Source - BeFlexible D5.2 Demo Planning and Deployment 2 (2025)

Title: D5.2 — Report on Demo Planning and Deployment - 2 Project: BeFlexible (EU-funded Horizon Europe project) Work Package: WP5 (North EU demonstration / Sweden — DEMO2) Publisher: E.ON Energy Networks (lead), E.ON Energy Infrastructure Solutions (EIS), Smart Innovation Norway (SIN), RWTH Document responsible: E.ON Version: 2.2 Submission date: 2025-08-26 (final); due 2025-08-31 Dissemination level: Public File: raw/20250826_BEFLEXIBLE-deliverable 5.2_Final_Cleaned.docx

Second preparation and planning report for the Swedish BeFlexible demonstration (WP5). Covers the preparation activities before the second demonstration period (2025/26), building on operational experience from 2023/24 and 2024/25 (D5.1 already in wiki; D5.3 is not public). The demonstration includes two parallel pilots: Pilot 2.1 (DSO perspective, E.ON Energidistribution) and Pilot 2.2 (FSP perspective, E.ON EIS). The demonstration results for 2025/26 will be reported in D5.4 (not yet available).

Key claims

Market scale and liquidity gap

• Markets grew from 3 areas (2023/24) → 10 (2024/25) → 12 areas (2025/26): 11 winter markets + 1 summer pilot
• 25.2 MW pre-qualified vs 59.5 MW total DSO need across all markets — 42% fill ratio; the clearest quantification to date of Sweden’s local flex market liquidity deficit
• 10 qualified FSPs, 19 assets: BESS, district heating assets, reserve generators, and a building with heat pumps + EVs (as of end of 2024/25 season)
• Each market aims to have needs expected for at least 3 years before launching (except the summer pilot)

Halland summer market — full design

Production-driven congestion has a three-factor cause: (1) high solar/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, and 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).

Market design choices (Halland, summer 2025):

• Period: June 1 – September 30, 2025
• Pre-study evaluated DSO-FSP vs P2P; DSO-FSP chosen for better controllability, scalability, and integration with the established SWITCH platform
• Product: 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% on winter markets — to incentivize participation by intermittent production resources where full delivery cannot be guaranteed)
• Trading time adjustment: call-off time moved to 08:30 (earlier than 10:30 on other markets) due to FSP feedback on 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 (separate DSO within the market area)
• At market launch (June 1): 32.5 MW qualified — solar park, wind park, BESS (one resource in Falkenberg Energi Elnät’s grid)
• New barrier found: chain of actors (resource owner ≠ technical controller ≠ trader ≠ BRP) creates coordination complexity; intraday participation near-zero due to imbalance cost risk; batteries face potential network tariff charges from consumption peaks when downregulating (charging = increased consumption)
• Future market periods could extend season (solar high in May) and add availability products

TSO-DSO coordination — trading time change

Key market design change for 2025/26: Aggregators reported that the previous D-2 18:30 availability call-off time was incompatible with their operations — most aggregators must send BRP instructions by D-2 12:00. Resolution: availability call-off time moved to D-2 10:30 for the upcoming season. This change specifically enables aggregators to participate in multi-market strategies without conflicting BRP obligations.

A coordination table (Table 3) in the report outlines the NC DR’s TSO-DSO and DSO-DSO coordination requirements: national T&C development, DSO observability areas, forecasting and detection requirements, data exchange protocols, and short-term temporary limit procedures.

SWITCH platform developments (2025)

Four development streams before the 2025/26 season:

1. Dremio data lake integration (meter data) E.ON’s internal Dremio data lake is integrated with SWITCH — meter data can now be automatically fetched for FSPs connected to E.ON’s grid. A 24-hour post-delivery delay is defined before final settlement validation (to ensure all meter data is collected). Only applicable to FSPs on E.ON’s own grid. Reduces the manual meter data submission requirement that is a major onboarding barrier for many FSPs.

2. Downregulation configuration New configuration option in SWITCH for resources to specify whether they provide up- or downregulation (or both). Four modes:

1. Reduced consumption (up) — standard winter market case
2. Increased consumption (down) — summer market: charge battery / use more power
3. Reduced production (down) — summer market: curtail solar/wind
4. Increased production (up) — standard

Modes 2 and 3 are used for the Halland summer market. This enables the SWITCH platform to support both production-driven (summer) and consumption-driven (winter) congestion markets.

3. Congestion forecast evaluation tool New page in SWITCH tracking forecast performance systematically: compares forecast values to real-time metering and activation limits per congestion event; shows which quantities above the limit were accurately predicted or not. Also tracks per-event history (order creation, activations) with chart visualization. Allows DSOs to identify which forecast model best suits each substation.

