% fill) but fill rate has fallen from 58.8% (V2023/24) following the October 2024 grid upgrade (+600 MW from Söderåsen–Barsebäck), which reduced the underlying congestion need
• Bålsta emerged as the second functional market at 22.7% fill (658 MWh awarded, 458 MWh activated)

E.ON’s stated target is supply of at least ~10 MW per market area — roughly 1.5–5× the stated DSO need — to generate competitive dynamics. This target is far from met in most markets.

Pricing structure — how SWITCH compensation actually works

A common misreading: the uniform prices (typically 3,000–3,500 SEK) visible across most SWITCH markets are the DSO-set availability rate (LFM-h/p capacity component), not FSP behavior. E.ON sets this rate per market per season. FSPs set the activation price (LFM-e energy component) through competitive bidding. These are two distinct compensation streams:

The availability payment is remunerated regardless of whether the DSO actually dispatches — an FSP registered for LFM-h earns the availability fee even in zero-activation seasons. This is the mechanism that makes registered supply valuable even in infrequently-activated markets.

LFM-h and LFM-p holders are obligated to participate in LFM-e dispatch, but LFM-e can also be used standalone (no availability component). (Source - Energiföretagen Förteckning Standardiserade Marknadsprodukter (2025))

Endurance: availability contracts require 1–4 hours of endurance per activation block, configurable. Lower endurance incurs stepped penalties on the availability payment but does not affect activation remuneration. This lets FSPs optimize the trade-off between LFM availability income and competing market commitments (e.g., FCR-N or FCR-D).

Zero-clearing markets: the case for staying open

The instinct to close zero-clearing markets is wrong for LFM-h markets. Three distinct “zero” situations require different responses:

For the first two cases, keeping the market open maintains the demand signal and provides an earning opportunity (LFM-h availability fee) that rewards early registrants. Closing removes both. An open market with no clearings but registered FSPs is meaningfully better positioned than a closed market when congestion materializes.

The third case (no real need) is where market existence should be questioned — but this should be confirmed by examining whether the DSO ever publishes a need, not by observing zero clearing alone.

Root causes of FSP supply shortfall

In rough order of explanatory power:

1. Geographic resource mismatch

Congestion relief only works if the flexible resource is electrically upstream of the specific constrained asset (transformer, cable) and has a non-trivial contribution at that point. BESS and new loads in E.ON’s 17 GW connection queue tend to locate where real estate is cheap or solar yield is favorable — not where the grid needs them. This is the primary explanation for markets like Bromölla-Sölvesborg, Enköping, Vaxholm, and Kallhäll having no registered FSPs: viable DER assets may not exist in the right electrical location, not just that they haven’t been recruited.

2. Exhausted local supply pool (Hässleholm)

Hässleholm (7 MW stated need, 150–300 required activation hours/year — the highest in E.ON’s portfolio) has had all obvious FSP candidates approached. The current single active FSP receives ~€1,500/MWh activation + ~€20,000/season LFM-p availability. The market is not “full” — 7 MW need vs <1 MW supplied — but the identifiable supply in that geographic area has been recruited. This is a genuine geographic scarcity problem, not a market design or pricing problem. Resolution requires either new resource types connecting in that area, using flexible connection onboarding as a supply recruitment mechanism, or accepting that grid investment must partially substitute for unavailable flexibility.

3. Actor chain fragmentation

As documented in Projekt Halland, the chain resource owner → technical controller → trader → BRP is often multiple separate entities. Each link requires a contractual and operational relationship. Without an aggregator willing to absorb this coordination cost, technically capable resources don’t become FSPs. In smaller markets and smaller towns, no active aggregator may have built this chain.

4. Multi-market opportunity cost

An FSP allocating a 1 MW battery to LFM-p receives ~€222/day in availability payment over a 3-month season (€20,000 / ~90 days). Against this: FCR-N at the Feb 2026 mean (~31 EUR/MW/h) yields ~€740/day for continuous 24-hour participation. The opportunity cost is real. However, LFM-p endurance blocks are 1–4 hours per event, not 24-hour commitments. If the block covers 2 specific morning hours, the FCR-N sacrifice is ~€62/day — making LFM-p a net gain for the FSP even before activation revenue. The actual cost depends on overlap between the LFM-p time window and the resource’s FCR commitment. Well-designed endurance block timing can substantially reduce conflict.

