Vattenfall vs E.ON — DSO Approaches to Flexibility

Sweden’s two largest privately owned DSOs — Vattenfall Eldistribution and E.ON Energidistribution — have arrived at fundamentally different positions on distribution-level flexibility procurement despite operating under identical regulatory requirements. This divergence is documented in their first mandatory DNDPs, both published December 2024.

The core divergence

Same regulation, different conclusions

Both DSOs operate under:

• Directive 2019/944 Art. 32(1) — market-based procurement as the default for flexibility
• Ei2025:01 — villkorade avtal as non-market redispatching, permitted only where Art. 13(3) exceptions apply
• EIFS 2024:1 — DNDP template and guidelines
• The forthcoming Network Code on Demand Response — market-first principle with derogation procedure

Both DSOs apply the market-first principle — but draw opposite conclusions about whether markets are viable. The key is the viability threshold: Vattenfall has defined an explicit quantitative standard (supply ≥5× demand, ≥5 independent actors, no single actor >50%); E.ON operates markets that don’t necessarily meet this standard but clears what supply exists. Neither threshold is formally required by regulation.

Network footprint and customer mix

Vattenfall: ~11,000 MW total load; five areas from Norrbotten to Västra Götaland. Growth driven by heavy industry (steel, mining, automotive) in the north and large mixed loads in Stockholm/Uppsala. The constrained locations are primarily single-purpose industrial substations in sparse areas — exactly where a flexible market with ≥5 independent actors is structurally impossible.

E.ON: County-level footprint covering Skåne to Gävleborg; primary congestion in Skåne (Södra Skåne, Hässleholm) driven by dense population + solar/wind, and in larger cities (Jönköping, Stockholm). Skåne has many potential FSPs — district heating, aggregated EV fleets, commercial buildings — making the liquidity threshold achievable in ways it simply isn’t for a steel mill in Norr.

The structural conclusion: Vattenfall’s assessment that markets are not viable may be simply correct for its network, while E.ON’s assessment that markets are viable is also simply correct for its network. The divergence may reflect genuine differences in congestion geography rather than a philosophical disagreement.

Cost comparison: different framings

Both DSOs have quantified the economic case. Their approaches reveal different analytical frameworks:

Vattenfall’s comparison (DNDP Section 3.1.2):

Ratio: 15–30× more expensive for flexibility. Vattenfall uses this as its primary argument against market-based procurement. The comparison is capital cost per MW against availability contract cost per MW — it measures the price of avoiding grid build, not the economic value of the flexibility service itself.

E.ON’s comparison (from FlexAbility Delrapport 3, Ellevio-led):

E.ON’s framing is marginal economic value per activation hour — asking not what the flexibility contract costs but what the alternative (grid investment) costs and when flexibility is the cheaper option. The conclusion: at 50–100 activation hours/year, flexibility is often structurally cheaper than grid investment. At Vattenfall’s implied activation frequency (near zero, given no markets), the comparison is indeed unfavorable for flexibility.

The two framings are not contradictory — they answer different questions. Vattenfall asks: “Is a standing availability contract cheaper than building grid?” E.ON asks: “Is activating flexibility during peak hours cheaper than building for peak capacity?” Both can be correct simultaneously.

Pilot history: same platform, different outcomes

Both DSOs participated in CoordiNet (2019–2022) on the same SWITCH platform:

• E.ON (Skåne + Gotland + Jämtland): operated markets, collected data, continued post-CoordiNet as live commercial markets
• Vattenfall (Uppland): operated markets, collected data, extended into UppFlex (V2023/24), then closed

CoordiNet’s Uppland (Vattenfall area) achieved the best liquidity of any Swedish market — 173 MW, 13 FSPs, 9,965 MWh cleared over 3 winters at 248 SEK/MWh. This is the most traded-MWh market in Swedish flex history. Yet Vattenfall closed the extension.

sthlmflex (Stockholm): Vattenfall was a participant alongside Ellevio and Svk (addressing TSO subscription management at the regionnät level, not local grid congestion). It was a different problem from E.ON’s local DSO markets. Vattenfall participated as a subcontractor to the Svk-led initiative, not as the DSO operator. The closure was when the TSO subscription problem that motivated the market resolved.

The key distinction: Vattenfall’s pilots were addressing stamnät subscription limits — a constraint that belongs to Svenska kraftnät to solve, not Vattenfall. E.ON’s markets address local network congestion — a constraint Vattenfall mostly manages through grid investment because its constrained locations are large industrial substations rather than urban distribution grids.

Villkorade avtal: complement vs. primary tool

E.ON: villkorade avtal as the backstop. Market procurement happens first (SWITCH platform). Villkorade avtal activate only when market volume is insufficient. Ei approved E.ON’s method on 19 March 2024. E.ON explicitly frames the two tools as complementary.

