EU DSO Entity & ENTSO-E Consultation on the Draft Network Code on Demand Response

A Eurelectric public consultation response

November 2023

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Eurelectric represents the interests of the electricity industry in Europe. Our work covers all major issues affecting our sector. Our members represent the electricity industry in over 30 European countries.

We cover the entire industry from electricity generation and markets to distribution networks and customer issues. We also have affiliates active on several other continents and business associates from a wide variety of sectors with a direct interest in the electricity industry.

We stand for

The vision of the European power sector is to enable and sustain: A vibrant competitive European economy, reliably powered by clean, carbon-neutral energy A smart, energy efficient and truly sustainable society for all citizens of Europe

We are committed to lead a cost-effective energy transition by:

investing in clean power generation and transition-enabling solutions, to reduce emissions and actively pursue efforts to become carbon-neutral well before mid-century, taking into account different starting points and commercial availability of key transition technologies;

transforming the energy system to make it more responsive, resilient and efficient. This includes increased use of renewable energy, digitalisation, demand side response and reinforcement of grids so they can function as platforms and enablers for customers, cities and communities;

accelerating the energy transition in other economic sectors by offering competitive electricity as a transformation tool for transport, heating and industry;

embedding sustainability in all parts of our value chain and take measures to support the transformation of existing assets towards a zero carbon society;

innovating to discover the cutting-edge business models and develop the breakthrough technologies that are indispensable to allow our industry to lead this transition.

Dépôt légal:

D/2023/12.105/45

Key Messages

A specific regulatory approach is needed to adapt to reflect the new reality in which the role of DSOs is increasing significantly. The Network Code on Demand Response is key to fill an existing gap in regulation and simultaneously it needs to be framed to complement (and not overlap or infringe) existing legislation. Demand response is a relatively untapped area that has been emerging, in part as a result of the rapid development of distributed energy resources and two-way energy flows. This part of the power sector is only partially covered by the current EU legislative framework and this framework will need to change in the coming years. Regulatory certainty and simplicity are key for market participants. We recommend a legislative analysis of the existing network codes and guidelines (in particular the Demand Connection Code, CACM, the Electricity Balancing Guidelines, and the System Operator Guidelines) and the development of a clearer definition of what is in scope for this Code and what is under the scope of other pieces of legislation. There should also be a better understanding of the foundational elements to be tackled in this Code which are not already covered elsewhere. This Network Code should be more focused on the local market and flexibility services in its specific provisions, while identifying needed revisions topics under the scope of other existing network codes.

This Code must not exclude any resource provider as the main aim of the new rules shall be to ensure access to all electricity markets for all resource providers (FG paragraph 4). The current draft Code must include load, storage, and distributed generation (aggregated or not), however, generation in particular is missing from the definitions and key articles throughout the Code.

Proper compensation must be ensured by setting in place appropriate frameworks. When it comes to the aggregation models, we would stress that the priority order for defining the exhaustive list of models should start with the balance responsibility, then with the compensations for different incurred costs, and then finally the metering architecture needed to measure the activations. The current draft does not make this clear and may force a rearrangement of existing markets across Europe. And when it comes to dispatch, freedom of dispatch must remain a key principle – any service provided to a system operated must be compensated.

Market-based procurement must be privileged by principle. We recognise that there are situations where a system operator may need to rely on non-market-based procurement to maintain system stability or where the market fails to deliver appropriate flexibility services, however, we would stress that in the Code it should be explicitly stated that market-based procurement should be the default form of procurement of flexibility services where it is fit for purpose. In the case where non-market-based procurement may need to apply, the procuring system operator should provide a justification to the NRA.

