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

Metadata

What this source is

This document is the actual regulation text as ACER proposes it should read — Article by Article, with ACER’s own drafting amendments incorporated. It is distinct from Source - ACER Recommendation 01-2025 on NC DR, which summarizes ACER’s analysis and positions. This Annex 1 is the legal text itself: 10 Titles, 58 Articles, directly applicable once adopted by the Commission and published in the Official Journal.

Bracketed elements (e.g., “[18 months]”, “[without undue delay]”) indicate values or phrases where ACER proposed changes but the Commission retains discretion to finalize.

Structure

Key definitions (Art. 2)

Title I — General Provisions

Art. 4 — National rules of procedure: National implementation rules must be approved by the NRA before any T&C processes begin. The sequence: national rules of procedure → then T&C development across seven domains (service providers, baselining, FIS, TSO-DSO coordination, local market procurement, DNDP, storage).

Art. 6 — Public consultation: Mandatory public consultation before adoption of each T&C. Minimum 1-month consultation period. NRA approval required.

Art. 9 — Cost recovery: T&C must specify cost recovery arrangements. Costs of FIS operation, prequalification, and market platform operation are borne by system operators — not passed to SPs as entry barriers.

Title II — General Requirements for Market Access

Art. 11 — National T&C for service providers: All SOs in a Member State jointly develop a single set of T&C. Must cover at minimum: qualification criteria (Title III), application procedures, data requirements, right to switch SPs, and rules consistent with Arts. 12–15.

Art. 13 — Dedicated measurement devices: When required by the T&C, SPs shall install dedicated measurement devices. But: small CUs with smart meters may use the smart meter data instead of dedicated devices, under conditions specified in T&C.

Art. 14 — Baselining methods T&C: A national register of approved baselining methods must be published and updated. Methods must be transparent, verifiable, non-discriminatory, and technology-neutral.

Art. 15 — Baseline validation: SPs are responsible for validating baselines. T&C shall specify the validation process; SPs must store metering data for validation. (Relevant context: SWITCH uses MBMA as its default baseline method.)

Title III — Qualification

Art. 16 — Table of Equivalences: Each Member State defines a national Table of Equivalences linking local products to balancing products. Resources prequalified for one product are automatically recognized for equivalent products — enabling value stacking without repeated prequalification.

Art. 17 — SP qualification: SPs must register once nationally. A European-wide unique SP identification code is assigned. Qualification is transferable between system operators via the FIS; no re-qualification when switching to offer the same product to a different SO.

Art. 18 — Product verification vs prequalification:

• Product verification (ex-post) is the default for local services
• Product prequalification (ex-ante) applies when the potential SPU/SPG capacity exceeds a voltage-level-specific threshold defined in national T&C
• Application confirmed within [X business days]; temporary qualification applies from confirmation until verification/prequalification complete (Art. 19 §1)
• For prequalification: activation test only required where necessary for system security (Art. 20 §2)
• Simplification for small/identical CUs (Art. 20 §3): where the SPU/SPG consists exclusively of small CUs or CUs identical to already-prequalified CUs, the evaluation process must be simplified and any activation test performed on a limited sample only

Art. 21 — Further harmonization: Within 12 months of entry into force, ENTSO-E and EU DSO Entity shall develop a Union-wide methodology for further simplification of prequalification processes, including identifying cases where prequalification can be replaced by verification.

Art. 22 — Reassessment criteria: A procuring SO may (if allowed in national T&C) require a new verification/prequalification if:

• Capacity changed >10% or 5 MW (whichever lower), and at least 0.5 MW
• ICT system for SPU/SPG control changed
• Last qualification was >5 years ago AND the product has not been provided to any SO in the last 12 months
• Previously used activation test results (<3 years old) for unchanged CUs can be reused

Art. 23 — CU switching between SPs: System operators must process a CU switch. Switching timeline must not exceed the supplier switching time under Directive Art. 12(1). Default: grid prequalification not required if SO doesn’t respond within the deadline. (Enabling independent aggregators to recruit CUs from other SPs without SO delays.)

