E.ON Energidistribution

E.ON Energidistribution AB is Sweden’s largest distribution system operator (DSO / elnätsföretag) by grid length, and one of the three largest by customer count alongside Ellevio and Vattenfall Eldistribution. As a DSO, E.ON Energidistribution operates the regional and local Electric Power Distribution grid, delivering electricity from the Electric Power Transmission system to end customers.

Grid coverage

• ~143,000 km of grid (air lines + underground cable) — approximately 1/4 of all Swedish grid
• ~1.1 million connected customers — approximately 1/5 of all Swedish grid customers
• ~50 connected third-party distribution companies
• Regional (regionnät) grid: ~500 regional lines, ~600 fördelningsstationer, voltage 40–130 kV
• Local (lokalnät) grid: ~48,000 nätstationer, voltage 6–20 kV (medium) and 0.4 kV (low)
• Geographic coverage: 15 Swedish counties (largest continuous areas in Skåne, Blekinge, Kronoberg, Kalmar, Halland, Jönköping, Västernorrland, Gävleborg, Jämtland)
• Interconnections to Denmark (Energinet.dk) from E.ON’s Skåne regional grid

(Source - E.ON Nätutvecklingsplan 2025-2034)

Distribution Network Development Plan

E.ON published its first mandatory DNDP (nätutvecklingsplan) in December 2024, covering 2025–2034. It is the first DNDP from the largest Swedish DSO and provides the most comprehensive public picture of E.ON’s grid capacity situation, investment plans, and flexibility needs. (Source - E.ON Nätutvecklingsplan 2025-2034)

Key outputs:

• Demand forecast: average 13% load increase by 2029, 17% by 2034; EVs 100,000 → 700,000; solar 1 GW → 2.6 GW in local grid
• ~700 MW / ~1 TWh per year stated as E.ON’s total near-term flexibility need (weather-conditional, peak scenario)
• 246 major projects listed; min. 23 BSEK to be invested by 2027 (30 BSEK in past 10 years)
• County-by-county capacity ratings (A/B/C) for production and consumption across three time horizons (0–2, 3–5, 6–10 years)

See Source - E.ON Nätutvecklingsplan 2025-2034 for full county-level tables.

Relevance to flexibility

E.ON Energidistribution is notable in this wiki as an early implementer of distribution-level flexibility mechanisms in Sweden:

Villkorade avtal

E.ON offers Villkorade Avtal (conditional connection agreements) to customers connecting large loads in congested grid areas. Their published guide (Source - E.ON Guide villkorade avtal (2025)) provides the most detailed available documentation of how Swedish DSOs implement conditional connections in practice.

Zero activations since introduction: E.ON’s villkorade avtal have not been activated since the framework was introduced — the SWITCH flex market has, in practice, always been sufficient to manage congestion events before reaching the backstop threshold. This is consistent with the design intent (market first, villkorade avtal only if market volume is insufficient) but also reflects that the markets, despite their liquidity gap (42% fill ratio), have not been tested against a congestion event that exceeded available market supply. The SGI No_ba_cons_proc figures for E.ON (97 consumer activations in 2024) represent a different category of bilateral agreement, not villkorade avtal.

• Customers receive a split between guaranteed capacity (garanterad överföringskapacitet) and controllable capacity (styrbar effekt)
• 15-minute curtailment response time when the DSO signals congestion
• Technical requirements include real-time metering (Modbus), API/IEC 60870-5-104 communication, and OpenADR 3.0.x for automated signal handling
• Grid tariff is the same as a standard connection — no penalty for the conditional arrangement
• E.ON’s OpenADR variant: start time = next hourly-aligned 15-minute period; duration PT15M; payload type CONSUMPTION_POWER_LIMIT or PRODUCTION_POWER_LIMIT with unit KW (maximum allowed power); VEN required to report real-time power readings; report type POWER_LIMIT_ACKNOWLEDGEMENT. This variant enables dynamic limits and real-time delivery validation across multiple customer resources. (Source - Energiföretagen Supplement Conditional Grid Connections (2025))
• E.ON and Vattenfall R&D conducted the industry’s first OpenADR PoC for conditional connections in 2022–2023 (E.ON as VTN via SWITCH, Vattenfall as VEN via OpenLEADR), testing at a physical EV charger in Älvkarleby. The PoC validated the 15-minute delivery period and the full acknowledgement flow. (Source - Energiföretagen Branschrekommendation Conditional Grid Connections (2023))

Simris microgrid pilot (2015–2018)

See Island Operation for the general ö-drift framework and comparison with Arholma. Before CoordiNet, E.ON built and operated the Simris Local Energy System (LES) — a grid-connected microgrid in the village of Simris in southern Sweden, funded under the EU H2020 InterFlex project (grant 731289). The pilot started in 2015 and ran field trials through at least 2018. (Source - InterFlex Simris Microgrid (2018))

Key assets: 333 kWh / 800 kW BESS (grid-forming unit in island mode); 500 kW wind turbine; 442 kWp PV plant; 480 kW bio-diesel backup generator; DSR platform controlling customer heat pumps, hot water boilers, and EV charging; 150 customers across five secondary substations.

