Source - FlexAbility Delrapport 3 (2025)

Full title: Det ekonomiska värdet av flexibilitet för lokala elnät (The economic value of flexibility for local electricity grids)

Part of: FlexAbility — sub-report 3 of 5

Authors: Plexigrid and Ellevio, coordinated by Power Circle

Funded by: Energimyndigheten (Swedish Energy Agency), project FlexAbility

Date: October 2025

Length: 42 pages

Related reports: Source - FlexAbility Delrapport 1 (2025), Source - FlexAbility Delrapport 2 (2025)

Summary

The third FlexAbility report quantifies the economic value of flexibility for DSOs (elnätsföretag) operating local distribution grids. Unlike Delrapport 1 (which mapped flexibility resources and needs) and Delrapport 2 (which covered market and tool development), Delrapport 3 focuses on the DSO’s own cost calculation — the value side of the flexibility procurement decision.

The report presents four case studies based on real Ellevio network data, then draws regulatory conclusions about why the CAPEX bias in current regulation prevents these economically sound cases from being acted upon.

Study 1: Utnyttjandegrad — regulatory incentive analysis (Station A)

Background

EIFS 2023:6 introduced utnyttjandegrad (utilization rate) as a metric in Swedish intäktsramsreglering. It is defined as:

Utnyttjandegrad = daily average power demand / average of the four highest daily peak demands (in the same period)

A higher utnyttjandegrad indicates more efficient use of the grid connection to the overlying network. The regulator (Ei) uses this metric to adjust the DSO’s revenue cap — low utilization rates trigger a revenue penalty (negatively adjusts the income ceiling).

Case study data (Station A, 2023)

• Normvärde (2020–2021 reference period average): 44.02%
• Actual utnyttjandegrad 2023: 38.88%
• Revenue cap penalty: −924,000 SEK/year

The gap between normvärde and actual is caused by a few very high peak demand days inflating the denominator while average demand remains lower. Flexibility that reduces these peaks — without reducing total energy throughput — directly improves utnyttjandegrad.

Quantified value

A 20 MWh intervention (flexibility activation during peak demand hours) was modeled across all hours of 2023 to assess its impact on utnyttjandegrad and the associated revenue cap effect:

• Average value: 10,711 SEK/MWh
• Range: 0–40,000 SEK/MWh (depending on hour — only interventions that reduce the four highest daily peaks have any effect)

This makes utnyttjandegrad one of the highest-value flexibility use cases for DSOs — but extremely timing-sensitive. Only a small number of hours have any value at all; interventions during most hours are worthless for this metric.

Limitations noted

• The incentive measures utilization at the border point (connection to overlying grid) only — it does not directly measure internal grid stress
• This creates an imperfect signal: a DSO could theoretically improve utnyttjandegrad without improving grid capacity management
• The 20 MWh modeling assumes a fixed intervention size; actual optimization would target only the highest-impact hours

Study 2: Abonnemangsoptimering — subscription optimization (Stations A and B)

Background

Swedish regional DSOs pay Svenska kraftnät (Svk) a subscription fee (abonnemang) for guaranteed access to the transmission grid. The fee structure:

• Base fee: 195,000 SEK/MW/year for subscribed capacity
• Overage penalty: 390,000 SEK/MW (2024), reduced to 292,500 SEK/MW (2025) for capacity above the subscription level during peak hours

If a DSO’s actual demand consistently falls below its subscribed level, it is over-subscribing and paying too much. If demand frequently exceeds the subscription level, it faces overage penalties. Flexibility can be used to reduce actual peak demand — allowing the DSO to reduce its subscription to Svk, saving the subscription fee for the reduced MW.

Case studies

Station A (current subscription: 55 MW): Station B (current subscription: 59 MW):

The analysis computes, for each station, the marginal value per MWh of flexibility used to cut peak demand and enable a subscription reduction:

The marginal value curve is steep and declining rapidly. The first MW of subscription reduction has extraordinary value; each additional MW has less value as the hours where the subscription limit is relevant become less critical.

Optimal subscription levels (at a flexibility procurement cost of 10,000 SEK/MWh):

• Station A: reduce from 55 MW → 51 MW (−4 MW); annual savings at 10,000 SEK/MWh: ~712,000 SEK
• Station B: reduce from 59 MW → 57 MW (−2 MW); annual savings at 10,000 SEK/MWh: ~482,000 SEK

Sensitivity analysis (at 5,000–10,000 SEK/MWh flex cost range):

Important caveat

The report notes that local savings from abonnemangsoptimering may not translate to system-level benefits. The peak demand that triggers the subscription is real — if it is avoided through flexibility (shifted to another time), the question is whether the system as a whole benefits, or whether costs are simply shifted to Svk or other parties. The report flags this as an open research question requiring further study.

Study 3: Alternativkostnad — bus depot investment deferral (Station C)

Network configuration

• Existing substation: two 20 MVA transformers
• N-1 capacity: 28 MVA (one transformer can carry the full load when the other fails)
• Planned new load: electric bus depot, 8.7 MW (planned connection 2028)
• Problem: bus depot would push demand above N-1 capacity during peak periods

Traditional solution

Upgrade transformers from 2×20 MVA to 2×25 MVA:

• Investment cost: ~22 MSEK

Flexibility alternative

Using Plexigrid’s platform, the report built an hourly demand forecast through 2034, including the bus depot load. Key finding:

The N-1 capacity of 28 MVA is exceeded only 4 hours per year after the bus depot connects.

