DSO Flexibility Valuation — Methods and Swedish Evidence

Central question: what is flexibility worth to a DSO, and how should that value be calculated? The question matters because a DSO that cannot quantify the value of flexibility cannot rationally decide how much to pay for it — and consequently either over-pays (destroying value) or refuses to procure at all (blocking markets). Sweden now has empirical data to answer it, at least for the most important use cases.

The short answer: flexibility is worth vastly more to DSOs than current market prices suggest — but the CAPEX-biased revenue regulation structure means DSOs currently have neither the incentive to quantify it properly nor to act on the result. Ei’s planned TOTEX reform for RP5 (2028–2031) is the critical structural fix.

The valuation problem

Flexibility creates economic value for DSOs in several distinct ways. These ways are not interchangeable — they operate at different timescales, activate at different hours, and face different regulatory accounting treatment. A DSO attempting to justify flexibility procurement needs to know which value channel it is optimizing, because the answer changes what price is rational to pay and when to pay it.

Four distinct channels exist, each quantified empirically in Swedish data. Their values differ by orders of magnitude:

(Source - FlexAbility Delrapport 3 (2025), Source - FlexAbility Delrapport 2 (2025))

Channel 1: Abonnemangsoptimering — subscription optimization

Swedish regional DSOs pay Svenska kraftnät a fixed subscription (abonnemang) for their power reservation on the transmission grid: 195,000 SEK/MW/year (2024) for subscribed capacity, with a penalty of 292,500–390,000 SEK/MW for exceeding the subscription level during peak hours without advance permission. If flexibility can cut the DSO’s actual peak demand at the transmission connection point, the DSO can reduce its subscription level and capture the fee savings.

This is the highest-value DSO flexibility use case. Modelling from two Ellevio stations shows how steep and non-linear the marginal value curve is:

At a flexibility procurement cost of 10,000 SEK/MWh (roughly the upper end of mature local market prices), the optimal subscription reduction was 4 MW for Station A (55 → 51 MW, saving ~712,000 SEK/year) and 2 MW for Station B (59 → 57 MW, saving ~482,000 SEK/year).

The implication: a DSO that accurately forecasts its transmission connection peak demand and can procure small quantities of highly targeted peak-shaving flexibility has an extraordinarily strong business case. The challenge is that this value is concentrated in very few hours — only the hours when the DSO’s demand would otherwise breach its subscription limit. Identifying those hours in advance requires high-quality short-term load forecasting, which most DSOs currently lack or cannot access in real time.

An important caveat: the analysis flags that abonnemangsoptimering savings may represent cost redistribution rather than system-level value creation. If a DSO reduces its subscription by 4 MW and Svk must handle the same underlying demand through other means, the system cost has not necessarily declined — it has shifted. Whether this constitutes genuine efficiency gain or merely transfers costs to Svk or other parties is an open research question. (Source - FlexAbility Delrapport 3 (2025))

Channel 2: Belastningsincitament — regulatory incentive for load flattening

Ei introduced utnyttjningsgraden (Ug, utilization rate) as the performance indicator for the belastningsincitament (load-balancing incentive) in Swedish revenue cap regulation for RP4 (2024–2027), replacing the earlier medellastfaktorn. The indicator is defined as:

Ug = Pmedel / Pmax,4 = annual average daily load / average of the four highest daily peak loads

measured at the DSO’s connection points to the overlying grid (Source - Ei PM2023-01 Incitament Effektivt Nätutnyttjande (2023)).

A DSO that improves its Ug relative to the norm (2018–2021 average) earns an addition to its intäktsram; underperformance triggers a deduction. The incentive is priced against the DSO’s subscription and connection costs to the overlying network.

Monetization: Ei’s empirical calculations across 18 local and 3 regional networks show a typical incentive magnitude of ±1% of intäktsram, equivalent to 40–174 SEK/customer/year per 1 percentage point for local network operators (median ~75 SEK/customer/year). For a DSO with 100,000 customers, a 1% intäktsram movement ≈ 7.5 MSEK/year. This is entirely separate from direct flex cost recovery — it is a reward for the outcome (load profile improvement), not compensation for the procurement cost.