Key technical result: during a 12-hour islanding test (April 2018), the LES exhibited better power quality than the Nordic grid — tighter frequency band, more stable voltage, and lower THD (total harmonic distortion).

Key economic finding: BESS + Power Conversion System was up to 4× cheaper than a conventional grid upgrade (conductor/substation expansion) for mitigating voltage deviations caused by newly connected RES plants. This is the earliest quantified E.ON evidence for the BESS-vs-copper cost comparison that appears in later Swedish analyses.

Protection engineering in island mode: A dedicated fault clearing study (Anton Dahlgren, E.ON, internal report D18-0192118) and the companion Energiforsk 2023:957 report document the Simris protection philosophy. All island-mode generation is concentrated at a single switchgear point, which fundamentally simplifies protection design. Key features: (1) Directional overcurrent protection on outgoing feeders, with the BESS feeder as backup reserve protection. (2) The BESS inverter was deliberately oversized to deliver 2× rated current for 2 seconds — an explicit engineering decision to ensure conventional overcurrent relays can detect fault currents from the inverter, which otherwise would be limited to ~1–1.5 p.u. (3) Ground faults in island mode are handled by zero-sequence voltage protection with sensitivity updated from 3 kΩ to 5 kΩ on island entry — but protection is non-selective: any MV ground fault in island mode blackouts the entire island. (4) Distributed solar PV fault current contribution was considered negligible and not included in protection design. (Source - Energiforsk 2023-957 Felbortkoppling i Mikronät (2023))

The Simris R&D was the technical foundation from which E.ON built its institutional knowledge for CoordiNet and subsequently SWITCH. The DSR platform at Simris (ICONICS) is an early operational precursor to the villkorade avtal automation later standardized via OpenADR.

CoordiNet and SWITCH

E.ON was the lead DSO developer in the Swedish CoordiNet demonstration (2019–2022), building the SWITCH platform in-house with requirements from E.ON, Vattenfall Eldistribution, and GEAB (Gotland). E.ON operated the flexibility markets in Skåne and Västernorrland/Jämtland, while Vattenfall used the same platform for Uppland and Gotland.

SWITCH has four components: a market tool (bid management, impact-factor-weighted merit order, mFRR forwarding), a flex tool (DSO operator interface with ML grid forecast and TSO subscription integration), an FSP interface (API, automated ordering, baseline), and a P2P platform (capacity trading during maintenance). The flex tool was also adopted by sthlmflex (Stockholm), which replaced the market tool component with NODES (Nord Pool subsidiary). (Source - CoordiNet D4.7.2 Swedish Demonstration (2022))

Key outcomes from E.ON’s Skåne demonstration: 12 FSPs, 188 MW registered capacity, 206 MWh cleared (mostly test trades) at an average price of 2,285 SEK/MWh. The TSO’s practice of granting temporary subscriptions in Skåne meant the DSO rarely needed to use the market for real congestion management — but the market infrastructure was built and processes validated.

Flexibility market integration

E.ON’s model envisions a sequence: the DSO first tries to resolve congestion through a local Flexibility Market via SWITCH, then activates villkorade avtal as a backstop if market-based flexibility is insufficient. (Source - E.ON Guide villkorade avtal (2025), Source - CoordiNet D4.7.2 Swedish Demonstration (2022))

130% overbooking model

The DSO Entity report (2026) describes E.ON’s Swedish approach as a European best-practice example. E.ON operates its grid at 130% of standard physical capacity by using flexible connection agreements (villkorade avtal) as the instrument for the additional 30%:

• Connections up to 100% are served on standard firm connection terms
• Connections 100%–130% are served on conditional (villkorad) terms — customers accept curtailment risk in exchange for faster/cheaper connection
• When real-time or day-ahead demand approaches the 100% threshold, SWITCH is activated first (market-based)
• Villkorade avtal activate as backstop if market volume is insufficient

This model allows E.ON to connect significantly more customers and loads without building additional grid capacity for the marginal 30%, while the flexibility mechanism manages the residual congestion risk. E.ON has signed flex contracts until 2029 with its large industrial customers and major aggregators — providing multi-year procurement commitment that enables service provider investment planning.

