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 — e.g. Kraftringen Nät (17 connection points, mostly 130 kV) and, in the same Lund/Kävlinge area, the smaller independent Skånska Energi Nät
• 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)

Malmö-region 145 kV area concession (2026-06-22): Ei granted E.ON a nätkoncession för område (area concession) in the Malmö region at 82–145 kV, valid tills vidare and covering only mark- och sjökablar (ärende 2025-103405). It is the first area concession to exceed the 110 kV ceiling — Ei accepted the exception because the area is a delimited, mostly developed metropolitan zone built out with cables only, enabling faster and more cost-effective regionnät expansion than per-line concession prövning (shorter lead times, faster connections in a growing region). A condition requires Försvarsmakten consent where total-defence riksintressen are affected. See Ei › Network concession practice — 145 kV area concession (2026). (Source - Ei Beslut Nätkoncession 145 kV Malmö (2026))

Sege station, Malmö (~800 MSEK, in service end-2029): E.ON is rebuilding its 1970s Sege station in Malmö for about 800 MSEK — a new 400/130 kV transformer of 750 MVA, a new 130 kV switchyard and 16 connecting lines, built without SF6 gas, with commissioning planned for the end of 2029 (ground broken October 2026). Sege is part of a Malmö package of over 1.1 billion SEK, together with Sjölunda (121 MSEK) and Oljehamnen (184 MSEK). (E.ON press release, 1 Sep 2026; E.ON press release, 8 Oct 2026)

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.

Second DNDP cycle — 2027–2036 (preliminary)

A second-cycle DNDP, shared preliminary for consultation in 2026, updates the picture: 27 billion SEK invested 2024–2027, 50+ capacity-boosting regional-grid projects already commissioned since the first DNDP, 216 more planned and 73 under consideration. Regional-grid project costs rose an estimated 50–75% over 2021–2026 — well above the ~20% CPI increase over the same period.

For the first time, E.ON splits its national lokalnät flexibility-need forecast into upregulation and downregulation separately: ~340 MW upregulation and ~45 MW downregulation by 2036. This isn’t a straightforward revision of the first DNDP’s combined ~700 MW / ~1 TWh figure above — E.ON states its estimation methodology has improved, the new figure excludes regionnät (assessed only qualitatively, since regionnät power flows are too complex to quantify with confidence), and it’s the first time downregulation is split out at all. Treat the two figures as measuring related but not identical things, not as a before/after correction.

The plan also names “flexibla avtal” (flexible agreements) as a new instrument distinct from Villkorade Avtal: where villkorat avtal is a temporary, last-resort backstop, flexibla avtal is being developed as a permanent solution aimed specifically at large batteries — whose fast, large activations can strain local capacity at peak even while the battery itself is a net grid asset. E.ON states it has an ongoing dialogue with Ei on the instrument’s design; it is not yet a finished, regulator-approved product.

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.

No activations documented in any source reviewed: no source reviewed for this wiki records a villkorade avtal activation by E.ON since the framework was introduced. If accurate, that would be consistent with the design intent (market first, villkorade avtal only if market volume is insufficient) and with the markets, despite their liquidity gap (42% fill ratio), not yet having been tested against a congestion event that exceeded available market supply — but the absence itself isn’t independently confirmed by a citable source, only inferred from silence. 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’s David Bjarup (IT-analytiker) backed the standardization effort as accelerating OpenADR adoption for flexibility solutions in Sweden, to the benefit of both customers and the grid. (Source - Energiföretagen Branschrekommendation Web (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%.

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)) Alvesta was added for the 2026/2027 season (5 MW; covers Vislanda, Gemla, Rydaholm, Åby, Rottene, Moheda, Ivarsfors, Dänningelanda, Skatelöv and Alvesta Elnät); it is not in the FlexAbility 2025 compilation. (Source - E.ON Flexibilitet i elnätet (web, 2025))

Live flexibility market (2026/2027 season)

E.ON operates SWITCH-based flexibility markets in 12 geographic areas: Alvesta, Bromölla-Sölvesborg, Bålsta, Enköping, Hässleholm, Kallhäll, Kungsängen, Nordöstra Skåne, Norra Örebro, Södra Skåne, Vaxholm, Älmhult-Osby. Alvesta is the new addition for 2026/2027 (Bromölla-Sölvesborg and Älmhult-Osby were the December 2025 additions, now established). With the Halland summer pilot, E.ON’s total active market count reaches 13. 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))

Prequalified capacity vs stated need (2025/26): BeFlexible D5.2 reported 25.2 MW pre-qualified against a stated DSO need of 59.5 MW (42%), but both were preliminary figures, compiled with 10 qualified FSPs and 19 assets registered as of end of 2024/25 and before the 2025/26 season closed. Neither is the season’s final figure: the per-area needs compiled in FlexAbility Delrapport 1 (October 2025) sum to ~71.5 MW across the 11 winter markets (76.5 MW with Alvesta, added for 2026/27), and prequalified capacity is 67.5 MW (below). (Source - BeFlexible D5.2 Demo Planning and Deployment 2 (2025))

