Source - FlexAbility Delrapport 5 (2025)

“Målkonflikter och hinder för flexibilitet” (Barriers and conflicts for flexibility). FlexAbility sub-report 5 (of 5). Power Circle + Uppsala University PhD candidate (Linn Söderberg), November 2025. 52 pages.

Funded by Energimyndigheten as part of the FlexAbility research programme. Final sub-report in the series; the others cover technical potentials (DR1), market economics (DR2), DSO value cases (DR3), and household acceptance (DR4).

Method

• 60 qualitative interviews (spring 2024 and autumn 2024) across all actor groups: DSOs, TSO, aggregators, industry, residential actors, regulators, platform operators, and energy researchers
• Follow-up workshop (spring 2025): approximately 15 participants from the interview pool; reflected on what had improved or deteriorated since the first round of interviews; ranked barriers by importance
• Approximately 250 barriers and conflicts identified, organized into 3 main areas and 11 sub-categories

Not a quantitative study — findings represent qualitative consensus and actor-reported experience, not statistical inference.

Three main areas and sub-categories

Area 1: Market design and economics

1. Market coordination and market design
2. BSP (Balance Service Provider) role
3. Standardization
4. Effekttariffer (demand tariffs)
5. Implicit flexibility risk
6. Retailer compensation for aggregated resources

Area 2: Rules and leadership

7. Revenue regulation (intäktsreglering) and DSO role
8. DSO risk culture and connection processes
9. Knowledge gaps and information asymmetry
10. Leadership and coordination vacuum

Area 3: Interest conflicts and environment

11. Alternativkostnad (opportunity cost) and wear

Key findings by sub-category

Market coordination

Competition between local flexibility markets and TSO balancing markets is a structural tension, not an anomaly. The preferred solution — TSO-DSO integrated market with forwarding of unsold bids — was tested in CoordiNet (mFRR forwarding) but never fully operationalized. The planned sthlmflex test of mFRR forwarding was never conducted before the market closed.

International models cited as more mature: Finland and Denmark (integrated TSO-DSO procurement), Canada and UK (integrated markets for demand-side resources). Swedish market actors describe the current state as coordination without architecture.

50% of active flexibility providers report increased interest in participating in Nord Pool (wholesale market) as an alternative to flex markets — an indication that the local flex market value proposition is competing unfavorably with national market participation.

BSP (Balance Service Provider) role

The single most frequently cited and emotionally charged barrier. Background:

• EBGL (Electricity Balancing Guideline, Regulation 2017/2195) required BSP role by December 2020
• Svk’s May 2024 “implementation” is described by market actors as a “paper construction” — formal compliance without operational substance
• Full BSP implementation now deferred to 2028

Workshop finding: BSP absence ranked as the worst deterioration among all barriers between the two interview rounds (spring 2024 → autumn 2024). No other barrier deteriorated more.

Quantified impact: one aggregator with ~500 MW of qualified flexibility resources reports spending 50% of their working time on BRP management — coordinating separately with each Balance Responsible Party whose customers they represent. The cross-BRP problem means an aggregator managing resources across 10 electricity suppliers must run 10 separate administrative processes instead of one.

Estimate: an independent BSP role with proper cross-BRP aggregation infrastructure would allow +300 MW to enter the market immediately — resources that are technically qualified but effectively locked out by administrative friction.

This barrier is directly linked to the pending centralt datahanteringsverktyg (compensation for independent aggregation is a named use case) and the Network Code on Demand Response (which includes standardized settlement rules for demand response across BRP boundaries).

Standardization

International aggregators (particularly those operating across multiple countries) report that Sweden’s non-harmonized products and prequalification processes are a competitive disadvantage relative to Finland, Denmark, and Norway, which have moved further toward Nordic-level harmonization.

FSPs want: single prequalification valid across multiple flex markets and TSO products, identical activation formats, harmonized products. NC DR expected to help. Swedish multi-DSO proposal (LFM-h/LFM-p/LFM-e) submitted to Ei in 2024 is a domestic step toward this.

