Source - CoordiNet D4.7.2 Swedish Demonstration (2022)

Metadata

Summary

The final report of the Swedish CoordiNet demonstration — three winters (2019/2020, 2020/2021, 2021/2022) of open, market-based flexibility markets for congestion management, operated by Vattenfall Eldistribution and E.ON Energidistribution in four demonstration areas, with Svenska kraftnät as TSO partner. The report organizes lessons learned around ten abilities a DSO must develop to unlock flexibility, from product design and customer engagement through to the digital platform (SWITCH). This is the primary source document for CoordiNet’s market outcomes, platform architecture, and operational learnings.

The Swedish business use case

The fundamental trigger for all four markets is the subscription level (abonnemang mot överliggande nät): the annually contracted maximum power a regional DSO may draw from the TSO grid without prior notice. When Svenska kraftnät denies a subscription raise, the DSO faces a choice between:

• Buying flexibility to keep consumption below the limit
• Applying for a temporary subscription increase (at a fee of ~240–280 SEK/MWh for the capacity used above limit)
• Exceeding the limit and paying the penalty (~2,800 SEK/MWh)

This creates a clear price ceiling for the local Flexibility Market. The business use case for Congestion Management is entirely structured around this subscription mechanism.

Demonstration areas and market outcomes

Four areas operated concurrently:

Uppland (Vattenfall Eldistribution)

• Problem: Uppsala city (170,000 inhabitants) growing rapidly; TSO denied subscription raise since 2016; 10-year wait for grid reinforcement
• Market: Day-ahead + intraday, merit-order-based; subscription level exceeded ~2% of winter hours pre-market
• FSPs: 13 FSPs over three winters; wide range including heat pumps (single-family, multi-family, industry), electric boilers, gas turbine, waste incineration, battery storage (5 MW/20 MWh), reserve power, office geothermal HP, hydro
• Volumes: 9,965 MWh cleared over three winters; avg price 248 SEK/MWh — well below TSO subscription fee
• Market dynamic: Low-price equilibrium — DSO bought whenever cheaper than temporary subscription; high volume, low price

Skåne (E.ON Energidistribution)

• Problem: Western Skåne capacity constrained by Baltic Cable export reservation (600 MW locked for Germany) + CHP closure; TSO granted temporary subscriptions on all occasions → DSO only bought flexibility as test
• FSPs: 12 FSPs; district heating, diesel genset, 0.48 MW/1 MWh battery, steel industry, copper industry, aggregated heat pumps
• Volumes: 206 MWh cleared (mostly test trades), avg price 2,285 SEK/MWh
• Market dynamic: High-price equilibrium — small volumes, high prices; market tested processes more than managed real congestion

Gotland (Vattenfall / GEAB)

• Problem: Aging HVDC link to mainland; moratorium on new wind/solar >43.5 kW since 2017; island DSO responsible for frequency management (unlike mainland DSOs)
• FSPs: 4 FSPs; electric boiler, heat pump, diesel genset, refrigeration
• Volumes: 879 MWh cleared (654 MWh first winter), avg price 821 SEK/MWh

Västernorrland/Jämtland (E.ON) — Peer-to-peer

• Context: Temporary constraints during TSO line maintenance (15–25 times/year); wind and hydro producers swap production capacity
• FSPs: 3 FSPs in one pilot; Jämtkraft wind (78 MW), Uniper hydro (96 MW), Wallenstam wind (16.5 MW)
• Volumes: 4 MWh cleared in concept proof; market design validated but not repeatedly tested

Total across all areas: 39 flexibility service providers participated; 477 MW/7 GWh flexibility registered

Products tested

Key product design finding: Energy-only payment proved insufficient. FSPs need predictable income given the 3× variation in winter temperatures → activation frequency. The solution: availability contracts (fast bid agreements) where FSPs receive a capacity fee regardless of whether flexibility is called. Introduced in Skåne from winter 2020/2021, Uppland from 2021/2022.

The SWITCH platform architecture

SWITCH was built in-house by E.ON Energidistribution with requirements from E.ON, Vattenfall, and GEAB. It has four components:

1. Market tool: Manages flexibility bids; applies impact factors (PTDF — Power Transfer Distribution Factors) to create geographically weighted merit-order list; supports continuous trading with configurable windows; linked to TSO mFRR market for bid forwarding
2. Flex tool (DSO operator interface): Grid state visualization using ML-based load forecast; subscription limit monitoring; recommended flexibility purchase based on forecast + impact factors; integration with TSO’s SUSIE system (subscription request tool); 48-hour ahead substation monitoring
3. FSP interface: Sell order placement (day-ahead, weekly scheduled, advanced grouped orders for batteries); API for automated order submission; real-time meter readings; delivery history and baseline comparison
4. P2P platform: Grid bottleneck market during maintenance; blockchain transaction recording

sthlmflex uses the flex tool from CoordiNet with NODES (Nord Pool subsidiary) replacing the market tool component — illustrating the modular architecture.

Market time coordination cascade

The platform is designed to fit into existing market schedules:

1. Local DSO market closes 10:00 (day-ahead)
2. Regional DSO market closes 10:30
3. NordPool day-ahead market closes 12:00
4. FCR-D first auction closes ~15:00 (D-2)
5. CoordiNet intraday opens 15:00 (after FCR-D closes)
6. mFRR gate closure: 45 minutes before delivery hour
7. Unsold bids forwarded to mFRR under BRP name (after TSO intermediary function merges with existing BRP bid list)

Impact factors (PTDF)

The market uses Power Transfer Distribution Factors to determine how a resource at location X affects power flow at the constrained substation. A bid price is divided by the impact factor to calculate cost per MW of congestion relief — enabling geographically targeted procurement. Impact factors are defined as time series (updated hourly in principle; static high-consumption patterns used in demonstrations).