Station A case from FlexAbility: normvärde 44.02%, actual 38.88% → revenue penalty of 924,000 SEK/year. Modelling a 20 MWh flexibility intervention targeted at peak demand hours: average 10,711 SEK/MWh (range 0–40,000 SEK/MWh). The extreme range arises because only interventions that cut at least one of the four highest daily peaks have any value at all — the metric is a step function.

The procurement logic: a DSO optimizing for utnyttjningsgraden is trying to flatten the worst few days of the year, not manage congestion in the conventional sense. This may or may not coincide with actual physical constraint events. The metric measures performance at the border connection point to the overlying grid — not internal grid stress — which can create perverse incentives where a DSO improves its regulatory score without improving capacity management.

Nevertheless, the incentive is real and the values are large. A DSO with a 924,000 SEK/year penalty from utnyttjningsgraden has a strong financial incentive to procure flexibility — and at 10,711 SEK/MWh average value, market prices of 3,000–3,800 SEK/MWh look cheap.

Channel 3: Alternativkostnad — grid investment deferral

The most structurally important value channel for the flexibility debate is investment deferral: using flexibility to postpone or permanently replace a grid reinforcement project. FlexAbility DR3 provides a concrete, fully-worked Swedish case.

Station C bus depot case: two 20 MVA transformers with 28 MVA N-1 capacity. An electric bus depot adding 8.7 MW is planned for 2028. Without action, this pushes demand above N-1 safe capacity. Traditional solution: upgrade to 2×25 MVA — approximately 22 MSEK.

Hourly demand modelling (using Plexigrid’s platform with Ellevio network data) revealed that the N-1 capacity threshold is exceeded only 4 hours per year after the bus depot connects — a total of 2.6 MWh/year. Flexibility cost at 10,000 SEK/MWh: 26,000 SEK/year.

Net present value comparison over 45 years at WACC 4.53%:

• Grid upgrade: ~22 MSEK
• Flexibility procurement: ~1.2 MSEK
• Savings from flexibility: ~20.8 MSEK (17:1 ratio)

This case is striking precisely because the numbers are so extreme. 4 hours of congestion per year makes grid expansion massively over-engineered and flexibility economically dominant — yet under current CAPEX-biased regulation, the investment is the regulatory-correct choice (it earns a return; flexibility procurement does not).

Generalizing the alternativkostnad method: FlexAbility DR3 computed upgrade costs for 29 transformer configurations using Ei’s normprislista (standard price list):

This gives a practical rule of thumb: 1 MW of grid upgrade capacity ≈ 100–200 hours of flexibility at 5,000–10,000 SEK/MWh per year. A DSO planning a transformer upgrade and observing that congestion will occur fewer than 100–200 hours per year has a prima facie case that flexibility is cheaper — before conducting a detailed NPV analysis.

The rule of thumb is a screening tool: it allows DSOs to quickly identify which planned investments are candidates for flexibility substitution and which are not. Most grid investments replace facilities needed continuously, making flexibility an impractical substitute. But in a subset of cases — particularly new connection-driven load like EV charging, industrial ramp-ups, or solar park connections — the new load creates few additional congestion hours, and the rule of thumb will identify this.

Earliest Swedish quantification: the BESS-vs-copper ratio has antecedents going back to E.ON’s Simris microgrid pilot (2015–2018, H2020 InterFlex). At Simris, a 333 kWh / 800 kW BESS together with its Power Conversion System was found to be up to 4× less costly than a conventional grid upgrade (conductor or substation expansion) for mitigating voltage deviations caused by newly connected renewable energy plants. This finding predates the FlexAbility 2025 data by nearly a decade and establishes that the BESS-vs-copper advantage is not a recent artifact of falling battery prices — it was already present at 2015–2018 battery costs in a specific network context. The Simris result and the FlexAbility 1.09 MSEK/MW norm are methodologically complementary: Simris is a measured project-level comparison; FlexAbility is a regulatory norm-based generalization across 29 transformer configurations. (Source - InterFlex Simris Microgrid (2018))

Channel 4: V2G and DER integration — avoiding negative value

A less discussed value channel runs in the opposite direction: the risk that poorly coordinated distributed resources, particularly V2G, create negative value by destabilizing local LV networks. FlexAbility DR3 quantified this for two Swedish LV networks.