Workshop: standardization ranked #4 barrier (16 pts), tied with BSP absence. Noted as having improved since spring 2024 — the NC DR process and the Swedish DSO product proposal have created momentum.

Effekttariffer (demand tariffs)

Mandatory by January 2027 (EIFS 2022:1). Correctly provides price signals encouraging demand flattening. But creates a structural double-edge:

• When electricity spot price is low (e.g., midday solar peak), consumers should be encouraged to charge EVs and batteries — load is cheap and beneficial for the system. But the demand tariff still applies to peak demand, creating a conflicting signal: economic optimum is to charge, but peak tariff punishes peaking behavior.
• This conflict undermines the intended coordination between spot price response (implicit flexibility) and tariff response.

Göteborg Energi Nät is testing a dual-tariff model to address the conflict — separating the incentive structures for spot-price response and capacity management.

API access requirement: aggregators and resource controllers need API access to real-time tariff data to automate responses. This is not standard in Sweden; market actors report delays and difficulty in obtaining consistent tariff data feeds.

Implicit flexibility risk

A structural risk not yet fully addressed in Swedish or EU policy. When large numbers of households respond to the same spot price signal simultaneously, the aggregate load shift is large but unpredictable by BRPs — the BRP contracted to serve these households cannot accurately forecast their consumption when they’re all responding to market prices.

This drives up TSO balancing costs: Svk must cover unexpectedly large imbalances. At sufficient scale, implicit flexibility creates a systemic balancing problem even while it benefits individual prosumers.

Elforsk 2013 study (cited): breakpoint estimated at 100,000–700,000 simultaneously responding households. Below this threshold, implicit flex creates no systemic problem. Above it, TSO balancing market costs rise significantly.

Nord Pool market design may require reform to address this — the current hour-ahead settlement and day-ahead price signal creates synchronous response patterns. No clear Swedish or EU policy response exists yet.

Retailer compensation for aggregated resources

When an independent aggregator activates resources in a customer portfolio, the customer’s BRP is typically left with an imbalance it did not forecast. Under EU law (Clean Energy Package), member states may implement compensation mechanisms — the aggregator pays compensation to the affected BRP, funded from the revenue earned by the activation.

Sweden has not yet implemented a retailer/BRP compensation mechanism. This creates friction: BRPs resist losing control of customer resources when they face uncompensated imbalance exposure.

Implemented models in neighboring countries:

• Finland/Denmark: Fingrid and Energinet directly compensate BRPs when DR activations create imbalances
• UK: “net benefit model” — aggregator retains net revenue after compensating all affected parties

The pending centralt datahanteringsverktyg names BRP compensation as a required function (“kompensation vid oberoende aggregering”). This is the infrastructure prerequisite.

Revenue regulation (intäktsreglering) and DSO role

Workshop ranking: #1 barrier — intäktsreglering and DSO role received 38 points, far ahead of #2 (marknadsutformning, market design, at 21 points). Every single DSO interviewed cites intäktsreglering as a barrier.

The core problem: DSOs running flex markets describe procurement cost as “välgörenhet” (charity) — they get 1:1 cost coverage for flex procurement but earn no regulated return on capital. Under the current CAPEX-biased regulation, grid investment is rewarded and opex flexibility procurement is not.

Ei’s TOTEX proposal (spring 2025) is viewed positively by market actors — seen as the right direction. But it takes effect from 2028 and full impact will not be felt until the 2028–2031 period.

DSO role ambiguity: unbundling rules make DSOs cautious about engaging customers proactively in flexibility services. The legal line between passive market facilitation and active customer recruitment is unclear, and DSOs report being advised by legal counsel to avoid customer contact that could be construed as market participation on their own behalf.

DSO risk culture and connection processes

N-1 deterministic methods: the electricity grid is identified as the only major infrastructure industry not using probabilistic risk assessment methods. Every other engineering domain (aviation, pipelines, civil structures) uses probabilistic methods that accept some small risk of failure in exchange for more efficient design.