A later BeFlexible project summary states 67.5 MW of prequalified capacity across the same 12 areas by 2025/2026, the season figure, about 94% of the ~71.5 MW per-area need. D5.2’s 25.2 MW is the earlier, preliminary count: D5.2 was compiled before the season closed, and further FSPs were prequalified afterwards. (Source - BeFlexible Technology Booklet (2026))

Season 25/26 outcomes (operator-reported): a cold winter produced record flex demand. On 10 of 11 markets flexibility was demanded for at least double the hours estimated pre-season (several markets 500–600 h, two markets 1,000–1,500 h); Södra Skåne’s realised need reached ~12,000 MWh. Supply could not keep up: after dispatching all available bids, the majority of need remained unmet on 10 of 11 markets, 3 of 11 markets had no active suppliers at all, and activation occurred on 7 of 11. Average activation price ~5,800 SEK/MWh (pay-as-bid), high relative to ancillary-services prices — attributed to limited competition. This is the operator-side corroboration of the 42% liquidity gap above. (Source - E.ON Webinar Lokala Flexibilitetsmarknader 2026-2027 (2026))

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: Falkenberg Energi (battery storage), CheckWatt (aggregator/software), Ntricity (multi-market optimizer), Varberg 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))

2025 pilot results (E.ON’s own pilot report, published 6 Aug 2025 — covers the full 1 Jun–30 Sep trading period): only two of the launch’s five named actors actually traded — aggregator Ntricity (Askome vindpark + Öringe Solpark) and aggregator CheckWatt (a battery owned by Falkenberg Energi) — against the 32.5 MW qualified.

Why gross ≠ net: because the reference point is a line in a meshed regional grid (not a station, where a valuation model already exists), the relationship between a resource’s own output adjustment and the actual relief at the constrained point is far from 1:1 — a low average impact factor across participating resources meant 554 MWh of gross adjustment produced only ~123 MWh of real relief. This pushed the DSO-perspective cost of relief to ~21,000 SEK/MWh, well above the ~4,700 SEK/MWh resource-level activation price (itself comparable to established winter markets) — a direct empirical illustration of why impact-factor accounting matters for valuing flexibility against alternatives like grid reinforcement.

Why only two of five participated: consumption-side actors cited effektavgift exposure from participating as a deterrent. On the imbalance-risk barrier already noted above, the pilot report is explicit: only FSPs using day-ahead activation actually participated — every actor considering intraday activation was deterred by imbalance-cost risk, confirming the barrier identified by BeFlexible D5.2 wasn’t just a design assumption but the actual, empirically observed cause.

Incentive structure: participants received a fixed pilot fee (65,000 SEK, +15,000 SEK per additional resource, capped at 80,000 SEK, contingent on a minimum-participation requirement) on top of per-MWh activation payment — cited by participants as central to their willingness to take on pilot risk at all.

What E.ON says needs to happen before this becomes an ordinary (non-pilot) market: (1) better short-term forecasting specifically for meshed-network load points, since load at any single point in a meshed grid is driven by many interacting factors that resist manual estimation — needed to enable automated, well-timed order placement; (2) a financing model for how an ongoing production-side market gets funded and by whom, explicitly under investigation through winter/spring 2026.

2026 continuation: E.ON continues the Halland production-side market in summer 2026 (1 June – 30 September) and is piloting intraday trading this season — testing whether trading closer to the operating hour improves forecast accuracy and eases participation. This directly targets the near-zero intraday participation seen in 2025: the day-ahead-only design left FSPs exposed to imbalance cost between commitment and delivery. Participation requirements are unchanged (≥0.1 MW). The pilot report adds mechanism detail beyond the webinar summary below: trading now happens after the day-ahead spot price is set (previously before), giving FSPs clearer alternative-cost information for bidding, and a post-activation balancing window lets an activated FSP trade itself back into balance on the wholesale market — if that isn’t possible, the FSP is not obligated to deliver on the local market for that activation. Explicit goal: reduce FSP risk exposure enough to unlock real intraday participation, while giving the DSO better forecasting inputs (driving plans) and more robust near-real-time activation. (Source - E.ON Webinar Lokala Flexibilitetsmarknader 2026-2027 (2026), Source - E.ON Projekt Halland (web, 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 › 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.

The project’s own EU-level summary describes this as HeatFlex for residential heat pumps rather than commercial buildings — either a broader or later pilot not otherwise documented, or looser EU-level scope language reused from the project’s non-Swedish demos. Not reconciled with the commercial-building Phase 1 above. (Source - BeFlexible Technology Booklet (2026))

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 — over 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 — no source reviewed records a villkorade avtal activation by E.ON 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

• DLR deployment progress: has the 2025 rollout to all 130 kV lines been completed?
• What the 97 bilateral consumer + 182 bilateral producer SGI activations represent — these are not villkorade avtal (no activation documented in any source reviewed) 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