National Regulatory Authorities should have the final say when it comes to validating methodologies or areas where system operators may have a conflict of interest. For example, system operators should not be validating their own proposals on baselining methodologies nor a proposal to co-own or outright own storage facilities where a market analysis should be conducted. We think this decision-making power should be in view of the wider goal of EU-level harmonisation, while recognising the different maturities of the different markets of different Member States

Response ID ANON-JBU7-6GQK-H
Submitted to DSO Entity & ENTSO-E Public consultation on Network Code for Demand Response
Submitted on 2023-11-10 22:24:43

Introduction

1 What is your name? Name: Savannah Altvater

2 What is your email address? Email: saltvater@eurelectric.org

3 What is your organisation? Organisation: Eurelectric

4 Terms of Use

I agree to ENTSO-E's Consultation Hub Terms of Use: Yes

5 Privacy Policy

I agree to ENTSO-E's Consultation Hub Privacy Policy: Yes

6 If you tick this box, we will not publish your answer to this consultation. However, your answer, without your name and organization, may

be shared with EU and national authorities, drafting committee members, and other persons or entities involved in the adoption process of

the consulted document to ensure the performance of ENTSO-E legally mandated tasks.

I want my answer to be confidential and not to be published: No

Reason for the request of confidentiality:

Whereas

7 Your views on the "Whereas" section:

Your comment on the section:

General Comments:

We would like to underline that following terms which are introduced in the ACER Framework Guideline on Demand Response from 20 December 2022 are not adequately taken into consideration in the proposed Network Code (not even included in Article 2):

(j) ‘local market for SO services’ or ‘local market’ means a market where service providers offer products for local SO services.

(k) ‘local service provider’ means a service provider of product(s) for supplying local SO services.

(l) ‘local SO services’ means market-based procurement of congestion management or voltage control.

The NC DR is intended to eliminate barriers to consumer participation in the market, regulate a new scope and optimize the activities, mainly of DSOs, under the conditions of DER development and bidirectional energy flow. A new scope relates to “local areas” where the DSO’s network operates, requiring specific regulations providing a basis for the development of DERs and the use of their capabilities, and generally activation of all customers (DSR).

Furthermore, please note that the balancing market is already regulated and the NC DR should only contain a description of its connections with the local market. The local market, and thus the provisions of the Code, should emphasize the role of the DSO as the entity responsible for networks in the local area, the importance of direct contact between the DSO and the connected entities, and increase the DSO's capabilities to use synergies resulting from both the development of DERs and cooperation with the aggregator. The needs for flexibility services in the whole National Power System and locally in the DSO network are different.

Taking into consideration all our remarks we propose to modify (and include in the Code) definition of local SO services as ”services for solving congestion issues and voltage issues at all voltage level within a DSO observability area, as defined in Article 2(9)”.

Article 2(9) must be technically amendment to clarify the reference to grid users in the definition. Grid users are not part of the observability area. Observability is guaranteed in the connection point of the ‘significant grid users’ (not necessarily all grid users and never in the same manner/with the same requirements). This should be reworded in coherence with SO GL (and relevant amendments of the SO GL, if necessary). We should add this comment as a complement to those already included on article 2(9).

For the whereas section:

- (a) suggest to add after trade in electricity, "while paying special attention to interactions with other regulations, in order to ensure coherence of the overall European framework."

- (b) The way the proposal is framed, leaves out distributed generation, and it is also restrictive on demand as it only foresees demand curtailment (which refers to demand response in only one direction).

The Framework Guidelines foresee a similar text but is also state that: “the new rules shall be technology neutral and non-discriminatory and shall thus not favour demand response and storage to the detriment of other resource providers. (…) The new rules shall thus be applicable to load, storage (in particular when combined with load), and distributed generation, aggregated or not (hereafter referred to as “demand response and other relevant resources” or in general “resources”). No resource provider shall be excluded and the main aim of the new rules shall be to ensure access to all electricity markets for all resource providers.”

-(c) We suggest to delete this paragraph as it is unnecessary.

-(d) To ensure the regulation's definition of a minimum bid size does not supersede other legislation should the granularity change, we recommend including "currently" ahead of the referenced definition of the minimum bid size.

This text refers to the “evolution of the bid granularity” in balancing products, to facilitate the participation of smaller resources. However, in only foresees such evolution for aggregated participation, thus excluding direct participation of those smaller resources.

-(e) We suggest merging this paragraph with point (i) of the same Title. We would also appreciate clarity on the objective of the term “systems operators” used everywhere in the draft instead of “system operators”. It is not a recognized term in the regulatory framework, so it must be avoided for legal certainty. Furthermore, we believe that very few individual SPUs or SPGs would have a significant impact on system security and grid operation in case of non-delivery. The administrative burden associated with the requirements for the prequalification process should consider the impact in case of non-delivery from multiple SPUs or SPGs prequalified under the same process that may together have an impact on system security.