Stockholm suburb network (2,019 customers): substation overload constraint at 80% EV+PV penetration (weekends, Q3); overvoltage at 90%. A reference southern Sweden network reached these thresholds at 30–40% penetration — less than half as resilient, due to less thermal headroom in the cables.

The policy implication: a V2G activation that provides FCR-D service (upward regulation, injecting power into the grid from EV batteries) creates value at the TSO level but may simultaneously create overvoltage and overloading at the LV distribution level. The two effects can conflict. A DSO that participates in a V2G or smart charging program without network simulation has no way to know where the threshold lies in its own network — the range between 30% and 80% penetration triggers across two Swedish networks illustrates that national averages are meaningless for local planning.

The consequence for valuation: the expected value of V2G to a DSO depends critically on network topology. For some networks, V2G at current penetration levels is safe with positive value. For others, it creates liability at penetrations already visible in the near-term deployment pipeline. DSOs need grid simulation tools (such as Plexigrid’s platform used in this study) to assess the sign of the effect, not just its magnitude.

Market prices as observed willingness to pay

Swedish local flexibility market data provides an independent valuation signal: the prices DSOs have actually paid in competitive markets. These are observed willingness-to-pay figures — bounded from below by the actual procurement cost DSOs accepted.

Activation prices, recent seasons (from FlexAbility DR2, all markets):

The Hässleholm price (~16,000 SEK/MWh) is extreme and informative: it corresponds to E.ON activating flexibility approximately 65–79 hours per season on a persistent congestion point where no near-term grid reinforcement is planned. Applied to the rule of thumb, 65–79 hours per season at 16,000 SEK/MWh is consistent with a transformer upgrade cost well above 1 MSEK/MW. The price reveals that E.ON has a high-value congestion problem it has chosen to manage via markets rather than investment — and is willing to pay accordingly.

The cluster of SE3/SE4 markets at 2,900–3,800 SEK/MWh represents more typical DSO willingness to pay for congestion management at the margin. This range is also consistent with the value implied by abonnemangsoptimering at the 5th–9th MW of subscription reduction, suggesting market prices roughly track the marginal value of the procurement in well-functioning markets.

The comparison with national balancing markets: during activation hours in 2024/25, local flex prices exceeded FCR-D prices in 100% of activation hours and exceeded mFRR prices in 93% of hours. This does not mean flexibility is cheap — it means DSOs procure at precisely the times when alternative uses of the same resource would also be high-value, confirming that congestion and balancing needs are correlated in time. (Source - FlexAbility Delrapport 2 (2025))

The CAPEX bias: why correct valuation doesn’t generate correct procurement

The most important structural finding from the Swedish evidence is that correctly identifying flexibility value does not lead to correct procurement decisions under current regulation. This is the CAPEX bias problem — and it is now empirically concrete.

Under current revenue cap regulation (förhandsreglering):

• Grid investment (CAPEX) enters the capital base, earns a regulated return (WACC × asset value) over the investment lifetime, and is insulated from efficiency benchmarking
• Flexibility procurement (OPEX) is formally classified as a påverkbar (controllable) operating cost under EIFS 2023:5 §2 — subject to efficiency benchmarking and efficiency deductions. Ei’s Handbok (§9.5.8) treats approved flex costs as opåverkbar (1:1 recovery, no deduction) in practice, but this is Handbok interpretation rather than the formal regulatory text. Even under this favourable treatment, flex costs earn no regulated return.

A DSO choosing between a 22 MSEK transformer upgrade and 26,000 SEK/year in flexibility procurement faces the following regulatory-financial logic: the 22 MSEK investment earns ~1 MSEK/year in regulated return (at roughly 4.5% WACC) for 40+ years. The 26,000 SEK/year opex solution earns nothing and is scrutinized for cost efficiency.