(Source - DSO Entity Distributed Flexibility Practices (2026))

EU context

As a Swedish DSO, E.ON Energidistribution must comply with the Clean Energy Package framework — particularly the Electricity Market Directive Art. 32 (market-based flexibility procurement), Art. 31 (neutral market facilitator role), and Art. 36 (storage ownership restrictions). The forthcoming Network Code on Demand Response will add further requirements around flexibility registers, prequalification, and TSO-DSO coordination.

Published flexibility needs by market area

E.ON publishes specific flexibility needs for each active market area. As compiled by FlexAbility (2025):

Hässleholm is notable for needing 150–300 activation hours/year — 2–4× the typical 50–100 hours for other areas, suggesting more chronic rather than peak congestion. (Source - FlexAbility Delrapport 1 (2025))

Live flexibility market (as of December 2025)

E.ON operates SWITCH-based flexibility markets in 11 geographic areas: Bromölla-Sölvesborg, Bålsta, Enköping, Hässleholm, Kallhäll, Kungsängen, Nordöstra Skåne, Norra Örebro, Södra Skåne, Vaxholm, Älmhult-Osby. Two areas (Bromölla-Sölvesborg and Älmhult-Osby) were newly added as of December 2025. With the Halland summer pilot, E.ON’s total active market count reaches 12 for 2025/26. Public market data: https://info.switchmarket.se/. Minimum order size: 0.1 MWh/h. Payment includes both availability and activation components. (Source - E.ON Flexibilitet i elnätet (web, 2025))

Liquidity gap (2025/26): Across all 12 markets, 25.2 MW is pre-qualified against a stated DSO need of 59.5 MW — a 42% fill ratio. This is the clearest quantification to date of the structural supply deficit in Swedish local flex markets. 10 qualified FSPs and 19 assets are registered as of end of 2024/25. (Source - BeFlexible D5.2 Demo Planning and Deployment 2 (2025))

Projekt Halland — production-side flexibility (2025)

Summer 2025, E.ON launched Sweden’s first local flexibility market with a focus on production load (produktionslast) in Halland (SW Sweden). This is distinct from all existing SWITCH markets, which address consumption-side congestion. (Source - E.ON Projekt Halland (web, 2025))

The problem: production-driven congestion has a three-factor cause: (1) high solar and wind production; (2) warm, sunny days simultaneously produce low consumption; (3) overhead line thermal capacity decreases as air temperature rises (warm air = less cooling = reduced line capacity). All three coincide in summer. The strained component is an overhead line in a regional meshed grid, meaning impact factors are not 1:1 — each resource’s effect on the line varies by location and grid coupling mode.

The market design (Source - BeFlexible D5.2 Demo Planning and Deployment 2 (2025)):

• Period: June 1 – September 30, 2025
• Direct orders only (no availability component) — chosen for shorter lead time enabling better forecasts and simpler FSP baseline setting
• Delivery validation cutoff: 50% — reduced from the standard 75% used on winter markets, to incentivize participation by intermittent production resources where full delivery cannot be guaranteed
• Call-off time: 08:30 — earlier than 10:30 on other markets, following FSP feedback about BRP reporting deadlines; DSO need published from D-2 10:30
• Market area: Halland region (Falkenberg and northeast), covering both regional (meshed) and local grids; includes FSPs on Falkenberg Energi Elnät’s grid (a separate DSO within the market area)
• 32.5 MW qualified at launch (June 1): solar park, wind park, BESS

Providers bid to reduce production or increase consumption during specified peak production hours. Auction via SWITCH; lowest price per MWh wins. Minimum 0.1 MWh/h, same threshold as consumption markets. No other equivalent local market exists in Sweden — the only comparable national instrument is Svk’s downward regulation balancing markets.

Five named participants at launch: Falkenbergs Energi (battery storage), CheckWatt (aggregator/software), Ntricity (multi-market optimizer), Varbergs Energi (aggregator; also participates centrally at Svk), Soltech Energy Solutions (solar park — Solpark Öringe in Halland).