-(f) We notice that mobile technical resources are referred here, but not elsewhere in the Code.
We feel this should be corrected.

-(i), (j), (k) We suggest merging these paragraphs and considering moving these points to the System Operator Guidelines.

-(o) The proposed wording seems to suggest that, besides the existing ToE which would ensure the same type of requirements for equivalent products, different system operators could still require different things. The example provided is that the TSO could ask for activation tests for aFRR while a DSO requires different steps for congestion management.

If products are considered as equivalent in the ToE, this possibility to ask for different requirements seems to contradict the purpose behind the definition of the ToE in itself, and even the definition of ‘product prequalification’ in article 2 (32), which foresee technical and data exchange requirements.

In that regard we propose to delete whereas (o).

Otherwise, the text would need to be clarified in a way this won’t imply an additional layer of differentiated requirements on top of a framework that was meant to avoid duplication and simplify the access to the market and existing products, and therefore allowing for value staking as correctly foreseen in whereas (n).

-(q) Suggest eliminating whereas (q), which is not clear in the purpose, and refers to situations that are not exclusive from small controllable units such as the “location in critical grid areas”.

-(r) The acronym oCUO is used without an explanation of what it stands for. We would appreciate clarity on this.

- (t) We propose the drafter be more precise in stating that the NCDR will focus primarily on local DR.

We also suggest striking the "including congestion management" following voltage control services due to redundancy.

- (u) The proposed wording seems to imply that article 13 of Regulation (EU) 2019/943, might not always apply, according to the national choices of implementation.

In our view Member States shall apply the options they consider nationally suited, as long as they comply with European legislation, which means to always apply article 13 of Regulation (EU) 2019/943, regarding rules for redispatch, namely on financial compensation rights.

Making the reference to article 13 of this Regulation may be adequate to frame the rules on redispatch, but it shall refrain from making consideration on whether article 13 is applicable or not and affected or not.

- (w) Price limits in wholesale electricity markets are, by definition, not allowed in Regulation (EU) 2019/943, Article 10. Additionally, whereas (w) has inconsistencies which contradict whereas (x).

For instance, whereas (w) refers to market-based procurement but it states that remuneration may (which implies it also may not) be determined by a market-based mechanism which is inconsistent to a procurement that is supposed to be market-based, and it extends into what is supposed to be covered in whereas (x).

- (y) Demand connection rules also derive from Network Codes for grid connection such as the Demand Connection Code, which doesn’t necessarily require transposition into national law to be applicable.

- (z) We propose to eliminate whereas (z) as system operators always have different options to choose and decide from, for grid management and this is not adequate to introduce under which conditions there could be connection limits and how these would be handled. This is out of scope for this Network Code, which shall not define rules regarding limits to grid connection.

- (aa) There seems to be a missing modal verb between "they assess" in the third line. We propose adding shall here.

- (cc) It is not clear whether this recital is in the scope of this Network Code as it focuses on network tariffs. We suggest eliminating this point.

- (ff) The proposed text only covers energy (not capacity), doesn't cover overall ancillary services (e.g. inertia), and is unclear on what may be considered "long-term". There is a definition for electricity markets in the Directive that should be used.

- (ll) In alignment to what is foreseen in SO GL, we suggest to change procurement might be under ruled or market-based mechanisms" to: "procurement by system operators should make use of market-based mechanisms as far as possible"

- (mm) Is this distinction between LV and HV actually valid, or just a question of current practices? If this is not a fundamental distinction, it’s not obvious that it should be included in the recitals.

Your text proposal:

(a) This Regulation helps to ensure fair conditions of competition in the internal electricity market, to ensure system security and the integration of renewable electricity sources, and to facilitate Union-wide trade in electricity, while paying special attention to interactions with other regulations, in order to ensure overall coherence of the European framework as a whole.

(b) Whilst having due regard to the particularities of demand response, this Regulation respects the principles of non-discrimination and technology neutrality, applying to load, storage (in particular when combined with load), and distributed generation, aggregated or not (hereafter referred to as “demand response and other relevant resources” or in general “resources”) , and considering the potential needs resulting thereof for adapting current and future rules.