Swedish grid planning uses deterministic N-1 standards: the grid must be capable of handling any single component failure at full load. This drives systematic overcapacity relative to probabilistically optimal design.

International comparison: TenneT (Dutch/German TSO) freed 9 GW of congested capacity by introducing flexible connection terms — new connections are granted with the condition that supply can be curtailed during N-1 events. Some EU countries mandate >100% connection (“overconnection”) through probabilistic planning. Swedish ellagen would need revision to permit this model.

Connection queue dynamics: E.ON alone has 17 GW of battery storage in its connection queue. Structural problem: batteries seeking grid connection often want to locate where real estate is cheap or solar resources are high — not where the grid congestion actually is. This “placement mismatch” means the queue doesn’t align with the problem locations.

Catch-22 for existing customers: industrial customers with a large grid subscription (abonnemang) cannot easily reduce it to a lower level reflecting actual maximum demand — if they do, they may not be able to get it raised again when production expands. Simultaneously, DSOs can’t easily procure peak-shaving flexibility from customers who can’t commit to a reduced subscription. Each party’s risk aversion blocks the efficient outcome.

Knowledge gaps and information asymmetry

Survey finding: 9 out of 10 customers believe they have no flexibility to offer, but in reality do. This is not a lack of interest — it is a lack of visibility into what their assets can provide.

Barriers:

• Service agreements and warranties: manufacturers’ warranties for EVs and heat pumps often prohibit third-party control or aggregation. This is a contractual barrier, not a technical one.
• Knowledge within large organizations: SVK (utility) interviews revealed an internal disconnect between commercial and technical divisions — the commercial side was unaware of what the technical side was doing on flexibility, and vice versa.

Leadership and coordination vacuum

No actor has a mandate to coordinate flexibility across energy carriers (electricity, district heating, natural gas). Each sector is regulated separately, but an optimized flexibility system would coordinate across them — e.g., a district heating plant that can switch between electricity and biomass should be coordinated with the electricity DSO’s congestion forecast.

The unbundling rules that protect competition and prevent cross-subsidy also prevent DSOs from engaging in the customer-facing coordination activities that would build awareness and supply.

Workshop finding: Ei and Svk were identified as the most responsible actors for resolving the identified barriers — they received the highest assignment of responsibility. This signals market actors expect regulatory initiative, not market-led solutions.

Two-thirds of participants (workshop) report that market coordination has improved since spring 2024. This is one of the few areas that improved.

Alternativkostnad (opportunity cost) and wear

Industry perspective: energy cost is approximately 5–6% of total production cost for most Swedish industrial flexibility providers. The primary cost driver is production output. Any flexibility activation that disrupts production quality carries a risk cost that may be 10–50× the direct energy cost.

Lean production philosophy (broadly adopted in Swedish manufacturing) explicitly minimizes input variability — the opposite of what flexibility participation requires. Flexibility means deliberately creating variability in energy input.

PPA (Power Purchase Agreement) lock-in: industrial customers with long-term fixed-price PPAs have no spot price exposure. They gain nothing from flexibility activations priced against the spot market. Their participation is structurally blocked regardless of the market price signal.

EV fleet operators: charging delay conflicts directly with customer promise — a fleet operator promising overnight charging cannot offer flexible curtailment without compensating (or risking) driver satisfaction.

FCR-D wear cost escalation: a September 2023 technical requirement change by Svk increased the number of required FCR-D activations for industrial and battery participants from approximately 60/year to approximately 3,000/year. For battery systems, this 50× increase in activation cycles creates significant wear on battery cells. For industrial processes, this frequency of activation makes FCR-D participation essentially incompatible with production schedules.

Aggregator-asset owner conflict: an aggregator managing a third-party battery earns revenue from FCR-D activations but does not directly bear the battery degradation cost. The asset owner bears the wear. This misalignment of incentives means aggregated battery portfolios in FCR-D may be operated more aggressively than the asset owner would prefer — a moral hazard problem with no standard contractual resolution.

