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 June 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; adoption via comitology is now expected Q4 2026–Q1 2027 (per ENTSO-E’s June 2026 Balancing Report), and 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))

Adoption procedure timeline: ACER submitted its draft implementing regulation to the European Commission in March 2025; the Commission held a public consultation July–September 2025; the comitology procedure began March 2026. As of ENTSO-E’s June 2026 Balancing Report, adoption by the Commission via comitology is now expected in Q4 2026–Q1 2027 — later than the “summer 2026” timeline earlier Swedish preparatory materials assumed. Following adoption and entry into force, TSOs are expected to develop and amend relevant T&Cs and methodologies at both Union-wide and national level. (Source - Ei Ställningstagande Ei2025-01 Villkorade avtal (2025), Source - ENTSO-E Balancing Report 2026)

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:

• 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. FIS T&C is itself due 18 months after national rules-of-procedure approval, giving a combined 3.5-year runway from rules-of-procedure approval to full FIS compliance — the further gap between entry into force and rules-of-procedure approval is not quantified in the amended text. (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. The joint proposal was delivered in September 2026 (Ei R2026:08). 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))

The final report (Ei R2026:08, September 2026) keeps this sequencing and warns of a greater risk of a time gap between the NC DR’s implementation requirements and the DHV delivering what the FIS needs if the DHV is built from scratch rather than from the earlier Elmarknadshubb material. Because the NC DR is not yet adopted, it does not introduce a national definition of flexibilitetsleverantör; the term corresponds mainly to the NC DR proposal’s “service provider”. The FIS fee would fall on flexibility providers (per active resource) and, for local-market functions, on grid companies. (Source - Ei R2026-08 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’s prequalification (Art. 18) and product-definition (Art. 38) provisions 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. Svk’s national-terms obligation under the EB GL was met on time (proposal submitted 2018, per Art. 18.1’s six-month deadline) — the years-long gap to a functional, free-standing BSP by 2028 is Ei’s approval process taking that long, not a missed EU deadline. 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)) setting out 11 recommendations for NC DR national terms and conditions (NTC) drafting, five of which carry a Critical Regulatory Action (A1–A5):

A1 — Regulate Technical Aggregation and strengthen cybersecurity requirements (under R5, securing flexibility value end-to-end): Technical Aggregators — and other cloud-hosted control infrastructure, often operated outside the EU — can create a legal void in end-to-end accountability. NC DR should secure end-to-end responsibility regardless of how SP/aggregator roles are split, and require aggregator control structures and staff to sit within the EEA; cybersecurity regulation alone (Network Code on Cybersecurity, NIS 2) is judged insufficient on its own.

A2 — Enable registration of resources beyond the service validation point as a single CU (under R8, FIS modules): in addition to per-device registration, NTC should let an entire site register as one controllable unit — reducing registration burden for multi-DER customers and matching how DSO metering (site-level, not device-level) actually works.

A3 — Improve the “compensation effect” concept (under R9, physical delivery): ACER’s draft NC DR text (Arts. 12–15) currently scopes compensation effects to non-activated CUs behind the same connection point only. DSO Entity argues this should extend to all technical resources behind the same service validation point, registered or not — otherwise baseline calculations will systematically under-credit aggregated portfolio flexibility.

A4 — Ensure grid reliability/safety and non-discriminative flexibility development as two independent processes (also under R9): non-discriminatory product qualification regardless of asset size or history; DSO Entity specifically cautions against lowering the minimum balancing bid size from 1 MW to 0.1 MW, which would add complexity and cost to European balancing platforms without a corresponding gain.

A5 — Define provisions for data-exchange standardisation within the NC DR framework (under R11): common standards (e.g. IEC 62325-x, IEC 62746-4 aligned with CIM) need to be ready before digital platforms are built, to avoid market fragmentation and vendor lock-in.

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. Note: the report frames DSOs as evolving toward “Digital Connecting System Operators” in its conclusions (and under R8) — this is a general role description, not itself a numbered critical action, and there is no separate “technical vs. commercial aggregator” critical action in the report.

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

Interaction with the July 2026 tariff proposal (DSO Entity view)

The Commission’s proposal to amend the Electricity Regulation (COM(2026) 600) would require network-tariff methodologies to enable non-fossil flexibility such as storage and demand response (Art. 18(2)(k)) and to let storage charges reflect network benefits (Art. 18(2)(n)). The EU DSO Entity asks for both to be deleted: point (k) duplicates Art. 18(2)(c) and mixes tariff methodology with revenue regulation, and point (n) would turn tariffs into a tool for remunerating flexibility, which it says should be done through the market or procurement and, in future, the NC DR’s own mechanisms; tariffs should mainly deliver implicit flexibility (DSO Entity’s reaction). The same paper describes the NC DR as “forthcoming” and lists it among the network codes that already govern system-operator data exchange, against Art. 18a(4).

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))

“Flexibility first” depends on national implementation. An industry outlook for 2035 argues that NC DR establishes a “flexibility first” direction, but whether that becomes a real priority over flexible connection agreements, tariffs and direct control depends on how member states implement it and on whether system operators are clearly incentivised to prefer markets. It also argues that simple, low-friction market access matters more in early markets than a perfect design, because lower barriers do not by themselves create liquidity (smartEn and LCP Delta 2026, written for the demand-flexibility industry association).

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 oversee and approve national terms and conditions across ~7 domains (proposed jointly by Svk and the DSOs): 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 168 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.

Staggered activation (Energimyndigheten’s reading)

Energimyndigheten’s ER 2025:35 says the proposed NC DR bars TSOs and aggregators from sending a start command to all their controlled devices at the same time, to avoid a load peak when devices restart after a control action (Source - Energimyndigheten ER 2025-35 Förbättra Flexibiliteten (2025)). The report cites only a personal communication (Nibe, 2025-10-02) and gives no article, and no such provision was found in the NC DR texts reviewed for this wiki (the amended text in ACER Recommendation 01-2025 Annex 1 and the ENTSO-E/EU DSO Entity proposal), so treat it as unverified, not a quoted article. The point 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 › 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 — see Coordinating Market-Based and Rules-Based Flexibility under NC DR for the full coordination-design analysis
• 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

Data gaps

• Whether an FSP has any appeal path against a DSO’s Art. 49 grid-prequalification “not approved” outcome, beyond the DSO’s justification requirement and annual NRA reporting — no article specifying an appeals/dispute-settlement mechanism has been identified, and it’s unclear whether Ei‘s tillsyn function (documented for DSO tariff/fee complaints) extends to FSP-side prequalification or curtailment disputes