Vattenfall: villkorade avtal as the primary tool. Bilateral agreements with individual large industrial customers. Market procurement is not used. DNDP Section 3.3.1 states: “Med utgångspunkt i nuvarande prognoser ser Vattenfall Eldistribution AB i dagsläget inget behov av andra flexibilitetslösningar än villkorade avtal med kund.”

The regulatory position (Ei2025:01) is that villkorade avtal may be used only where market-based alternatives are not viable (Art. 13(3) exceptions). Vattenfall’s position is that those conditions are met everywhere in its network. E.ON’s position is that they are not met in its most congested locations (Skåne, Hässleholm) — hence the markets.

Under the forthcoming NC DR, both DSOs will need to formally justify any use of villkorade avtal via the derogation procedure. This creates a significant compliance difference: E.ON has already built the market infrastructure that would satisfy the NC DR’s market-first requirement; Vattenfall will need to either demonstrate that derogation conditions are met or develop market infrastructure for its constrained locations.

Arholma: Vattenfall’s implicit demand response

Vattenfall’s “no flex markets” stance does not mean no demand-side management. The Arholma microgrid (northern Stockholm archipelago, commissioned August 2023) demonstrates active DSO control of customer loads — but through implicit, rules-based mechanisms rather than a competitive market. (Source - Vattenfall Arholma Microgrid (2025))

Two 160 kW battery systems provide 2-hour island supply. When the mainland submarine cable fails, the system automatically enters ö-drift mode. The next phase (planned 2025) is to extend control to customer heat pumps and heating systems, with sequential load reconnection to prevent cold-load pickup. Compensation to customers: a discount on the grid tariff.

This is the sharpest possible contrast with E.ON’s approach:

Vattenfall’s skepticism is specifically about market-based explicit DR — where independent FSPs compete for compensation. Arholma demonstrates they have no objection to load control per se; the barrier is market viability conditions (≥5 actors, ≥5× supply/demand ratio) which the Arholma context — 250 island residents, a single DSO controlling a microgrid — cannot satisfy. The operational logic is different: this is infrastructure management, not a procurement market.

E.ON’s earlier analog: The Simris microgrid (2015–2018, InterFlex H2020) was E.ON’s comparable precursor. Simris also used a rules-based DSR platform (ICONICS) to control heat pumps, boilers, and EV charging through SoC-based signals — before the CoordiNet market approach was developed. (Source - InterFlex Simris Microgrid (2018)) The progression from Simris’s rules-based DSR to SWITCH’s market-based procurement mirrors the conceptual shift from implicit to explicit flexibility.

Implications

For the NC DR implementation: Vattenfall’s position will likely require NRA (Ei) approval for systematic derogations from the market-based default — one derogation per congestion location, renewable for up to 2 years, with NRA notification to ACER and the Commission. This is a significant administrative and regulatory burden that E.ON’s approach largely avoids.

For flexibility providers: Vattenfall’s network (~11,000 MW, major industrial areas) is effectively closed to aggregators and FSPs for local DSO services. This represents a major gap in Sweden’s emerging flexibility market — the DSO with the largest industrial electrification pipeline reports zero quantified flexibility needs.

For the FNA 2026: Vattenfall participated in the tripartite FNA 2026 agreement as a signatory DSO. Its reported flexibility needs will be N/A or zero in the FNA’s FNAM Tabell 15 data. This creates an apparent paradox: Vattenfall expects +7,500 MW of growth requiring 22 major investments, while simultaneously reporting no flexibility need. The resolution is that Vattenfall handles this growth through grid investment and villkorade avtal — both outside the market-based flexibility framework that the FNA is designed to measure.

For the “thin market” diagnosis: Why Swedish Local Flex Markets Are Thin — Structural Causes identifies the TSO subscription mechanism, energy price correlation, and concentration risk as structural causes. Vattenfall’s N/A adds a seventh structural cause not previously articulated: geographic incompatibility between the DSO’s congestion profile and the minimum market conditions for viable competitive procurement. Industrial substations in sparse areas may simply never develop a ≥5-actor market. This is not a market design failure — it is a structural reality of Sweden’s electrification geography.

Related pages

• Vattenfall Eldistribution — entity page
• E.ON Energidistribution — entity page
• Flexibility Market — Swedish market landscape
• Villkorade Avtal — the shared backstop tool
• Distribution Network Development Plan — the source documents for both positions
• Why Swedish Local Flex Markets Are Thin — Structural Causes — broader structural analysis
• Congestion Management — what both tools are trying to achieve
• Network Code on Demand Response — forthcoming regulation that will require both DSOs to justify their approaches