The key implication: at current LFM-p rates, participation is financially attractive for resources that are not fully committed to FCR markets around the activation window. The obstacle is more likely operational complexity and aggregator chain setup than pure economics.

5. Aggregator absence in smaller geographic areas

The named Swedish aggregators (Flower, CheckWatt, Ingrid Capacity, Capalo AI, Sympower) concentrate operationally where balancing market volume justifies overhead — primarily SE3/SE4 urban areas. In towns in Kronoberg, Blekinge, or northern Halland, no active aggregator may have recruited local assets. This means a DH plant or industrial load that could qualify lacks a partner to handle technical and market participation complexity.

6. Awareness and champion deficit

Palm et al. (2023) find that 9 of 10 eligible customers believe they have no flexibility to offer. The most important participation driver — identified empirically — is an internal champion: a person within the target organization who understands the concept and advocates for participation internally. Without the champion, the organization does not participate regardless of economics. E.ON’s outreach must cultivate champions, not just broadcast market rules at decision-makers. (Source - Palm et al LFM Drivers and Barriers (2023))

7. Small resource fragmentation

Heat pumps and EVs hold substantial aggregated flexibility potential but are individually 5–15 kW — far below the 0.1 MW market minimum. Accessing this supply requires an active aggregator operating in the specific grid area and willing to build the aggregation infrastructure. Without that aggregator, the potential is inaccessible.

8. Warranty and contractual barriers

Manufacturer warranties for EVs and heat pumps frequently prohibit third-party control. This is a contractual barrier, not technical — the hardware could participate, but the contract forbids it. Particularly relevant as residential EV and heat pump penetration grows.

Recommendations by dimension

A. FSP supply recruitment

A1. Aggregator-first strategy for zero-supply markets

For markets with no registered FSPs, the primary question is whether an active aggregator covers that grid area. Map the overlap between SWITCH market areas and the geographic footprints of Swedish aggregators. Where there is no aggregator presence, the supply gap cannot be filled without first bringing in an aggregator — individual resource owners will not participate without one. Target: sign one active aggregator per zero-supply market before V2026/27 season opens.

The new Dremio smart meter integration (automatic meter data fetching for FSPs on E.ON’s grid) materially reduces the onboarding cost that aggregators face. This should be front-page of all aggregator outreach — the message is “zero sub-meter installation required.”

A2. District heating as capacity anchor

Energy companies (DH, CHP, municipal utilities) provide market depth — few units but large capacity — while aggregators provide diversity. Sweco’s analysis confirms DH plants are decisive for activated volumes. Structured outreach to municipal energy companies (kommunala bolag) in each congested market area should be a priority for H1 2026 prep. The pitch is the full value stack: day-ahead optimization + LFM availability + eventually mFRR, with E.ON providing the platform.

A3. Commercial buildings as geographic fill

E.ON EIS’s Heat Flex result (~20% electricity cost reduction using building thermal inertia) is a compelling case for commercial property managers. 200 kW is currently connected against ~1 MW potential. For 2026/27, scale to 5–10 commercial sites in congested market areas. These provide smaller per-site capacity than DH but cover more substations geographically.

A4. Flexible connection onboarding as recruitment channel

New large loads connecting under Villkorade Avtal (E.ON’s 130% overbooking model) are contractually committed to curtailability. This existing relationship is a natural bridge: every villkorad anslutning candidate in a constrained area is also a potential LFM FSP. The connection approval process should include an explicit offer to register as an FSP in the corresponding market.

A5. Champion cultivation workshops

Target CFOs and facility managers — not energy executives — in industrial customers with large subscriptions in congested areas. These are the people who can authorize internal change. Give them the vocabulary and internal business case tools to advocate within their own organizations. Breakfast seminars and structured site visits to existing FSPs are more effective than information broadcasts.

B. Market design

B1. Keep zero-clearing markets open with active LFM-h

As discussed above. An open market with published availability pricing continues to recruit supply and maintains optionality for future congestion. The cost of keeping an empty market open is near-zero; the cost of closing and reopening is high (re-procurement, reputation damage with FSPs, lost lead time).

B2. Differentiate strategy by market tier

B3. Invest in Bålsta

Bålsta’s 22.7% fill rate and 458 MWh activated in V2025/26 signals real and growing structural congestion in a commuter-belt area north of Stockholm. This is where the next Södra Skåne could develop. For 2026/27: increase the LFM-h/p availability rate to attract more FSPs, raise the procurement volume target, and run active aggregator recruitment in the Uppsala-Stockholm corridor.

