Flex›NC DR Implementation in Sweden — What Changes and for Whom

NC DR Implementation in Sweden — What Changes and for Whom

The Network Code on Demand Response is not a single policy event but a rolling implementation of roughly a dozen interlocking obligations, each affecting a different actor. Some parts are already in force. Most are not. This synthesis maps what each actor faces, in what order, and why it matters.

What is already in force

Part of the NC DR framework entered force before the main regulation was adopted:

ACER Decision 05-2025 (FNAM) — published 25 July 2025 — established the Flexibility Needs Assessment Methodology. This is secondary EU legislation, directly applicable in all Member States, not requiring national transposition. Sweden’s first Flexibility Need Assessment under it is due July 2026 — a live process as of April 2026. The FNAM is the leading edge of NC DR implementation.

The Överenskommelse — the tripartite agreement between Svenska kraftnät, Ei, and DSO representatives (signed November 2025) is Sweden’s national implementation scaffold for FNA 2026. It pre-operationalizes the FNAM requirements into concrete reporting obligations before the main NC DR regulation exists.

Everything else — the FIS, local services markets, grid prequalification, DNDP local services requirements, TSO-DSO coordination framework — waits for the main regulation’s entry into force, expected 2026, and then further national implementation by Ei across seven T&C domains.

The implementation architecture

The NC DR does not self-execute. It requires Ei to develop national terms and conditions (T&C) in approximately seven domains — each requiring public consultation:

  1. Service provider qualification
  2. Baseline methodologies
  3. Flexibility Information System (FIS)
  4. TSO-DSO coordination framework
  5. Local services procurement rules
  6. Distribution Network Development Plan content and process
  7. Energy storage treatment

The regulation’s core deadlines are measured from “T&C approval” — not from entry into force. This means the clock restarts with each T&C domain. The effective implementation timeline is therefore:

NC DR entry into force (est. 2026)
    ↓
Ei develops national T&C (18 months per domain, sequenced)
    ↓
T&C approved → domain-specific clocks start
    ↓
FIS T&C approved → 2 years to update/replace existing platforms (SWITCH, NODES)
                 → 4 years to full interoperability
    ↓
Observability areas → 6 months from T&C approval

Sweden’s likely runway from entry into force to full FIS compliance: 5–6 years.

Actor-by-actor map

Ei — Energimarknadsinspektionen

Ei faces the largest regulatory production workload. As Sweden’s NRA under the NC DR, Ei must:

  • Approve derogations from market-based procurement (max 2 years per derogation, renewable; must specify which system segments, voltage levels, time periods, and products are covered). This means the current informal tolerance for Villkorade Avtal as the dominant congestion management tool becomes formally time-limited.
  • Approve national T&C across all seven domains — seven consultation processes, each requiring analysis, stakeholder engagement, and formal decision.
  • Oversee the FIS: if a third party operates it, Ei must verify business separation; Ei receives annual reports on non-approved and conditionally approved grid prequalifications.
  • Supervise DNDPs: require amendments if mandatory local services content is missing; ensure 6-week consultation standard is met.
  • Approve or contest the FNA: Ei is the supervisory authority — if Svk and DSOs cannot agree, Ei decides.
  • Approve alternative grid prequalification timelines (for voltage-level thresholds), alternative derogations for voltage control with reactive power, and any national derogation from product harmonization.

From Sweco’s 2025 analysis, four specific areas where Ei’s clarifications are most urgently needed (Source - Sweco Kartläggning av lokala flexibilitetsmarknader (Ei, 2025)):

  1. Define redispatching and when each flexibility tool is permitted (traffic light model)
  2. Clarify what “socioeconomic efficiency” means when comparing flex vs grid investment
  3. Establish methodology for responsibility and cost allocation across grid levels
  4. Clarify how “system operator” (NC DR concept) applies in Sweden’s multi-level DSO structure

Ei has already moved proactively through ställningstaganden (Ei2025:01 on Villkorade Avtal) and is developing TOTEX-based CAPEX reform for RP5 (2028). But the NC DR multiplies its regulatory agenda substantially.

Swedish DSOs (elnätsföretag)

DSOs face changes in four areas:

1. Flexibility Information System (FIS) The FIS will replace or absorb the current fragmented registration approaches. The register-once principle means DSOs can no longer maintain proprietary, incompatible resource registries. Existing platforms (SWITCH, NODES) may continue as transitional IT solutions, but must be updated or replaced within 2 years of FIS T&C approval. Vendor lock-in is explicitly prohibited — all data must be exportable in structured, machine-readable format.

2. Distribution Network Development Plans (DNDPs) Every DSO with relevant local services will be required to include a quantified local services assessment in its DNDP: forecasted needs, cost-effectiveness methodology, and medium/long-term estimates with locational granularity. This is currently best practice in Sweden but not universal, and the locational granularity requirement is new for most DSOs. The DNDP must feed the FNA — using the same Tabell 15 format — creating a data pipeline obligation, not just a disclosure one. (Source - ACER CEER DNDP Guidance (2025))

3. Market-based procurement obligation + derogation The NC DR formalizes market-based procurement as the default. DSOs that currently rely heavily on villkorade avtal must apply for Ei derogations — maximum 2-year terms, renewable. Each derogation must specify scope. This creates an annual compliance pressure and documents the transition trajectory. DSOs will need to demonstrate they have explored market alternatives before the derogation is renewed.