Environmental conflicts

Battery lifecycle: increased flexibility activation cycles accelerate battery degradation, shortening battery lifetime and increasing replacement frequency. From a full-lifecycle emissions perspective, a battery that is activated very frequently for balancing may not deliver the net carbon benefit assumed in policy calculations.

“Green flex” concept: emerging market actor interest in certifying that flexibility services come from assets with favorable lifecycle profiles (renewables-based, low wear, no fossil backup). Not yet standardized.

Fossil reserve power on local flex markets: some local flex market participants use diesel or gas-fired backup generators as their flexibility resource. From a system operator perspective this is technically valid; from a sustainability perspective it creates perverse incentives.

Hydro flexibility vs ecosystem: hydro power is the backbone of Nordic balancing. Increasing the ramping rate and frequency of hydro flexibility activation conflicts with ecosystem requirements (minimum flow, temperature stability, sediment transport). Regulatory limits on hydro flexibility are binding in some catchments.

Workshop findings (spring 2025)

~15 participants from the interview pool.

Change since spring 2024

Barrier ranking (prioritization exercise)

Who is most responsible for resolving barriers: Ei and Svk — assigned highest responsibility by participants.

Mood: approximately 40% describe themselves as “somewhat more hopeful” than before; 50% report increased interest from their own organizations in Nord Pool participation.

Five policy recommendations (conclusions chapter)

1. Implement TOTEX reform — as Ei has proposed for RP5 (2028–2031); critical that it genuinely creates lösningsneutralitet (solution neutrality) between grid investment and flexibility procurement; must not penalize proactive grid building
2. Introduce BSP role as fast as possible — the infrastructure prerequisite for cross-BRP aggregation; described as the most damaging delayed reform; the datahanteringsverktyg must be designed to enable this
3. New DSO working methods: simplify connection processes, publish grid needs transparently, provide API access to network tariffs — requires regulatory guidance on what DSOs are permitted and encouraged to do without unbundling conflict
4. Better price signals and product harmonization: effekttariffer design must be resolved (dual-tariff model or equivalent), NC DR product harmonization accelerated, LFM-h/p/e standardization formalized
5. Stronger leadership and cooperation between Ei, Svk, and government: no single actor can solve cross-carrier coordination; Ei and Svk must take lead roles; suggests a national flexibility roadmap or coordination function

What’s new for the wiki

Extends and deepens existing wiki content on:

• BSP role absence (already in Aggregation, but now with 2028 deferral, 50% time cost, and +300 MW estimate)
• CAPEX bias / “charity” finding (already in Flexibility Market and synthesis, now supported by interview data from all DSOs)
• FCR-D wear cost: new; not previously documented
• Implicit flex risk at scale: new; not previously documented
• Effekttariffer double-edge: new context; not previously documented
• Connection Catch-22: new; not previously documented
• N-1 probabilistic methods gap: new; not previously documented
• Retailer/BRP compensation: new; related but separate from aggregation infrastructure already documented

Workshop ranking provides empirical evidence confirming the synthesis page analysis: intäktsreglering (#1), market design (#2), BSP (#3), standardization (#4) — consistent with FlexAbility DR2 analysis and Sweco’s interview findings.

Relevance to wiki pages

• Aggregation — BSP 2028 deferral, 50% time cost, +300 MW, retailer compensation models, wear cost conflict
• Balancing Markets — FCR-D wear cost escalation (60→3,000 activations), implicit flex risk
• Demand Response — implicit flex risk at scale, effekttariffer double-edge
• Flexibility Market — “charity” finding, connection Catch-22, Göteborg Energi dual-tariff
• Svenska kraftnät — BSP delay, internal disconnect, most responsible actor assignment
• Ei — workshop ranking, TOTEX seen positively by market actors, most responsible actor
• Why Swedish Local Flex Markets Are Thin — Structural Causes — multiple new evidence points across all eight causes