B4. Extend Projekt Halland based on internal results

BeFlexible D5.4 (Halland summer 2025 outcomes) will not be publicly released — E.ON holds this data internally. The go/no-go decision on market extension will therefore be an internal one. If E.ON’s internal data confirms viability:

• Extend the season to May–October (solar peaks in May and September are substantial)
• Add LFM-p seasonal availability contracts for large solar and wind parks that want revenue certainty beyond direct orders
• Identify the next production-market area using the DNDP county-level production capacity ratings (C-rated counties with high solar/wind concentration)

B5. Design a firm-cap (operating-envelope) product — corrected for the baseline objection

E.ON’s hesitancy toward capacity-limit products is well-founded: in naive designs baselining creeps back (the value is benchmarked against a historical-consumption reference — a counterfactual), and “what are we paying for” is unanswerable when the cap may never bind. The Swedish record on NODES MaxUsage™ is genuinely mixed, not a simple cautionary tale: it succeeded and scaled at Effekthandel Väst (the dominant activation product by volume from Dec 2024) but was discontinued at Kinnekulle Energi — for reference-baseline drift and tariff-redundancy, not because the cap concept failed (Source - Effekthandel Väst Produkter och MaxUsage (NODES, 2024)). The corrected design below keeps what works and fixes the drift, and fits the existing TO/DO architecture:

1. Anchor the cap to firm contractual capacity, not a forecast baseline — but understand what the subscription actually is. Abonnerad effekt is a commercial/billing cap: a customer who exceeds it pays an överuttagsavgift, but is not physically cut off. So the product procures one of two things, neither of which is “capping something already capped”: (a) soft → firm — converting the soft commercial cap into a hard, real-time-binding ceiling at C = S, so the DSO gets certainty the customer will not overdraw during the risk window (and that overdraw is precisely what threatens the node); or (b) a reduced ceiling C < S, procuring the surrendered headroom (S − C), where staying under C requires active load management — and that management is the delivered flexibility. The congestion constraint is on aggregate node flow; subscriptions sum (with diversity) to more than the transformer can safely carry at coincident peak, so firm caps restore the margin without reinforcement. Verification is direct metering against C — no counterfactual at settlement.

2. Name the procured object — firm headroom / reinforcement deferral, priced as an option premium. Benchmark the availability fee against avoided reinforcement (the ~4 SEK/kW transformer reference, Distribution Network Development Plan › DNDP digitalization and automation) or the överuttag/överliggande abonnemang cost. This answers “what are we paying for”: certainty that aggregate node load stays under the N-1 limit during forecast-risk windows. It is insurance; pricing it as insurance dissolves the confusion.

3. Set the strike level with the high-CI forecast. Offer the product only on node-windows the P90/P95 forecast flags as congestion-risk, and set C where it is expected to bind only in those hours. This is the direct cure for the MaxUsage “paid for a cap that never binds” failure — and it ties the product to the same high-confidence-interval STLF E.ON already runs for order generation (see STLF for Flexibility Markets — What Counts as Good and How to Achieve It).

4. Settle on cap-compliance, not energy-delta. Delivery = “metered net offtake stayed ≤ C for the window” (binary/duration check), with pro-rata penalty or availability clawback on breach. No baseline, no 75% energy-delta threshold — recalculable and manipulation-resistant, since a hard meter cap cannot be gamed the way a baseline can. This would be a third SWITCH product type alongside TO (availability) and DO (direct) orders.

5. Scope by node type — using the actual congestion-point sizes. Firm-cap products fit the concentrated 15–50 MW/MVA transformer nodes with a few large customers, where a clean per-customer cap is possible. Keep energy / merit-order products (LFM-e) for the large diffuse constraints (Södra Skåne ~800 MW) where a single aggregate cap must be allocated across many contributors and a genuine energy event is being managed.

The honest caveat — and why E.ON’s “baselining creeps back” instinct is half-right: capacity-limit products eliminate the counterfactual from settlement and verification (a hard metered ceiling), but not from valuation/targeting (whether a cap is worth buying still depends on whether load would have exceeded C). The corrected design does not escape the counterfactual — it relocates it from per-activation settlement (adversarial, gameable, per-FSP) to once-per-node targeting (forecast-driven, at the buying decision). That is the same relocation logic as the high-CI forecast itself, and it is why the cap product’s integrity depends on forecast quality rather than on baseline policing.