(d) The minimum bid size of standard balancing products is currently defined as 1.0 MW for: standard products for balancing capacity for frequency restoration reserves and replacement reserves in accordance with Article 25(2) of Regulation (EU) 2017/2195, and for standard products for balancing energy for (automatic and manual) frequency restoration reserves and replacement reserves in accordance with Articles 19(1) and 19(3)(i), Articles 20(1) and 20(3(i), and Articles 21(1) and 20(3)(i) of Regulation (EU) 2017/2195. This Regulation requires an evolution of the bid granularity of standard balancing products intended to facilitate the participation of smaller resources in balancing services either directly or by means of aggregation.

Merging of (e), (i), (j), and (k) to a single point - When developing the procedures for product prequalification processes, they should be as simple as possible, user-friendly, technologically neutral, non-discriminatory, fair, objective, transparent and striving to minimise and standardise the different steps when possible. System operators should ensure that the administrative burden associated with the requirements for the prequalification processes is proportionate with the size of SPU or SPG and its impact on the system security and grid operation in case of non-delivery. The product prequalification requirements should be limited to the technically necessary level to ensure system security and safe grid operation and should not create unreasonable entry barriers for SPUs and SPGs consisting of only small controllable units. System operators should avoid any unnecessary duplications of prequalification processes. Specific approaches should be considered to lower the integration barriers for mass-produced standardised devices across Europe through the establishing of dedicated standardised market interfaces for both pan-European and national balancing, congestion management or voltage control products. When setting procedures for product prequalification processes, system operators should consult market participants and consider the real-world experiences to update the requirements and processes in the future.

(t) This Network Code aims at enabling an efficient use of mainly local demand response in power systems by facilitating the creation of markets for congestion management and voltage control services which should be interoperable with existing markets.

(u) Congestion management is to some extent ruled by Article 13 of Regulation (EU) 2019/943, regarding redispatch, namely on the circumstances for which non-market-based may apply, and the rules on financial compensation, whether redispatch is market-based or not, by the system operator requesting the redispatching to the operator of the redispatched resource.

(w) Market-based procurement is understood as a mechanism whereby a service is procured by soliciting market participants to place an offer for the service. The remuneration shall be determined by a market-based pricing mechanism.

(y) Member States, through national applicable law and in line with the applicable Network Codes for grid connection, prescribe how distribution and transmission system operators should connect customers or group of customers. This includes connection conditions applicable to the access to network capacity, as conditions for guaranteed capacity or firm connection.

(aa) If transmission and distribution system operators are nationally enabled to connect more customers than supported by their grid capacity or their contractual agreements with overlaying system operators, they shall assess the effective and efficient solution at their hands in line with the national applicable rules, as for example non-firm connection agreements or the procurement of congestion management and voltage control services.

(ff) Market participants can trade in all electricity markets including over-the-counter markets and electricity exchanges, markets for the trading of energy, capacity, balancing and ancillary services in all timeframes, including forward, day-ahead and intraday markets, as defined in the Directive (EU) 2019/944. This Regulation states principles applicable for the use of bids and for the coordination for those wholesale and balancing markets and for the local markets for congestion management and voltage control.

(ll) Procurement of voltage control by system operators, including reactive power capacities, should make use of market-based mechanisms as far as possible, as foreseen in Directive 2019/944

Article 1

8 Your views on Article 1:

Your comment on the article:

- Paragraph 1 leaves out distributed generation, and it is also restrictive on demand as it only foresees demand curtailment (which refers to demand response in only one direction).

The Framework Guidelines foresee a similar text but is also state that: “the new rules shall be technology neutral and non-discriminatory and shall thus not favour demand response and storage to the detriment of other resource providers. (…) The new rules shall thus be applicable to load, storage (in particular when combined with load), and distributed generation, aggregated or not (hereafter referred to as “demand response and other relevant resources” or in general “resources”). No resource provider shall be excluded, and the main aim of the new rules shall be to ensure access to all electricity markets for all resource providers.”