TSO-DSO coordination

The demonstration established a formal TSO-DSO cooperation framework:

• DSO control room integrated with TSO subscription request system (SUSIE)
• Joint definition of products and prequalification criteria
• mFRR forwarding protocol with TSO intermediary function to avoid overwriting BRP bid lists
• Each mFRR bid tied to a single BRP (a structural limit — no aggregation across FSPs for mFRR; BSP role expected to solve this)
• Gotland: historically not allowed in national mFRR — CoordiNet opened that dialogue with Svk

FCR-D vs mFRR: battery and EV preference

A key finding: owners of batteries and EV chargers preferred FCR-D over mFRR for the following reasons:

• Lower minimum bid: 0.1 MW for FCR-D vs 1 MW (CoordiNet exception) / 5–10 MW (normal mFRR)
• Shorter endurance: 20 minutes vs 1 hour for mFRR
• All-year capacity market: FCR-D operates as a capacity product; revenue available all hours
• Low energy impact: FCR-D activation is rare and short (seconds to minutes when frequency deviates from 49.9–50.1 Hz) — state of charge barely affected

This was demonstrated: a 0.48 MW/1 MWh battery in Skåne successfully participated simultaneously in CoordiNet (local congestion market) and FCR-D, using the two FCR-D auction windows (D-2 at 15:00 and D-1 at 18:00) to cancel FCR-D bids when cleared day-ahead on CoordiNet.

Market demand and liquidity findings

Temperature dependence: Swedish winter flexibility demand varies by a factor of 3 between a warm and cold winter (114–329 hours above subscription limit in Uppland across three winters). Most congestion is electricity-for-heat driven (heat pumps), so cold spells drive the market.

Energy price effect on liquidity (winter 2021/2022): Spot prices tripled/quadrupled (SE3 average rose from 39 SEK/MWh in 2020/2021 to 116 SEK/MWh in 2021/2022; SE4 even more due to continental exposure). District heating electric boilers — which had provided bulk of cheap flexibility — ran only 522 hours vs 1,527 hours the previous winter because they were more valuable producing heat than providing flexibility. Result: cheap flexibility disappeared exactly when cold-period congestion was highest. Perversely, the cold winter had the lowest market liquidity for cheap bids.

Two market equilibria observed:

1. Low-price, high-volume (Uppland): Flexibility priced below TSO subscription fee → DSO buys routinely → 248 SEK/MWh avg
2. High-price, low-volume (Skåne, Gotland): DSO only buys when TSO denies subscription → ~2,285 SEK/MWh avg, minimal volume

Barriers to flexibility markets

1. Insufficient FSP income from energy-only payment: Business case too uncertain without availability contracts; weather-dependent volumes create investment risk
2. Market liquidity: Concentrated supply (one district heating company dominated Uppland volumes); insufficient small-actor participation
3. CAPEX bias: Revenue cap regulation not designed for DSOs purchasing flexibility as operating expenditure — confirmed by CoordiNet experience, addressed by Ei‘s TOTEX reform from RP5 (2028)
4. High electricity prices destroy cheap flexibility: FSPs divert flexible resources to higher-value uses in volatile market conditions
5. mFRR minimum bid size: 5–10 MW standard (reduced to 1 MW for CoordiNet) excludes most distributed resources
6. Prequalification burden: Time-consuming; needs standardization for FSPs participating in multiple markets
7. Baseline methodology: No single method fits all FSP types; automated methods struggled with weather-volatile resources
8. Peer-to-peer taxation: Swedish VAT/energy tax structure (non-transferable consumption tax on heat company electricity + VAT on delivered heat) made P2P electricity-to-heat sector coupling unprofitable
9. DSO organizational change: Control room operators accustomed to real-time response had to shift to day-ahead market planning culture

Historical context: rundstyrning

Sweden had widespread ripple control (rundstyrning) in the mid-1990s: a kHz signal on the 50 Hz supply switched water boilers, street lamps, and controllable loads. Could deliver 7–8% peak load reduction; some individual DSOs had 6 MW controllable. Monthly tariff discounts incentivized customers. Phased out ~2000 after electricity market deregulation removed delivery responsibility from utilities. Now being “reinvented in a more digital and market-oriented way.”

CIM / IEC 62325 national standardization spinoff

CoordiNet directly triggered a joint TSO-DSO national standardization project: a national product catalog for flexibility services using IEC 62325 CIM (the same standard mandated by the European Commission under M490). Started spring 2021; first draft delivered 2022. Contributors: Vattenfall, E.ON, Svenska kraftnät, NODES, and the sthlmflex market. Covers actors/roles mapped to ENTSO-E’s Harmonised Electricity Market Role Model, business use cases, sequence diagrams, and CIM message mapping.

Conclusions from the report

• Flexibility proved technically successful for managing congestion — but is “not a silver bullet”
• Participation was a multi-year learning curve for both DSOs and FSPs
• Availability contracts (capacity fees) are necessary to build the FSP business case in thin markets
• The flex tool + market tool architecture is reusable and has been adopted by sthlmflex (Stockholm) and SWITCH (E.ON’s ongoing platform)
• CoordiNet directly inspired sthlmflex and Effekthandel Väst; Uppland and Skåne markets continued post-project
• DNO → DSO transition requires organizational change across planning, operations, and corporate culture — not just technology

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