Title III Chapter 2 — Flexibility Information System

Art. 24 — FIS T&C: All SOs of a Member State shall develop national FIS T&C within [18 months] after rules of procedure approval. Full interoperability deadline: [4 years] after entry into force.

Art. 25 — Governance, accessibility, interoperability:

• One common national FIS with single common access point
• Both GUI (graphical user interface) and API at national level
• Data portability: all SP module and CU module data must be exportable in structured, machine-readable format with a defined migration procedure — to prevent vendor lock-in
• If a centralised FIS with a single SP and CU module is established, the national T&C specifies which single SO (or group of SOs or other entity) is responsible

Art. 26 — SO responsibilities for FIS:

• Non-discriminatory data access
• ETSI-CEN-CENELEC standards for API
• Test environments with test data for all participants
• SPs and system users register and update data only once (no duplicate entry)
• Unbundling: if a third party operates the FIS, it must have adequate business separation from parties with commercial interests in local services (Art. 35 Directive unbundling rules apply)

SP module procedures (Art. 27): Registration, application, update, suspension, de-registration, grid prequalification, switching, revocation, confirmation — 9 defined procedures.

CU module procedures (Art. 28): Registration, update, suspension, de-registration, grid prequalification, switching, revocation, termination, re-activation — 9 defined procedures.

Title IV — Market-Based Procurement of Local Services

Art. 29 — Biennial assessment obligation

At least every two years, each SO shall:

1. Assess the need for DR/storage/other resources as alternatives to system expansion
2. Publicly consult on this assessment
3. Use it to fulfil DNDP obligations (Directive Art. 32(3) and 51(3))
4. Take into account the national FNA report under Regulation Art. 19e

This is the formal NC DR anchor for the three-way FNA–DNDP–NC DR linkage that the FNA Webinar 7 describes.

Market-based procurement is the default (Art. 29 §2). Derogation requires NRA approval under Art. 30.

Art. 30 — Derogation from market-based procurement

The NRA may grant a derogation (at SO request or own initiative) allowing non-market procurement under Regulation Art. 13(3) and Directive Arts. 32(1), 31(7) and 40(5). The derogation:

• Must consider: latest DNDPs (incl. local service needs), DSO observability areas, national assessment on flexible CAs
• Must specify: which parts of the system, voltage levels, time periods, and products it covers
• Must consider DSO size
• Duration: max 2 years, except for voltage control with reactive power (may be longer)
• Must be published on NRA website
• NRA may revoke if circumstances change
• NRA notifies relevant SOs, ACER, and the Commission

Art. 31 — Rules for flexible connection agreements

Three binding requirements for Villkorade Avtal equivalents:

§1 — Counted as firm connections in needs assessment: When assessing local service needs (Art. 29 §1), SOs shall treat flexible CAs as firm connections. Exception: permanent solutions under Directive Art. 6a(1)(c). This directly flows into the FNA methodology — the full underlying grid constraint must be reported.

§2 — Activation must coordinate with markets: When a local services market exists, activation of flexible CAs shall be subject to coordination via a mechanism specified in the market rules (Art. 32). Additionally:

• If activated after day-ahead gate closure: the TSO shall calculate an imbalance adjustment to affected balance responsible parties
• Activation must not impact trade position consistency (Art. 51)

§3 — Market participation rights preserved: System operators shall not limit system users with flexible CAs from:

• Providing balancing and local services in relevant markets (except for grid prequalification limits under Art. 49 and temporary limits under Art. 50)
• Participating in other electricity markets

This is a significant right: holding a flexible CA does not disqualify a resource from bidding into SWITCH or other local markets.