4. Grid prequalification and observability areas DSOs must define observability areas within 6 months of T&C approval and establish formal grid prequalification procedures with three defined outcomes (approved / conditionally approved / not approved). The default-to-approval rule (silence = approval) limits DSO discretion to block market participation. Annual reporting to Ei on non-approved and conditional cases creates transparency about where DSOs are constraining market access.

Who is most affected: larger DSOs running active flexibility markets (E.ON, Ellevio, Vattenfall Eldistribution, Göteborg Energi) face the most near-term work on FIS and DNDP. Smaller DSOs may not yet have local services markets but still face DNDP obligations if congestion is present.

Svenska kraftnät (TSO)

Svenska kraftnät faces NC DR implementation in two roles — as TSO and as FNA Designated Entity:

As TSO:

  • Formalize the observability area framework with Swedish DSOs (currently informal via the subscription mechanism and SO GL Art. 182 discussions)
  • Establish the grid prequalification coordination mechanism — the NC DR requires connecting and impacted SOs to coordinate grid prequalification results; Svk must build this into its processes for distribution-connected resources affecting transmission
  • Implement trade position consistency procedures (Art. 51): when a DSO activates local services after day-ahead gate closure, Svk must calculate imbalance adjustments for affected balance responsible parties — this requires data exchange not currently formalized
  • Conclude the SO GL Art. 182 TSO-DSO cooperation agreement (expected H1 2026; currently deferred from FNA 2026)

As FNA Designated Entity: produce and submit the national FNA every two years. FNA 2026 is live; FNA 2028 will be substantially more complex (energy data, transmission-level needs, guiding criteria, grid prequalification data, villkorade avtal/market split).

Key deferred item: Svk explicitly agreed not to report transmission-level flexibility needs in FNA 2026 due to methodology immaturity. FNA 2028 will need transmission needs included — requiring Svk to develop a methodology it does not currently have.

Aggregators and service providers

Aggregators and other service providers get new rights under NC DR:

  • CU switching within supplier-switching timeframes — reduces switching friction between aggregators; SOs cannot use slow processes to trap customers
  • Temporary qualification from application confirmation — aggregators can begin market participation before qualification formally completes
  • Small CU simplification (≤50 kW) — simplified qualification and exemption from near real-time data requirements; lowers the cost of aggregating household-scale resources
  • Market participation rights for flexible CA holders (Art. 31 §3) — a customer with a villkorat avtal retains full rights to bid into SWITCH or other markets alongside the CA; DSOs cannot exclude them
  • Table of Equivalences — one qualification, multiple revenue streams; if a resource qualifies for one product it may be automatically recognized for equivalent products, enabling value stacking across balancing and local markets

The business case for aggregating small DERs (EVs, heat pumps, batteries) improves with these rights — but the business case only materializes if local markets are liquid, and Swedish markets have thin demand (see Why Swedish Local Flex Markets Are Thin — Structural Causes).

Customers with villkorade avtal

Customers currently holding Villkorade Avtal are affected in two ways:

  1. NC DR Art. 31 §3 protects their market rights: a customer that signed a villkorat avtal cannot be barred from also bidding into a local flexibility market. The two roles are separate. This is a strengthening of their position.
  2. Art. 31 §2 formalizes the activation coordination: if a DSO activates a flexible CA after day-ahead gate closure, the TSO must make an imbalance adjustment to affected balance responsible parties. This creates a formal settlement mechanism for what is currently ad hoc.

What NC DR does not change

  • Ei2025:01 positions remain valid — the ställningstagande positions on villkorade avtal (DSO with physical constraint bears obligation; Ei must approve methods before signing; activation requires fresh per-dispatch assessment) are not superseded by the NC DR. They will coexist and likely inform Ei’s T&C development.
  • Bidding Areas — the NC DR does not affect Sweden’s four price zones or the bidding zone review process.
  • Balancing Markets — FCR, aFRR, mFRR structures are set by the SO GL and Nordic balancing arrangements, not by NC DR. NC DR improves access to these markets (qualification, data exchange) but does not redesign them.
  • Revenue regulation — the CAPEX bias is addressed through Ei’s RP5 TOTEX reform, not through NC DR. The NC DR’s market-first principle reinforces the reform’s direction but the mechanism is separate.

The three items most likely to slip

Based on what is currently deferred in FNA 2026 and what is structurally underdeveloped:

  1. SO GL Art. 182 TSO-DSO agreement — expected H1 2026; needed to formalize how Svk and DSOs manage simultaneous use of the same resources for local services and balancing. Currently no formal agreement exists. This is the linchpin for TSO-DSO coordination under NC DR.

  2. National FIS T&C — developing an interoperable national FIS from SWITCH and NODES (two proprietary platforms with very different architectures) is technically complex. The 2-year transition after T&C approval means the T&C development itself is the bottleneck. No Swedish entity has been designated as FIS operator; Ei has not begun the T&C process (as of April 2026).

  3. Villkorade avtal derogation management — the NC DR’s maximum 2-year derogation renewals will require DSOs to document that they have explored market alternatives before each renewal. For DSOs in areas where no market exists, this creates a circular problem: the market doesn’t exist because the DSO relies on the derogation, and the derogation doesn’t incentivize market development. Resolving this loop requires Ei’s clarification of when the Art. 13(3) exceptions are satisfied.