How this differs from MaxUsage™. Two clarifications first, because MaxUsage is closer to good design than a “cautionary tale” implies: its cap is set jointly with the DSO (not FSP-nominated), and it is window-targeted to the DSO’s known critical hours (e.g., Renova 07:00–10:00) — both via grid experience (Source - Effekthandel Väst Produkter och MaxUsage (NODES, 2024)). So the compliance-based settlement (shared — no per-event baseline) and the DSO-set, time-windowed structure are not the differences. The genuine improvements are two:

• The reference anchor (the real one). MaxUsage benchmarks value against a historical-consumption reference (Renova ~300 kW; GKT 450 kW), which drifts as efficiency and behaviour change — the documented reason it failed validation and was dropped at Kinnekulle. Anchoring instead to the firm contractual level (abonnerad effekt, firm or reduced) gives a stable, DSO-owned reference that does not drift.
• Formalized targeting. MaxUsage picks the critical window from grid experience; B5 sets it from an explicit high-CI forecast, making the “where does the cap bind, and is it worth buying” decision systematic rather than judgemental — tightening the cure for the “paid for a cap that never binds” failure.

The shared virtues (joint DSO setting, time-windowing, clean cap-compliance settlement) are kept; the drift failure is fixed. The residual dependency is forecast quality at targeting — a better-controlled risk than chasing a drifting historical reference, and one E.ON already carries via its order-generation forecast.

Economic caveat on the C = S variant — it is usually a tariff question. The firm-at-S product has an awkward cash flow: today an overdraw earns the DSO an överuttagsavgift, so paying an FSP to firmly not overdraw means forgoing that revenue and paying an availability fee — a profit-to-cost flip. It is justified only when (a) reinforcement-deferral value exceeds (forgone överuttag revenue + availability payment), and (b) the DSO needs firmness, not merely deterrence — because the fee penalises overdraw ex post but does not physically prevent it, and a deferral decision cannot be underwritten against “they will probably pay the fee and probably not overdraw too much.” Where neither condition holds, the superior lever is implicit: reprice the överuttagsavgift to bite in forecast-flagged congestion hours (a condition-differentiated overdraw penalty), which deters the behaviour while staying revenue-positive — squarely within the live effektavgift reform (Source - Ei Effektavgifter webb (2026)). A firm cap at C = S and a condition-differentiated overdraw penalty are two prices for the same behaviour: one pays the customer, the other charges them — prefer the latter unless a contractual guarantee is genuinely required. The upshot: C < S is the real explicit-market product (new headroom below entitlement, no overdraw-fee flip; cost is purely the availability payment against deferral), while C = S is a tariff-design question wearing a market-product costume — reach for it only when the tariff route is blocked or firmness must be contractually guaranteed.

This is not just theory: Kinnekulle Energi dropped MaxUsage partly because time-differentiated tariffs (EIFS 2022:1) will deliver the same load-shifting signal market-wide for free — a Swedish DSO independently concluding that the tariff lever dominates the explicit cap product for exactly this behaviour. (Source - Effekthandel Väst Produkter och MaxUsage (NODES, 2024))

C. Pricing calibration

C1. Audit availability rate levels per market

The DSO-set availability rate is the primary tool for attracting FSP registrations. If markets are empty despite real need, the rate may be too low relative to the opportunity cost of committing endurance capacity. Review each market’s rate against local FCR-N/FCR-D revenue benchmarks and the endurance block structure. Hässleholm’s rate (implied by the ~€20,000/season figure) demonstrates willingness to pay substantially; other markets at the uniform 3,000–3,500 SEK may be underpriced for their specific congestion profiles.

C2. Publish indicative activation willingness-to-pay per market

FSPs bidding activation prices report not knowing what to bid. Publishing a reference range (historical average, or a stated ceiling) per market gives FSPs a price anchor, reduces strategic uncertainty, and helps competitive pricing develop. ~40% of European LFMs already publish such indications. This is a unilateral E.ON decision, no regulatory change required.