Art. 32 — Rules for market-based procurement

All procuring SOs shall define market rules as part of the T&C proposal under Art. 11. Rules shall be:

• Objective, transparent, non-discriminatory, technology-neutral
• Designed to avoid market fragmentation and market abuse

Required content (Art. 32 §3):

• Roles and responsibilities (Art. 33)
• Market coordination (Art. 34): interaction with day-ahead, intraday, and balancing markets
• Procurement, pricing, and settlement rules (Art. 35)
• Coordination mechanism for flexible CAs and market products (Art. 31 §2(a))
• Transparency/publication requirements (Art. 37)

3-year mandate (Art. 32 §6): Within 3 years of entry into force, ENTSO-E and EU DSO Entity shall develop a Union-wide methodology to further harmonize procurement rules, market coordination, settlement, and product attributes.

Art. 33 — Procuring SO requirements

• Non-discriminatory procurement and activation
• No sharing of preferential/confidential/commercially sensitive information with affiliated companies
• Common information platform for all procuring SOs in a Member State
• Standardized geographical/topological information
• Business separation from market activities (unbundling)
• Costs of local services kept separate from balancing (Art. 33 §9)

Art. 34 — Market coordination (local + day-ahead/intraday/balancing)

• The same bid may be submitted to multiple markets but not selected twice for the same time unit
• When a bid is not selected, it can be re-submitted to another market
• A CU can be registered in different SPGs for different services, provided no double activation of the same volume for the same imbalance settlement period
• Forwarding of bids between markets is allowed with SP consent and transparency requirements

Art. 35 — Pricing and settlement

Pricing shall:

• Ensure cost-efficient activation
• Take into account market structure and concentration
• Provide incentives for long-term market development

Allowed pricing variations: capacity payments, energy-only payments, or combinations. Settlement must include: activated volume calculation using the relevant baseline, claims and recalculation process, validation of delivery.

Art. 37 — Transparency and publication

• Market session information published no later than [2 months] before launch
• Indicative but non-binding need forecasts published at least as frequently as network development plans
• Market results published no later than 1 day after service procured: aggregated and anonymised volumes, selected bids, costs, flexible CA activations
• Annual reporting: volumes, locations of activated services, temporary limits applied
• All information accessible from a single national access point

Note: SWITCH already publishes data at info.switchmarket.se — broadly aligned with this requirement.

Art. 38 — Product attributes

14 mandatory attributes for active power products: (a) availability window; (b) preparation period; (c) ramping period; (d) full activation time; (e) validity period; (f) mode of activation; (g) location; (h) minimum and maximum quantity; (i) deactivation period; (j) minimum and maximum duration; (k) recovery time; (l) direction of activation; (m) divisibility; (n) relevant data exchange standards.

8 additional attributes for reactive power / voltage control products.

Art. 39 — Product definition requirements

SOs shall standardize local products and avoid product fragmentation. When defining new products, consider: DNDPs, current and future system needs (capacity/energy, short/long-term), and FSP capabilities.

Title V — Energy Storage Ownership

Arts. 40–42 elaborate the derogation process for SO-owned storage beyond Directive Arts. 36 and 54:

• Open, technology-neutral tendering required before derogation
• Shared ownership allowed (derogation process same as full ownership)
• Regular public consultation on phasing out SO-owned storage (every assessment period)
• If market interest exists → cost-benefit analysis → NRA decides within 6 months → phase-out within 18 months if decided

Title VI — Distribution Network Development Plans

Art. 43 — DNDP content: Required to include at minimum:

• Planning framework (efficient + cost-effective measures; consideration of local services)
• Scenario(s) reflecting 5–10 year futures, coordinated with transmission development plans
• Investment plans for distribution assets including metering and control systems
• Local services information per Art. 44

6-week minimum public consultation; NRA may request amendments; final DNDP published on DSO website and central platform.

