Network Code on Demand Response

The Network Code on Demand Response (NC DR) is a forthcoming EU regulation that will establish detailed, binding rules for how Demand Response, energy storage, distributed generation, and demand curtailment participate in electricity markets. It operationalizes the Clean Energy Package‘s high-level principles into concrete technical, procedural, and data exchange requirements.

As of May 2026, the NC DR is in the late stages of the legislative pipeline. ENTSO-E and the EU DSO Entity submitted a joint proposal in May 2024. ACER issued a substantially revised recommendation in March 2025 — including Annex 1, the near-final regulation text (85 pp, 10 Titles, 58 Articles). The Commission is drafting the final Regulation; entry into force is expected in 2026 but the Commission text has not yet been published. Ei is already designing the national T&C process in advance of formal adoption; Energiföretagen Sverige is coordinating member preparation. (Source - Flexibilitet Energiföretagen Sverige (web, 2025), Source - Ei NC DR Förberedelser (2025))

Why it matters

The Clean Energy Package established that demand response and storage must participate in markets on equal footing with generation (Regulation Art. 3(j)) and that DSOs must procure flexibility through market-based procedures (Directive Art. 32). The SO GL (Regulation 2017/1485) already provided a partial framework — reserve providing units/groups that include demand units, prequalification processes, and TSO-DSO cooperation on reserve delivery (Art. 182) — but left local flexibility markets and distribution-level participation largely unaddressed. The NC DR fills these gaps with:

• Standardized market access: a common pathway from resource registration to market participation
• Harmonized products: common attributes for flexibility services across the EU
• Mandatory infrastructure: flexibility registers, data exchange standards, prequalification processes
• Coordination rules: how TSOs and DSOs share flexibility resources and avoid conflicts

Key elements

The participation pathway

The NC DR defines a multi-step process to enter flexibility markets:

Controllable Unit (CU) registration
        │
Service Provider (SP) qualification
        │
SPU / SPG registration  ← group CUs for market participation
        │
Product prequalification / verification
        │
Grid prequalification  ← system operators verify grid safety
        │
Market participation

• A Controllable Unit (CU) is the atomic building block: a single resource or ensemble behind one metering point (battery, heat pump, EV charger, industrial process, etc.)
• A small CU is ≤ 50 kW — receives simplified qualification procedures and is exempt from CU-level near real-time data requirements
• A Service Providing Unit (SPU) groups CUs at one connection point
• A Service Providing Group (SPG) aggregates CUs/SPUs across multiple connection points — the formal mechanism for Aggregation
• Product verification (ex-post, the default for local services) is a lower-barrier process than full product prequalification (ex-ante, triggered when SPU/SPG capacity exceeds a voltage-level threshold)
• Temporary qualification applies from application confirmation until verification/prequalification completes — enabling immediate market participation

Simplification for small and identical CUs: where an SPU/SPG consists entirely of small CUs or of CUs identical to already-prequalified CUs, the evaluation process must be simplified and activation tests (if required) limited to a sample. (Source - NC DR Amended Text (ACER Recommendation 01-2025 Annex 1))

Flexibility Information System (FIS)

Each Member State must establish a Flexibility Information System — the central national register for all flexibility market participation. The regulation text specifies in detail (Arts. 24–28):

• Single common access point per country with both GUI and API (ETSI-CEN-CENELEC standards)
• SP module (9 defined procedures: registration, application, update, suspension, de-registration, grid prequalification, switching, revocation, confirmation)
• CU module (9 defined procedures: registration, update, suspension, de-registration, grid prequalification, switching, revocation, termination, re-activation)
• Data portability: all data exportable in structured, machine-readable format to prevent vendor lock-in; defined migration procedure
• Register-once principle: SPs and system users register and update data only once — no duplicate data entry across DSOs
• Unbundling: if a third party operates the FIS, it must have adequate business separation from parties with commercial interests in local services
• Timeline: FIS T&C developed within 18 months of rules approval; existing systems updated or replaced within 2 years of T&C approval; full interoperability within 4 years of entry into force

Transitional provision: existing platforms (e.g., SWITCH, NODES) may continue operating until the national FIS is implemented. They must be updated or replaced within 2 years of FIS T&C approval. This gives Sweden a runway of roughly 5–6 years from entry into force before full FIS compliance is required. (Source - NC DR Amended Text (ACER Recommendation 01-2025 Annex 1))