- Paragraph 2 has some points which could benefit from further clarification. The phrase "obligations for ensuring that the systems operators have access to energy resources of all the electricity markets" is very broad and very vague. Obligations for whom? What does 'access to energy resources' mean? This paragraph should rather clarify that this regulation aims to govern the procurement by system operators of the necessary services for operation and planning. Furthermore, we suggest to add "and trade for congestion management purposes" after "all of the electricity markets" because it is not explicitly included in the Directive and it is out of the definition of ancillary services.

- Paragraph 3 seems to imply that some system operators do not have to comply with this NC, as it states Member States may determine which system operators need to comply if some system operators may not properly fulfil one or more obligations. In a more extreme situation one might infer that the procurement of demand response for those connected to the grids of other system operators (that are not the ones assigned with the responsibility to comply) could not be possible at all.

In that regard we propose to delete paragraph 3.

Your text proposal:

This Regulation establishes a network code which lays down the requirements in relation to demand response and other relevant resources as defined in article 2, including rules on aggregation to contribute to market integration, non-discrimination, effective competition and the efficient functioning of the market pursuant to Article 59(1) of Regulation (EU) 2019/943.
This Regulation also lays down the obligations for ensuring that the systems operators have access to energy resources of all the electricity markets and trade for congestion management purposes in accordance with the principles regarding the operation of electricity markets pursuant to Article 3 of Regulation (EU) 2019/943, and allow the use of energy resources by the systems operators for the operation and planning of the Union electricity network.

Article 2

9 Your views on Article 2:

Your comment on the article:

General comments:

Some definitions can take the form of amendments of the corresponding ones of SO GL or be introduced directly in the SO GL always with the DSO perspective for the sake of completeness. Lack of accuracy of certain definitions impact on legal certainty.

Missing definitions:

- A definition of "dedicated measurement device" is missing from this article. We recommend: (# tbd) 'dedicated measurement device' means a device as defined in Article 2 (79) of (EU) 2019/943 (with updated reference to EMD revision)

- There are several references to the scope of this Network Code that leave out distributed generation and it might be perceived as restrictive on demand as it only foresees demand curtailment (which refers to demand response in only one direction).

The Framework Guidelines state that: “the new rules shall be technology neutral and nondiscriminatory and shall thus not favour demand response and storage to the detriment of other resource providers. (…) The new rules shall thus be applicable to load, storage (in particular when combined with load), and distributed generation, aggregated or not (hereafter referred to as “demand response and other relevant resources” or in general “resources”). No resource provider shall be excluded and the main aim of the new rules shall be to ensure access to all electricity markets for all resource providers.”

The same expression of “demand response and other relevant resources” is then also included in other parts of the Framework Guidelines.

In that regard we propose to add a definition of “other relevant resources” in line with the stated intention in the Framework Guidelines for this network code, and as a reference to other proposals in other articles/whereas:

(# tbd) ‘Other relevant resources’ means storage (in particular when combined with load), and distributed generation, aggregated or not.

- As foreseen in the proposal for the definition of the ‘metering point’, some physical metering points refer to multiple demand “sides” as is the case for electric vehicles that charge in different charging points. A charging point can than be of private access (as in the customer’s home) or of public or semi-public access, which mean that the metered data is disaggregated amongst different consumers and suppliers. The same way, the total demand for such electric vehicle is than provided by the sum of metered data in different physical metering points (charging points) and is thus a virtual metering point.

As a complement to definition (1) in article 2 (‘metering point’) a definition of ‘virtual metering point’ must also be added to clarify what is meant as “calculated” in the definition of ‘metering point’.

In that regard we propose the following definition of “virtual metering point”:

(#tbd) ‘Virtual metering point’ means the sum of metered data, which can include metered data from different physical metering points, either withdrawal or injection, referring to mobile loads from electric vehicles, that connect to multiple ‘connection points’, namely of public or semi-public access.

- In the current definition of ‘Locational information’ the accounting point is referred but it is not defined anywhere.

We therefore suggest including a definition for ‘accounting point’ which we consider to be referring to situations where the accounting point might be in a physical location that doesn’t match with the connection point to the public grid.

-The current definition of ‘SP qualifying responsible’ (article 2, 34) refers to the entity responsible by SP prequalification, the same way the definition of ‘Product qualifying responsible’ (article 2, 35) refers to the entity responsible for product prequalification.