D. TSO-DSO coordination and NC DR

D1. Engage actively in Ei’s NC DR T&C development (2026)

Ei’s T&C process starts 2026. E.ON has more operational LFM experience than any other Swedish actor. Key positions to advocate:

• Confirm 0.1 MW minimum bid size (already working in practice)
• Lock in the D-2 10:30 trading time that enables BRP coordination by aggregators — this was a hard-won operational fix that should be the national standard
• Push for market-based procurement as the default (matching Art. 29 NC DR) so DSOs like Vattenfall cannot structurally opt out

D2. Prepare for FIS integration

The centralt datahanteringsverktyg (DHV/FIS) proposal is due September 2026. The FIS will eventually handle SP qualification, registry, and settlement across markets. Ensure SWITCH’s qualification data structures (FSP records, resource specs, prequalification status, sub-resource categories already being updated for NC DR) map cleanly to the expected FIS schema before the schema is finalized, not after.

D3. Model mFRR forwarding feasibility under EAM

The mFRR EAM (launched March 2025) moved the MTU to 15 minutes and automated activation. This significantly improves timing compatibility between SWITCH local markets and Svk’s mFRR market compared to the CoordiNet-era attempt. The NC DR T&C process will define the formal coordination mechanism. E.ON should commission a feasibility analysis of sequential bid forwarding under the current EAM architecture and submit it as evidence during T&C development.

E. Effekttariff interaction

The mandatory effekttariff deadline under EIFS 2022:1 (previously set for January 2027) has been repealed — Ei was tasked with developing a replacement model, with a new proposal due April 2027. There is no hard Jan 2027 cliff. (Source - Ei Effektavgifter webb (2026))

However, demand tariffs remain permissible and some DSOs (Göteborg Energi) are already running pilots. The structural double-edge is real: when a battery or heat pump provides explicit flexibility (LFM activation) and compensates by charging/heating immediately before or after, the compensation peak can trigger a demand tariff charge that erodes the activation revenue. This is particularly acute for resources participating in both implicit (tariff-shaped) and explicit (market) flexibility.

For 2026/27: monitor which current FSPs are subject to voluntary effekttariff schemes in their grid area; model the net impact on their activation economics before the season opens. If net impact is negative, adjust activation scheduling or compensation. Track the Göteborg Energi dual-tariff pilot — if it proves effective at separating the tariff and explicit-flexibility incentive structures, advocate for adoption in E.ON’s own grid and in Ei’s replacement model process.

F. BSP transition preparation (target: ready for 2028)

The independent BSP role (cross-BRP aggregation) is deferred to 2028. FlexAbility DR5 estimates +300 MW could enter the market immediately if BSP removes the BRP coordination friction. One aggregator reports spending 50% of working time on BRP management. (Source - FlexAbility Delrapport 5 (2025))

The bottleneck today is the low number of FSP resources, not the qualification process. But supply growth before 2028 and the ability to absorb the BSP-enabled surge are related: aggregators who are already operating on SWITCH markets in 2026/27 will scale faster when BSP launches than aggregators who have to start from zero.

For 2027/28: identify aggregators with technically qualified resources who are not participating today due to BRP friction; establish preliminary relationships and provisional resource records; ensure SWITCH’s DIS qualification process can handle a substantially larger intake than the current 10-FSP/19-asset base.

What E.ON cannot control

For completeness: the structural barriers outside E.ON’s direct action are:

• Intäktsreglering / TOTEX: Ei’s RP5 reform (effective 2028) is the fix for the “charity” DSO incentive problem. Until then, flex procurement earns no regulated return on capital.
• BSP role: Svk’s timeline, deferred to 2028.
• FIS / datahanteringsverktyg: Ei + Svk’s infrastructure, proposal due September 2026.
• NC DR entry into force: affects prequalification harmonization, FIS, and coordination standards.

These are the ceiling on how far market growth can go regardless of E.ON’s actions. The recommendations above are specifically within E.ON’s operational authority.

Related pages

• SWITCH — platform mechanics, product structure, market data
• E.ON Energidistribution — grid coverage, DNDP flexibility needs, BeFlexible outcomes
• Flexibility Market — EU framework, Swedish landscape, FSP barrier analysis
• Aggregation — BSP delay, cross-BRP friction, NC DR qualification pathways
• Why Swedish Local Flex Markets Are Thin — Structural Causes — structural root causes
• E.ON SWITCH Three-Year Strategic Plan — broader strategic framing
• Villkorade Avtal — connection mechanism doubling as supply recruitment channel
• Network Code on Demand Response — T&C process, FIS, harmonization