4. Seasonal availability fully in-platform (DIS-compatible) Full in-platform support for the seasonal availability (Säsongstillgänglighet) procurement workflow, aligned with DIS (Dynamiskt inköpssystem). Previously: bilateral agreements established outside SWITCH. Now: DSO creates a tender for availability capacity over a specified period; FSPs bid (lowest price per MWh wins, clearing visualized in platform); schedules automatically generated for awarded FSPs; supports:

• Endurance preview: FSPs can see estimated remuneration at different endurance levels before submitting
• Shared orders: scheduled orders can span multiple substations — purchasing coordinated across DSO needs
• Availability payment calculation: automatic after schedule period, accounting for delivery validations Planned to cover 1–3 month periods; all suitable markets in 2025/26.

5. NC DR resource qualification alignment Resource qualification in SWITCH being updated to include more detailed sub-resource categorization (heat pumps, batteries, EV chargers, etc.) with max capacity per sub-resource — aligning with NC DR national data requirements for flexibility market participants.

FSP portfolio: E.ON EIS multimarket strategy

FCR-D price decline as driver: FCR-D prices have declined significantly since 2023, making BESS 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.

Demo case 3 — Heat Flex (heat pumps, commercial buildings):

• Phase 1 (winter 2024-25) delivered approximately 20% electricity cost reduction through day-ahead price optimization using building thermal inertia
• Technology: ectocloud™ platform (E.ON EIS) + Energy Manager IoT gateway → BMS → heat pump control
• Mechanism: heat the building more during cheap hours, less during expensive hours; comfort maintained within ±0.5°C tolerance (“Building as a Battery”)
• ~1 MW potential aggregated flexibility; 200 kW currently connected
• Future business model: subscription SaaS for BTM services; FTM services (LFM/balancing) to be added via revenue-sharing model

Demo case 4 — District heating multimarket:

• Aggregated target: 36 MW across district heating assets (CHPs, heat pumps, boilers)
• mFRR prequalification underway for feasible assets
• Value pool progression: Day-ahead → LFM → Intraday → mFRR capacity + energy activation
• VPP integration: ectocloud → E.ON VPP → SWITCH (LFM) and TSO portal (mFRR); control room operators manage activation
• First flexibility delivered in November 2023 (3 MW from DH-coupled heat pumps, Södra Skåne)

Demo case 1 — BESS LFM summer market:

• Falkenbergsenergi’s 312 kW / 401 kWh BESS; primarily front-of-meter (FTM)
• Revenue consideration: 2 hours LFM summer delivery should offset 6–8 hours loss of FCR-D revenue
• Zero-baseline for BESS: downregulation = increased charging → risk of network tariff charges

Demo case 2 — BESS multimarket pilot:

• BESS configurations: standalone BESS, BESS+CHP/HP, BESS+PV; megawatt range; SE3/SE4
• Business case modelling: simulations to optimize size/type; multimarket strategy; bidding strategies; grid connection constraints (local tariffs affect case)

NC DR gap analysis

Gap analysis conducted spring 2025 to identify discrepancies between current qualification processes and NC DR requirements. Key finding: since much of the prequalification process depends on the FIS (Flexibility Information System), necessary platform adjustments cannot yet be determined — awaiting national FIS specification. Phased approach:

1. Participate in developing national T&C
2. Develop observability zones and data exchange frameworks
3. Apply and implement solutions

Both Swedish DSO and TSO identified TSO-DSO coordination as the element with the shortest implementation timeline.

Energy communities in Sweden

Chapter 9 explores energy communities (ECs) as a potential new FSP category and liquidity source. Key findings:

EU framework: RECs (Renewable Energy Communities, RED II Art. 22) and CECs (Citizen Energy Communities, IEMD Art. 13) are the two formal EU EC types.

Sweden’s situation: Four interviewed stakeholders (including one EC member) all confirmed ECs are effectively illegal in Sweden — no transposition of REC or CEC definitions into Swedish law. Key barriers: outdated legislation, lack of standardization, economic uncertainty, limited technical expertise, distrust between ECs and energy companies.

European country comparisons:

• Italy: leading — full Legislative Decree 199/2021 implementation; €110/MWh incentive for self-consumed renewable; €2.2B NRRP grants; 100+ communities by mid-2023
• Austria: swift transposition; 349 communities by 2022; clear REC/CEC separation; reduced grid tariffs; investment grants
• Denmark: strong tradition (wind/heat cooperatives); minimal legislative change needed; Samsø 100% renewable island
• France/Germany: partial transpositions; significant gaps

Barriers in Sweden (qualitative interviews):

• Legislation primary barrier (all 4 participants)
• Non-standardized data formats and tagging protocols for multi-resource integration
• Economic uncertainty in battery/storage investments
• Distrust between ECs and energy companies (“net negative” perception)
• GDPR data ownership concerns

EC flexibility potential: aggregated DR, local generation/storage, value stacking (DSO + TSO markets simultaneously).

Balancing market developments

• FFR: Volumes growing; transition to day-ahead capacity market planned for 2027
• FCR-D up: Need growing from 400 MW (2024) → ~500 MW (2026); prices already low, expected to remain low
• FCR-N: Demand stable at ~230 MW/h; prices ~10× higher than FCR-D
• aFRR: Volumes estimated to double from ~100 MW to ~200 MW by end-2026
• mFRR: Expected to grow

Relationship to existing wiki topics