FlexAbility DR5 confirmed this through interviews: DSOs describe running flex markets as “välgörenhet” (charity) — they receive 1:1 cost recovery for approved procurement costs but no return on the effort. (Note: the 1:1 recovery itself requires prior Ei approval of the market product specifications under §11 Förordning 2022:585 — DSOs procuring via non-approved products cannot claim even the opåverkbar treatment. (Source - EIFS 2023-4 och 2023-5 Rapporterings och Beräkningsföreskrifter (2023))), while a comparable grid investment would earn a regulated return. Every single DSO interviewed in DR5 cited intäktsreglering as a barrier — it ranked #1 by a wide margin (38 points vs 21 for market design in second place). (Source - FlexAbility Delrapport 5 (2025))

This means that DSO flexibility valuation is currently a necessary but not sufficient condition for procurement. A DSO that correctly demonstrates that flexibility saves 20 MSEK in NPV terms is still behaving rationally under current regulation if it chooses the 22 MSEK investment — because only the investment generates regulated income.

The regulatory fix: TOTEX reform

Ei’s planned reform for RP5 (2028–2031) directly targets the CAPEX bias through a TOTEX (total expenditure) framework. The key change: both capital costs and operating costs are included in a single benchmarking and efficiency incentive framework. A DSO that achieves a lower TOTEX outcome by using flexibility instead of building grid gets credit for the efficiency gain — it is no longer penalized for treating an OPEX solution as efficient.

This creates lösningsneutralitet (solution neutrality): the regulation stops caring whether the cheapest solution involves capital or operating expenditure, and simply incentivizes the cheapest solution. (Source - Ei Inriktning intäktsramar 2028-2031 (2025))

However, three important nuances from the FlexAbility research must be held simultaneously:

1. TOTEX must not penalize proactive grid building. The reform must be designed so that DSOs who invest ahead of need — building anticipatory capacity for a forecast electrification wave — are not benchmarked as inefficient relative to DSOs who wait. TOTEX efficiency benchmarking measures outcomes; a proactively built grid looks expensive in early years before the load materializes. If the benchmark punishes proactive investment, the reform will suppress necessary grid development. This is a design risk in the TOTEX reform that the Swedish DSO community has explicitly flagged. (Source - FlexAbility Delrapport 3 (2025))

2. TOTEX takes effect in 2028, full impact from 2032. Revenue frames for 2028–2031 will be decided by October 2027. DSOs making procurement decisions today operate under RP4 (2024–2027), where the CAPEX bias fully applies. The reform is correctly directioned but its timing means several years of sub-optimal flexibility development before incentives align.

3. TOTEX alone is insufficient. Even after TOTEX reform, the nine structural conditions identified in DR2 — cross-BRP aggregation (BSP role), common APIs, single prequalification, standardized products, tariff API access, and coordinated national flex architecture — must also be in place for DSOs to actually procure the flexibility that the new regulation makes economically rational. The BSP absence in particular blocks ~300 MW of technically-qualified flexibility from entering the market regardless of DSO willingness to pay.

System value vs. DSO value: the key analytical distinction

A recurring theme in the FlexAbility research is that DSO flexibility value ≠ system flexibility value. This distinction matters enormously for policy, regulation, and investment decisions.

The most concrete example is abonnemangsoptimering: a regional DSO that uses flexibility to reduce its Svk subscription saves the subscription fee — but does this represent a real efficiency gain? The peak demand that drove the subscription is still there, just shifted in time. Svk may need to meet the same peak demand through other means. If so, the DSO’s saving is merely a cost transfer to Svk or other parties, not a net system benefit.

In contrast, the alternativkostnad (investment deferral) case represents genuine value creation: if a 22 MSEK transformer never needs to be built because congestion occurs only 4 hours per year and flexibility covers those hours, the capital is genuinely freed for other uses. This is not a cost redistribution — it is a resource saving.

The utnyttjandegrad metric sits in an intermediate position: it incentivizes demand flattening at the grid connection point, which may or may not correspond to genuine network stress reduction depending on whether the DSO’s peaky behavior reflects real internal congestion or merely purchasing patterns.