Total excess energy requiring flexibility: 2.6 MWh/year

Flexibility procurement cost: 2.6 MWh × 10,000 SEK/MWh = 26,000 SEK/year

45-year net present value comparison

At WACC 4.53% over 45 years:

The CAPEX bias problem (explicit)

Despite the overwhelming economic case for flexibility, the report identifies the regulatory barrier:

• The 22 MSEK investment is CAPEX — it earns a regulated return (WACC × asset base) over the asset’s lifetime under the current intäktsramsreglering
• The 26,000 SEK/year in flexibility procurement is OPEX — it is subject to Ei’s cost efficiency benchmarking with no regulated return

A DSO that builds the 22 MSEK substation upgrade earns a return on that capital for 40+ years. A DSO that buys flexibility and defers the investment earns nothing on that decision — and is at risk of being benchmarked as inefficient if its OPEX is high relative to peers who built grid.

This case makes the CAPEX bias empirically concrete: the economically correct answer (flexibility, NPV ~1.2 MSEK) loses to the regulatory correct answer (grid investment, NPV ~22 MSEK) under current regulation.

Generalized transformer upgrade cost table

To generalize beyond the single case study, the report computed upgrade costs for 29 transformer configurations using Ei’s normprislista (standard price list). Results:

Rule of thumb derived:

1 MW of grid upgrade capacity = 100–200 hours of flexibility at 5,000–10,000 SEK/MWh

This generalizes the alternativkostnad methodology: for any transformer upgrade under consideration, the DSO can estimate how many hours of flexibility per year would need to be procured at market prices to justify deferral.

Study 4: V2G impact on LV distribution networks (Monte Carlo simulation)

Study design

Goal: Assess how increasing penetration of V2G-capable EVs and rooftop solar PV affects an LV residential distribution network when V2G is activated for FCR-D service (upregulation).

Study area: Stockholm suburb (kranskommun till Stockholm)

• 2,019 customers
• Residential LV network (low voltage distribution)
• Network data from Ellevio

Platform: Plexigrid’s network simulation platform

Method: Monte Carlo simulation

• EV and PV penetration modeled from 10% → 100% in steps of 10%
• Temporal clustering to select four representative weeks (captures seasonal variation)
• Probabilistic hourly profiles for EV availability and V2G/PV activation
• FCR-D expected activation: ~58.4 hours/year

Threshold criteria (binding constraints)

Results — Stockholm suburb (main study)

All binding constraints occurred on weekends in Q3 (July–September): the combination of low residential load, high solar production, and FCR-D-driven V2G export creates a perfect storm for the LV network.

The Stockholm suburb network proved highly resilient — constraints only emerge at 80–90% EV+PV penetration, well above any near-term deployment scenario.

Reference comparison — southern Sweden

For comparison, the report used a prior Plexigrid study of an LV network in southern Sweden:

• 192 customers, five feeder cables from a transformer in a residential area (villa area)

The southern reference area reached constraints at 30–40% penetration — less than half the Stockholm suburb threshold. The difference is attributed to transformer and cable dimensioning: the southern network has less thermal headroom.

Key conclusions from V2G study

1. Results are highly network-specific: a 2.7× range in constraint thresholds (30% vs 80% for substation overload) between two Swedish LV networks shows that national-level V2G policy must be underpinned by per-network analysis
2. Q3 weekends are the critical window in both networks: the combination of high solar, low load, and FCR-D activation creates the worst conditions
3. V2G without smart charging coordination risks destabilizing LV networks while stabilizing the transmission network — the opposite of the intended outcome
4. Reverse power flows at 10% penetration (both networks): even low DER penetration introduces bidirectional power flows requiring updated protection and control systems
5. Planning tools must handle uncertainty: deterministic grid models miss the stochastic nature of EV behavior, FCR-D activation timing, and load variability

Conclusions

The report draws five high-level conclusions:

1. Flexibility is a cost-effective alternative to grid investment

The case studies confirm flexibility can defer or replace investment. Forecast quality is critical: without granular hourly load forecasts, flexibility risks being more expensive or insufficient to replace capacity.

2. Current regulation does not incentivize efficient grid use

The CAPEX-biased intäktsramsreglering favors building grid over procuring flexibility. TOTEX reform (planned for RP5, 2028–2031) is necessary to create lösningsneutralitet (solution neutrality).

3. TOTEX reform must not penalize proactive grid building

The report explicitly qualifies the TOTEX reform push: a TOTEX model must be designed so that proactive grid investment — building capacity ahead of demand to meet society’s expectation of a future energy system — is not penalized. Pure cost efficiency benchmarking risks discouraging necessary anticipatory investment. This is a nuance rarely stated explicitly in the flexibility literature.

4. Abonnemangsoptimering creates local savings — system benefit is uncertain

Subscription optimization generates clear savings for the DSO (up to 712,000 SEK/year in the case studies). Whether these savings represent genuine system benefits or merely cost redistribution (from DSO to Svk or others) requires further study.

5. Cross-level flexibility interactions are understudied

When flexibility is activated in the regional or transmission grid, effects on local LV grids can be positive or negative. The V2G study demonstrates this: FCR-D activation (transmission-level service) creates local grid stress. Systematic study of these cross-level effects is needed to correctly value flexibility’s total societal benefit.

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