Swedish FIS process: In September 2025, the Swedish government issued an assignment to Ei and Svenska kraftnät to develop a proposal for a centralt datahanteringsverktyg (central data management tool) — explicitly naming the NC DR FIS requirement as context. The government cancelled the old 2015 elmarknadshubb mandate to Svk at the same time. Proposal due 30 September 2026. See Elmarknadshubb. (Source - Uppdrag Centralt Datahanteringsverktyg (2025))

In early 2026, Ei and Svk published a consultation document presenting the emerging design: a two-component architecture of DHV (centralt datahanteringsverktyg, handling market master data and settlement) and FIS (flexibilitetsinformationssystem, handling DER registration, qualification, measurement, verification, and settlement basis for flexibility deliveries). Svenska kraftnät is proposed as the operator. Key FIS design elements aligned with NC DR Arts. 24–28: single national registration (register-once principle); no duplicate entry across DSOs or platforms; FIS verifies delivered flexibility by comparing reference profiles with actual metering; provides settlement basis for all affected actors. Critical sequencing: DHV v1 must go live before FIS, as FIS depends on DHV’s delivery structure. (Source - Ei Förslag Centralt Datahanteringsverktyg (2026))

Local services markets

The NC DR gives detailed rules for DSO-level flexibility procurement (Title IV, Arts. 29–39):

• Market-based procurement is the default (Art. 29 §2) — non-market solutions require NRA derogation (Art. 30), max 2 years, renewable; voltage control with reactive power may have longer derogations
• Products can include energy-only payments, capacity payments, or combinations (Art. 35)
• Flexible connection agreements (Art. 31) — the EU-level equivalent of Villkorade Avtal — are explicitly recognized but with three binding requirements: (1) counted as firm connections in needs assessments; (2) activation must coordinate with market-based procurement; (3) system users holding flexible CAs retain full rights to participate in local services and balancing markets
• Local market operators can be DSOs, TSOs, or third parties — must be neutral (Art. 33)
• Transparency: market results published within 1 day; single national access point for all market information (Art. 37)
• Product harmonization: 14 mandatory attributes for all active power products (Art. 38); SOs must standardize products and avoid fragmentation (Art. 39)
• 3-year mandate: ENTSO-E and EU DSO Entity must develop a Union-wide procurement harmonization methodology within 3 years of entry into force (Art. 32 §6)

Commission Recommendation C(2026)2850, Rec 28, complements NC DR Art. 28–35 by explicitly requiring Member States to ensure that minimum bid sizes, contract durations, market access models, and prequalification requirements allow smaller aggregated assets managed by energy communities or energy sharing groups to participate in local energy service markets — directly or through an aggregator. Regulatory sandboxes for testing these design elements are encouraged. This is soft law but directionally aligned with NC DR’s small-CU simplification provisions. (Source - Commission Recommendation C(2026)2850 Energy Communities)

(Source - NC DR Amended Text (ACER Recommendation 01-2025 Annex 1))

TSO-DSO coordination

A detailed framework for how TSOs and DSOs share the flexibility resource pool (Title VII, Arts. 45–52):

• DSOs define observability areas — their own grid plus relevant parts of adjacent systems. Must be established within 6 months of T&C approval and reviewed with each DNDP update (Art. 46)
• Congestion forecasting across multiple timeframes: day-ahead → intraday → real-time, at ≤1 hour granularity (Art. 47)
• Grid prequalification (Art. 49): before or parallel to product qualification, connecting and impacted SOs assess grid safety and assign one of three statuses:
  • “Grid prequalification approved”: delivery respects operational security limits
  • “Grid prequalification conditionally approved”: only under specified time/quantity conditions
  • “Grid prequalification not approved”: full justification required; why temporary limits cannot address the issue must be explained
  • Silence = automatic approval if SO doesn’t respond before the deadline
  • Annual reporting to NRA on non-approved and conditional results
• Temporary limits (Art. 50): short-term procedure; must be communicated at least 1 hour before balancing energy gate closure; SOs must minimize market impact
• Trade position consistency (Art. 51): if local service activation occurs after day-ahead gate closure, the activating SO must compensate via opposite-direction activation or netting
• Data exchange (Art. 52): structural, schedule/forecast, and real-time categories; requirements reviewed every 2 years

(Source - NC DR Amended Text (ACER Recommendation 01-2025 Annex 1))

Table of Equivalences

A mechanism for value stacking: if a resource is prequalified for one product, it may be automatically recognized for others with equivalent requirements. This transforms the business case for flexibility — one qualification, multiple revenue streams.