Understanding which value channel is at work matters for:

• Regulation design: TOTEX reform should incentivize genuine system-level value, not cost redistribution. If DSOs game utnyttjandegrad metrics without reducing real congestion, the reform creates gaming incentives.
• TSO-DSO coordination: the subscription optimization value channel is intrinsically linked to Svk’s subscription pricing policy. A Svk policy change (e.g., automatic subscription raises) could eliminate the value proposition overnight.
• Societal cost-benefit analysis: flexibility that merely redistributes costs within the regulated sector does not reduce total network charges; only genuine investment deferral and congestion cost avoidance reduce the total bill.

Forecasting as a prerequisite

All four value channels share a common prerequisite: granular, accurate, short-term load forecasting. The FlexAbility DR3 conclusion states this explicitly:

Forecast quality is critical: without granular hourly load forecasts, flexibility risks being more expensive or insufficient to replace capacity.

The bus depot case illustrates this starkly. The finding that N-1 capacity is exceeded only 4 hours per year could not be identified without building a detailed hourly demand forecast through 2034, including the bus depot load profile. A DSO relying on worst-case planning assumptions would have seen only that the bus depot would breach N-1 capacity — triggering the conventional grid investment response.

Similarly, the subscription optimization value is concentrated in a handful of critical hours. Only a DSO with a real-time forecast of demand at its transmission connection point can identify those hours and dispatch flexibility into them precisely.

This creates a digital capability gap. E.ON has developed an in-house TFT (Temporal Fusion Transformer) model for 48-hour and weekly demand forecasts, and has structured SWITCH to handle automated market participation using these forecasts. (Source - BeFlexible D5.1 Demo Planning and Deployment (2024)) Most Swedish DSOs lack this capability — and Vattenfall explicitly cited the absence of such tools as a reason not to pursue market-based flexibility. The forecasting infrastructure is not just a nice-to-have; it is the prerequisite for identifying where flexibility value actually lives in any given network.

Summary of the valuation framework

A DSO attempting to quantify the value of flexibility in its network should work through four questions in order:

1. Does my subscription or connection to the overlying grid create peak-driven costs?
If the DSO faces a Svk subscription fee or an utnyttjandegrad revenue penalty from a small number of high-demand hours, the marginal value of flexibility can reach 10,000–122,000 SEK/MWh. This is the highest-value use case. The prerequisite is a granular load forecast at the border connection point.

2. Do I have planned or foreseeable grid investments driven by infrequent peak demand?
Apply the rule of thumb: 1 MW of transformer upgrade capacity ≈ 100–200 hours of flexibility at 5,000–10,000 SEK/MWh. If the congestion constraint is hit fewer than ~100–200 hours per year, flexibility is likely cheaper than the investment. Build an hourly demand forecast to confirm.

3. What do comparable markets reveal about willingness to pay?
Mature Swedish markets clear at 3,000–3,800 SEK/MWh (excluding Hässleholm). This is a benchmark for congestion management value. If internal calculations imply a value well above this level, there may be untapped procurement space. If internal value is below market prices, flexibility may genuinely not be cost-effective at that location.

4. Does my regulatory framework allow me to act on the answer?
Under RP4 (current regulation), the CAPEX bias largely prevents rational flexibility procurement even when the NPV case is strong. Under RP5 (TOTEX, 2028–), the incentive structure improves. DSOs planning ahead for RP5 should begin the valuation work now, even if procurement at scale must wait for the regulatory shift.

Open questions

• Whether abonnemangsoptimering generates net system value or merely redistributes cost from DSOs to Svk is unresolved. Svk needs to study this.
• The TOTEX reform design must protect proactive grid investment from efficiency benchmarking — the tension between lösningsneutralitet and anticipatory investment is not yet resolved in Ei’s proposals.
• V2G valuation requires per-network simulation; no national-level planning tool currently exists to screen LV networks for V2G risk thresholds.
• The utnyttjandegrad metric incentivizes a proxy (flat load profile at border connection) rather than the underlying objective (efficient network use). Whether this creates gaming behavior or accurate incentives depends on the correlation between load profile flatness and actual grid stress in each DSO’s network.

Related pages: Congestion Management · Flexibility Market · Distribution Network Development Plan · Flexibility Need Assessment · Why Swedish Local Flex Markets Are Thin — Structural Causes · Villkorade Avtal · Virtual Power Plant