However, unlike ‘Product prequalification’ which is also defined (article 2, 33), ‘SP prequalification’ is not defined.

We therefore suggest including a definition for ‘SP prequalification’.

- The current definition of ‘Activation test' (article 2, 42) foresees an activation signal as a test to ensure the service provider can deliver under normal operating conditions. However, there is no definition of what ‘normal operating conditions’ are.

We therefore suggest including a definition for ‘normal operating conditions’ which shall refer both to the status of the grid but also of the technical asset itself. For instance, the SP must be able to communicate maintenance situations that should be excluded of such normal operating conditions to avoid triggering such activation tests in maintenance periods.

Specific comments:

- (1) We suggest adding a reference to a virtual metering point. To clarify the addition of situations where this is to be calculated. This must be complemented with a new definition for the virtual metering point, referring to mobile demand (electric vehicles) whose consumption is metered in several places and where a connection point serves multiple consumers (charging points with public or semi-public access), each with their chosen supplier (or suppliers, as even the same consumer may have more than one charging card from different entities).

- (2) This definition should state that it is not the way of lowering the requirements that are mandatory for other participants to provide the same service. This definition is also missing minimum interoperability and requirements.

- (3) To better align with the FGs definition by covering all flexibility services, and adding that this is a forecast, which means an expected withdrawn or injection, we propose the below reword.

- (6) This point has a reference to Implementing Regulation about access to metering data. This role of MDA has been considered from the scope of that Implementing Regulation and should not be referred here. The data interoperability requirements will be set in the upcoming Implementing Regulation for flexibility data. We propose deleting definition or redefining it.

- (7) We suggest rewording this definition to reflect the existing definition in the Network Code on Capacity Allocation and Congestion Management.

- (7) & (8) These definitions should be introduced in SO GL aligned with the definitions related to contingency there. The term “issue” is not accurate.

Moreover, definitions of congestions are present in CACM and it is planned to translate congestion management in SO GL.

- (8) We suggest to include "or is likely to be outside of" after "above and below" and before "operational limits"

-(9) It is unclear why the definition of 'DSO observability area" was included here instead of using "SO coordination group" and "SO coordination areas" as listed in the FG.

-(11) A controllable unit may be a particular asset of set of assets behind the main-meter and the connection point.

- (12) & (13) We suggest to expand these definitions to encompass wider designations of frequency and non-frequency services

- (14) We suggest a clearer definition below.

- (16) For clarification purposes, we suggest to either review this definition as proposed or to replace it by a ‘Flexible connection agreement’ definition from the EMD review (Art. 2 (79b) Regulation 2019/943).

- (17) You could have the same actors in multiple member states — in fact, with harmonisation, you’d expect to. Hence, we do not see the reason to specify "national" actors

- (21) We are concerned that as written, it could lead to a variety of different thresholds in different Member States. We would recommend the drafters set EU-wide thresholds for these small controllable units.

- (22) To specify in the definition that the set of CUs can be defined by the customer itself.

- (23) We suggest including Type D generation in this definition. Exclusion of type D power generation modules in the definition of technical resource is discriminatory and lead to legal uncertainty. Generation, demand and storage at distribution level currently participate in congestion, voltage control and balancing markets. The definition of technical resource also comprises “any other consumption device”. This term is complemented with the definition 2(39) of “standardized device”, but generation and storage at any voltage level can fit perfectly with this definition (they are also mass-produced in scalable technologies e.g. batteries and even combined cycle generation turbines.

- (24) We suggest deleting "local or balancing" from this definition as it may be misleading. We suggest instead to align this definition with the definition of “reserve provider” of the SO GL and Balancing Service Provider of the EB GL, because the reserve provider (or BSP) is a sub-type of service provider. This is also the case for service providing unit (28) and “group”. All of these definitions should be mad0e homogeneous and compatible through proper amendments of SO GL and EB GL, while avoiding duplicity, overlapping, and contradicting definitions.

- (26) We suggest deleting this definition and refer instead to "preparation time" and "full activation time" as defined in EB GL (Regulation (EU) 2017/2195).

- (28) We find there is no need for a definition for a service providing unit since controllable unit is used throughout the code.