Independent aggregation models — moved to EB GL

A significant regulatory architecture finding from the EC’s 2025 LFM study (VITO): provisions on independent aggregation models — specifically perimeter correction mechanisms and BRP financial compensation arrangements — were removed from the current NC DR as proposed by ACER and will instead be addressed through updates to the Electricity Balancing Guideline (EB GL, Regulation 2017/2195). The current NC DR text “leaves room to have different aggregation models in different Member States.”

This has direct consequences for the Swedish BSP/BRP implementation debate:

• The regulatory home for cross-BRP aggregation compensation (the mechanism that allows an aggregator to activate resources across BRP boundaries without leaving BRPs with uncompensated imbalances) is the EB GL, not the NC DR
• Sweden’s current “paper construction” BSP — where an actor must already hold a BRP agreement to sign a BSP agreement — is a national implementation of EB GL Art. 18, not a transposition of NC DR
• NC DR sets the market access rights for independent aggregators (registration, qualification, CU switching, SPG formation) but deliberately leaves the financial compensation architecture to EB GL

The practical implication: Sweden cannot wait for NC DR adoption to fix the BSP/BRP problem. The obligation has been in the EB GL since December 2020. Full free-standing BSP by 2028 is an EB GL compliance matter. NC DR’s T&C process will not resolve it.

(Source - EC LFM Specification and Design Criteria (VITO, 2025), Source - EB GL (Regulation 2017-2195))

DSO sector’s critical NTC drafting priorities (DSO Entity 2026)

The DSO Entity Expert Group on Distributed Flexibility approved a knowledge-sharing report in February 2026 (Source - DSO Entity Distributed Flexibility Practices (2026)) identifying five critical regulatory actions (A1–A5) that must be addressed in NC DR national terms and conditions (NTC) drafting, without which LFMs may fail or fragment across Member States:

A1 — Compensation effect scope: The current NC DR text defines “compensation effect” as covering only non-activated CUs behind the same connection point. The DSO Entity argues this is too narrow: the compensation effect should cover all technical resources behind the service validation point — the DSO grid measurement point where service delivery is verified. Without this, baseline calculations will systematically under-credit aggregated portfolio flexibility, discouraging participation by multi-CU SPGs.

A2 — Single-CU site registration: NTC should explicitly allow registering an entire site as a single CU (not device-by-device). This reduces registration burden for customers with multiple DER assets, enables site-level aggregation without individual device registration, and aligns with how DSO metering actually works (site-level meters, not device-level).

A3 — Technical vs Commercial Aggregator distinction: NC DR uses “aggregator” as a single role. In practice two distinct roles exist that NTC must differentiate:

• Technical aggregator: manages the DER connectivity and control layer — ensures DERs receive and respond to signals; provides communication infrastructure
• Commercial aggregator: manages the market interface — submits bids, receives settlement, manages commercial relationships with resource owners

A single entity may perform both roles or they may be separated. NC DR NTC must clarify which regulatory obligations attach to which role.

A4 — Service validation point: The point at which delivered flexibility is measured for settlement. NC DR leaves this underspecified. NTC must define it precisely, distinguish it from the “connection point,” and specify data quality, timing, and measurement responsibility.

A5 — Digital connecting SO: A new functional role for the entity responsible for the digital communication layer between CUs and the market when this differs from the physical grid operator. As VPPs and cross-DSO service provision become common, the physical and digital connecting SO may diverge. NTC must clarify which obligations (data provision, metering, settlement) attach to this role.

These five actions directly shape Sweden’s NTC process. Ei’s T&C development work will need to address A1–A5 explicitly — they are not resolved by the current ACER Annex 1 text.

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

Open questions and tensions

The ACER recommendation reveals significant disagreements that will shape the final regulation as the Commission drafts it. ACER’s Annex 1 text leaves several values in brackets, signalling that the Commission retains discretion:

(Source - ACER Recommendation 01-2025 on NC DR, Source - NC DR Amended Text (ACER Recommendation 01-2025 Annex 1))

Distribution Network Development Plans (DNDPs)

Title VI of the NC DR (Arts. 43–44) specifies binding content requirements for DSO network development plans:

Mandatory DNDP content (Art. 43):

• Planning framework demonstrating effective and cost-efficient measures, including consideration of local services as alternatives to investment
• Scenario(s) covering 5–10 year futures, coordinated with transmission development plans and between relevant system operators
• Investment plans for distribution infrastructure, metering, and control systems
• Local services section per Art. 44

Local services in DNDP (Art. 44): This is not optional. Where local services are deemed relevant and cost-effective based on the Art. 29 assessment, the DNDP must include:

• DSO’s assessment of forecasted local service needs
• Description of cost-effectiveness assessment methodology, criteria, data, and results
• Medium and long-term local service estimates with locational and time granularity

Process: 6-week minimum public consultation. NRA may request amendments. Final DNDP published on DSO website and on a central platform.