New barrier identified: a chain of actors (resource owner ≠ technical controller ≠ trader ≠ BRP) creates coordination complexity in production-side markets. Intraday participation is near-zero due to imbalance cost risk. Batteries face potential network tariff charges from consumption peaks when downregulating (charging = increased consumption). (Source - BeFlexible D5.2 Demo Planning and Deployment 2 (2025))

BeFlexible project

E.ON’s markets in Hässleholm, Södra Skåne, and several Stor-Stockholm sub-areas were developed under the EU-funded BeFlexible project. A report on these markets was published in autumn 2024. Key outcome: product designs were revised for V2024/25 to comply with Swedish public procurement rules (LOU/LUF) — blind bidding was replaced with need-first bidding, and first-come-first-served availability allocation was replaced with lowest-bid-wins auctions. See SWITCH › BeFlexible project and public procurement compliance for details. (Source - Sweco Kartläggning av lokala flexibilitetsmarknader (Ei, 2025))

The BeFlexible project also covers FSP-side demonstration through E.ON Energy Infrastructure Solutions (EIS). Key 2025/26 findings (Source - BeFlexible D5.2 Demo Planning and Deployment 2 (2025)):

Heat Flex (commercial buildings with heat pumps): Phase 1 (winter 2024–25) delivered approximately 20% electricity cost reduction through day-ahead price optimization using building thermal inertia — heating the building more during cheap hours, less during expensive hours, within ±0.5°C comfort tolerance (“Building as a Battery”). Technology stack: ectocloud™ platform → Energy Manager IoT gateway → BMS → heat pump control. ~1 MW potential aggregated flexibility; 200 kW currently connected.

District heating multimarket strategy: E.ON EIS is aggregating district heating assets (CHPs, heat pumps, boilers) across multiple sites with an aggregated target of 36 MW. mFRR prequalification is underway for feasible assets. Value pool progression: Day-ahead → LFM → Intraday → mFRR capacity + energy activation. First flexibility delivered in November 2023 (3 MW from DH-coupled heat pumps in Södra Skåne market).

FCR-D price decline as multimarket driver: FCR-D prices have declined significantly since 2023, making battery investments based solely on balancing services less attractive. E.ON EIS has shifted strategy to multimarket approaches combining LFM + mFRR + day-ahead trading + behind-the-meter (BTM) optimization.

Technical alternatives: Dynamic Line Rating

E.ON has deployed Dynamic Line Rating (DLR) — real-time thermal capacity calculation for overhead lines based on temperature and wind — with an ambition to deploy on all 130 kV lines during 2025. DLR complements the flexibility toolbox by expanding effective line capacity under favorable weather conditions, reducing the need for flexibility activations. (Source - E.ON Nätutvecklingsplan 2025-2034)

Ei’s SGI data (No_DLR, 2023 and 2024) records 3 lines, 40 km of DLR-equipped network for E.ON in both years — unchanged. The DNDP stated “1 line currently deployed” as of late 2024, a discrepancy that may reflect different definitions (SGI counts sensor-equipped lines; DNDP may have referred to lines where DLR is actively used in real-time operational decisions). (Source - Ei SGI Data 2023-2024)

SGI data — 2024 indicators

Ei’s mandatory SGI reporting (EIFS 2022:5) provides an independent cross-sectoral view of E.ON’s grid digitalization and flexibility activity:

Energy storage (ES_tot_direct)

E.ON’s grid-connected third-party storage (ES_tot_direct) is the largest in Sweden — nearly 6× the second-largest (Ellevio, 36.6 MW). This reflects E.ON’s position as the primary aggregator-facing DSO for battery flexibility in SE3/SE4.

Flexibility activations

The 32 market activations (all at exactly 2.5 MW — a standardised activation unit in SWITCH) are outnumbered by 97 bilateral consumer activations and 182 bilateral producer activations. These bilateral activations are not villkorade avtal — E.ON’s conditional connection agreements have had zero activations since the framework was introduced. The SGI bilateral figures instead represent separately negotiated direct flex contracts with consumers and producers operating outside the formal SWITCH market. The 172 lokalnät production activations suggest significant solar/storage dispatch via direct bilateral agreements in E.ON’s local grid areas — a parallel channel to the market that is not publicly visible.

Substation digitalization (RER, 2024)

E.ON’s regionnät is highly digitalized relative to the Swedish DSO sector: near-complete hourly measurement and majority remote operability. E.ON’s lokalnät (REL) is much lower (measure1: 8%, remote switching: 1.7%), consistent with the general gap between regional and local grid digitalization nationally. (Source - Ei SGI Data 2023-2024)

Data gaps

• Comparison with Ellevio and Vattenfall Eldistribution flexibility approaches
• DLR deployment progress: has the 2025 rollout to all 130 kV lines been completed?
• Halland summer market results (activations, prices, delivery rates) — BeFlexible D5.4 will not be publicly released; E.ON holds the data internally; no public source available
• Heat Flex scale-up: has the 200 kW connected grown toward the ~1 MW potential?
• What the 97 bilateral consumer + 182 bilateral producer SGI activations represent — these are not villkorade avtal (zero activations since introduction) and not SWITCH market activations (32); likely direct bilateral contracts outside the formal market, but the nature, counterparties, and grid areas involved are not publicly documented