Art. 44 — Local services in DNDP: Where local services are deemed relevant and cost-effective (based on Art. 29 assessment), the DNDP shall include:

• Forecasted needs for local services in the DSO’s system
• Description of cost-effectiveness assessment methodology
• Medium and long-term local service estimates with locational and time granularity

This formalizes the requirement to quantify and publish local flexibility needs — essential market signal for FSPs and aggregators.

Title VII — TSO-DSO Coordination

Art. 45 — National T&C: All SOs shall develop national TSO-DSO/DSO-DSO coordination T&C within [6 months] of rules of procedure approval.

Art. 46 — DSO observability area: Each DSO defines its observability area (own system + relevant parts of adjacent systems). Established within [6 months] of T&C approval; reviewed with each DNDP update. Annual reporting to NRA.

Art. 47 — Congestion forecasting: DSOs responsible for forecasting congestion and voltage issues across multiple timeframes consistent with day-ahead, intraday, and balancing market cycles. Granularity: 1 hour or less for D-1 through real-time.

Art. 49 — Grid prequalification: Three possible statuses:

• “grid prequalification approved” — activation respects operational security limits
• “grid prequalification conditionally approved” — only under specified conditions (time and/or quantity limits)
• “grid prequalification not approved” — in other cases (rare; full justification required)

If a SO does not communicate its result before the product prequalification completes, grid prequalification status is automatically approved. Annual reporting to NRA on non-approved and conditionally approved cases.

Art. 50 — Temporary limits: Short-term procedure (distinct from grid prequalification). Temporary limits communicated at latest 1 hour before balancing energy gate closure. SOs shall minimise the market impact of temporary limits.

Art. 51 — Trade position consistency: If local service activation takes place after day-ahead gate closure and before intraday cross-zonal gate closure, the activating SO must ensure trade position consistency — either immediate opposite-direction activation or netting before TSO bid submission.

Art. 52 — DSO-TSO data exchange: Structural, schedule/forecast, and real-time data exchange. Requirements reviewed every 2 years. Small CU aggregations exempt from CU-level near real-time data requirements (Art. 54 §8).

Title VIII — Data Exchange from Service Providers

Art. 53: SP responsible for providing high-quality data. Data requirements are limited to what is necessary and usable. Requirements reviewed every 2 years.

Art. 54: Three categories of SP data:

• Structural data (for prequalification/verification)
• Schedule and forecast data (day-ahead, updated after each market session)
• Near real-time data (operation status, active/reactive power, storage SoC, etc.)

Exemption for small CUs (Art. 54 §8): SPs with SPUs or SPGs consisting only of small CUs are not required to provide near real-time data at CU level.

Title X — Transitional Provisions

Art. 57:

• Existing IT solutions (e.g., SWITCH, NODES) may continue until the national FIS is implemented
• Existing FIS must be updated or replaced within 2 years of FIS T&C approval
• All FIS operators must have fully functional services within 3 years of FIS T&C approval

Key timeline summary

Relevance to wiki

Directly updates: Network Code on Demand Response, Villkorade Avtal, Aggregation, Flexibility Market, Flexibility Need Assessment, Energy Storage, Congestion Management, SWITCH, NODES

Key new information vs prior wiki sources:

• Art. 31 §3: system users with flexible CAs retain full market participation rights (not in prior wiki)
• Art. 31 §2: specific imbalance adjustment mechanism for post-DA flexible CA activations (new detail)
• Art. 30: 2-year derogation maximum formalized; voltage control exception; DSO size consideration
• Art. 32 §6: 3-year ENTSO-E/EU DSO harmonization mandate (new)
• Art. 37: 1-day post-market publication requirement; single national access point (new)
• Art. 38: 14 mandatory product attributes for active power (new)
• Art. 44: Local services assessment is required DNDP content (new — not optional)
• Art. 57: 2-year transition for existing FIS systems (important for SWITCH/NODES)
• Art. 54 §8: Small CUs (<50 kW) exempt from CU-level near real-time data (important for household participation)