The DNDP requirement links directly to the FNA: the biennial Art. 29 needs assessment is used to fill the DNDP’s local services section, and the DNDP’s estimated needs feed into the next FNA cycle. (Source - NC DR Amended Text (ACER Recommendation 01-2025 Annex 1))

The ACER/CEER guidance on distribution network planning (July 2025) elaborates extensively on how NC DR Arts. 43–44 should be interpreted in practice: the three-pillar planning process (scenario development → grid capacity needs → project identification), the requirement to use the FNAM Tabell 15 format, and the expectation that contractual arrangements (including flexible connection agreements) be specified alongside market-based flexibility options. Portugal is cited as the EU benchmark for DNDP flexibility quantification. See Distribution Network Development Plan for full detail. (Source - ACER CEER DNDP Guidance (2025))

Art. 29.1 — biennial assessment linking FNA, DNDP, and NC DR

NC DR Art. 29.1 requires each system operator at least every two years to perform an assessment of the need for and procurement of DR/storage/other resources as alternatives to system expansion. This assessment:

• Must consider the national Flexibility Need Assessment (FNA) report under Art. 19e of Regulation 2019/943
• Is used to fulfill DNDP obligations under Directive Art. 32(3) and 51(3)
• Must be publicly consulted on

Art. 31.1: When conducting this assessment, flexible connection agreements (Villkorade Avtal) shall be treated as firm connection agreements — the full underlying grid constraint must be reported, not a reduced figure because some capacity is already contracted. Only permanent solutions under Art. 6a.1.c are exempted. (Source - FNA Webinar 7 (2026-03-16))

FNA — already in force

One part of the NC DR framework is already in force as of July 2025: ACER Decision 05-2025 establishing the Flexibility Needs Assessment Methodology (FNAM). This is secondary EU legislation directly applicable in all Member States, adopted ahead of the main network code.

The FNAM requires TSOs and DSOs to produce a national Flexibility Need Assessment every two years. Sweden’s first FNA is due July 2026 — a live process as of April 2026, coordinated by Energiföretagen Sverige and governed by a tripartite agreement between Svenska kraftnät, Ei, and DSO representatives. (Source - FNA Överenskommelse Svenskt genomförande 2026 (2025), Source - Flexibilitetsbehov FNA Energiföretagen Sverige (web, 2026))

Swedish implications

The NC DR will significantly reshape the Swedish flexibility landscape:

1. Ei will need to develop national terms and conditions across ~7 domains: service provider qualification, baselining methods, FIS, TSO-DSO coordination, local market procurement rules, DNDPs, and energy storage. Each requires public consultation and Ei approval. Ei has been preparing the process design for SO participation in T&C development from November 2025 — ahead of the regulation’s adoption. The statutory deadline is 12 months after entry into force. Project leader: Yuri Joelsson. A study mapping European T&C process models was launched in early 2026. Sweden’s ~170 DSOs present a significant representation challenge vs countries with one or two large DSOs. (Source - Ei NC DR Förberedelser (2025))

Governance structure: Energiföretagen Sverige‘s Eldistributionsrådet and AG Flex Elnät proposed a “hybrid solution” in April 2024 — formal decision-making process hosted within Energiföretagen but open to all DSOs (including non-members of Energiföretagen) and Svenska kraftnät. This is structurally unprecedented: Sweden’s DSOs have never had a formal role in developing binding sector regulation (prior network codes such as RfG were assigned to Svk). The statutory obligation: within 3 months of NC DR entry into force, all DSOs + Svk must jointly submit a national process proposal to Ei; Ei then has 2 months to approve it. Ei R2023:18 (Ei + Svk + Swedac) also recommended studying a nationally legislated organization as an alternative to industry self-organization. (Source - Energiföretagen NC DR National Conditions Webinar (2024)) 2. Villkorade Avtal get EU-level recognition as “flexible connection agreements” but: (a) activation must coordinate with markets; (b) customers holding flexible CAs retain full market participation rights (Art. 31 §3) — they cannot be excluded from bidding into SWITCH or other local markets. 3. Svenska kraftnät and Swedish DSOs will need formalized coordination: DSO observability areas, data exchange agreements, grid prequalification processes, and temporary limits procedures — all formalized within 6 months of T&C approval. 4. A national FIS must be established. Sweden’s existing platforms (SWITCH, NODES) can continue during transition, but must be updated or replaced within 2 years of FIS T&C approval. The register-once principle and data portability requirements will transform the relationship between DSOs and platform operators. 5. DNDP requirements: Swedish DSOs will be required to include a quantified local services assessment in their network development plans, with locational granularity — a major transparency upgrade from current practice. 6. Grid prequalification formalization: the three-status system (approved/conditionally approved/not approved) will constrain DSO discretion to block SPU/SPG market participation on vague grid safety grounds. 7. Aggregators get standardized market access rules (CU switching within supplier-switching timeframes, simplified qualification for small/identical CUs, prohibition on SOs limiting flexible CA customers from market participation).

The two-pillar regulatory structure for flexibility technology

NC DR defines the market rules for flexibility — how resources register, qualify, and participate. It explicitly does NOT define the technical protocols or data formats that devices must use for communication. The technical layer is governed by a separate instrument:

IA DR — Implementing Act on Demand Response (under Arts. 23–24 of Directive 2019/944): a companion data interoperability implementing regulation, developed jointly by ENTSO-E and EU DSO Entity, specifying the data exchange processes that underpin flexibility market participation. Entry into force estimated 2027. This is the second regulatory pillar alongside the NC DR:

• NC DR = market rules (registration, qualification, products, markets, coordination)
• IA DR = data interoperability processes (CU/SPG registration, baseline calculation, service quantification, settlement)

Timeline: Phase 1 submitted to the European Commission Q2 2025; Phase 2 Q4 2025. The IA DR builds directly on IR 2023/1162 (metering data) — the same 5-layer EU reference model applies (business, function, information, communication, component). A national EU reference model database starts June 2025.

Scope: The IA DR covers information exchange in contexts where DSOs are directly involved: (1) customers in the DSO grid participating in balancing markets; (2) DSO procuring congestion management or voltage control services; (3) DSO with flexible connection agreements (villkorade avtal).

New functional roles introduced by the IA DR (not in IR 2023/1162):

• CU Module Operator — party managing the CU-module of the FIS (stores and distributes CU data)
• SP Module Operator — party managing the SP-module of the FIS (stores and distributes SP data)
• Baseline Calculator — calculates baselines per NC DR Title II
• Baseline Provider — nationally assigned party distributing calculated baselines to entitled parties
• Quantification Aggregator — aggregates metering/measurement data across CUs for settlement
• Quantification Responsible — calculates baseline vs actuals difference for settlement

Phase 1 processes (15): CU registration/update/de-registration/suspension/re-activation, service provider registration, service contract revocation/termination, baseline data handling, service delivery quantification, settlement, SP switching, third-party CU operator registration, plus general register access.

Phase 2 processes (18): Adds SPG/U registration/qualification/switching/revocation processes, CU grid prequalification/switching/termination, product verification, flexibility product activation, flexible connection agreement management, temporary limits, bidding.

(Source - Svk IA DR Webinar Part 1 (2025), Source - Energimyndigheten ER 2025-35 Förbättra Flexibiliteten (2025))

For the full protocol landscape that the Art. 24 Implementing Act will regulate, see Flexibility Communication Protocols.

NC DR staggered activation

NC DR requires that TSOs and aggregators do NOT send simultaneous activation commands to all managed devices — staggered dispatch is required. This addresses the systemic risk of simultaneous implicit flexibility response (the “synchronisation risk” documented in Source - FlexAbility Delrapport 5 (2025) and ER 2025:35). See also Demand Response › Synchronisation risks and random startup delay.

Relationship to existing wiki concepts

• Flexibility: the NC DR is the detailed implementation layer beneath the CEP’s high-level flexibility framework
• Demand Response: gets its own network code — the first EU regulation specifically focused on demand-side participation
• Villkorade Avtal: recognized as “flexible connection agreements” but subjected to market coordination requirements
• Clean Energy Package: the NC DR is the operational child of the Directive Art. 32 and Regulation Art. 3/6/13
• Bidding Areas: local services markets operate within bidding zones; the NC DR doesn’t change zone boundaries but structures how congestion is managed within them
• Flow-Based Capacity Calculation: the NC DR’s TSO-DSO coordination framework operates alongside the capacity calculation methodology
• Flexibility Communication Protocols: the technical protocol mandate runs in parallel to NC DR via the Art. 24 Implementing Act