- (29), (32), (33), (34) We suggest to change the different reference to congestion management, voltage control, balancing, and local services to "flexibility services" - Again, this seems restrictive. it's a general comment for the overall draft.

- (32) Product pre-qualification, as an ex-ante process, is not necessarily a condition prior to participation, as for local and non-standard balancing services it is foreseen that an ex-post verification may apply and the ex-ante prequalification always applicable. Therefore it’s not accurate to define this as an element prior to the participation as some products might only apply an ex-post verification.

Also, sometimes this is referred as congestion + balancing + voltage, other times as balancing + local . The concept should be harmonised in the text and be wider to cover all forms of participation of flexibility in the markets (including DA, ID, all non-frequency ancillary services."

- (34) and (35) It is not clear what differentiates these definitions, we would suggest they be merged.

- (37) We suggest deleting the i.e. clause in this definition.

Dispatch limitation must be a product itself and can be procured prior or after closure of the dayahead market. Otherwise, the use of temporary limitations as defined in the draft NC can drain the interest of creating robust and valuable congestion products. Accordingly, definition 2(37) must be amended and the draft NC must change the approach of this matter.

- (38) It is unclear why this definition limits activation to only after the closure of the Day Ahead market.

- (40) Even if for some products it might be premature to already define an European common view of comparable qualification attributes, this should not be excluded. Additionally, for some products it doesn’t make sense to already consider it just at national level, namely for standard balancing products, based on pan-European platforms with European implementation frameworks. Therefore, the definition in itself should not restrict this to just a national view and national terms and conditions, but to open the scope so that it can consider both national and European.

- (42), (43), and (44) must be included in SO GL (Regulation (EU) 2017/1485), particularly considering they are developed under Chapter 2 regarding operational testing.

- (42) "normal operating conditions" is undefined in the text. We recommend including a definition which clarifies that it refers to both normal conditions of the grid (no need for service to be provided) and the technical asset itself (the SP may be able to communicate maintenance situations that should be excluded of such normal operating conditions).

- (47) For clarification purposes, namely that this is a recovery from an activation and regarding the concepts used (e.g. activation instead of provision, injection/withdrawal instead of generation/consumption as this also applies to storage).

- (48) For concept clarification (injection/withdrawal instead of generation/consumption as this also applies to storage) and to clarify what these changes are in non-activated technical resources, assuming those refer to assets behind the connection point that may counteract the activation effects on specific

activate assets. If this compensation effect from non-activated resources refers to a different thing than it should be properly clarified considering this refers to assets that are not to be somehow activated.

- (49) The proposed definition seems to imply that once the product verification is concluded the SPU or SPG is no longer qualified, which would be an obstacle to DR. In products where ex-ante prequalification is not required, this should be a default state that should only stops applying if product verification is systematically not concluded with success.

- (50) and (51) We suggest deleting these definitions. CU Operator definition overlaps with technical aggregator’s and service provider’s and poses concerns because the term “operator” can be confusing. This can be perfectly substituted by “CU owner or delegated third party in charge of controlling the CU” in Article 33(6) and Table 2.1 of Annex 2. Furthermore, the delegation by the consumer is done to an aggregator (which may or may not be an independent aggregator) which is already defined in legislation, and can provide a service as a service provider, based on an aggregated portfolio of different CUs. Any relation between the SP and an IT supplier or other on which the aggregator supports their actions should not be regulated under the scope of this NC and risks create confusion in the concepts and in the defined roles and responsibilities.

Your text proposal:

(# tbd) 'dedicated measurement device' means a device as defined in Article 2 (79) of (EU) 2019/943 (with updated reference to EMD revision)

(# tbd) ‘Other relevant resources’ means storage (in particular when combined with load), and distributed generation, aggregated or not.

(1) ‘Metering point’ means a physical location where the withdrawal or injection of electrical quantities is measured or calculated, in the case of a virtual metering point.

(2) 'Submeter' means a metering device (embedded in a particular asset or an autonomous meter) placed behind the meter at the connection point with the transmission or distribution system operator as defined in the connection agreement.

(3) ‘Baseline’ means a counterfactual reference about the electrical quantities that were expected to have been withdrawn or injected in the absence of the activation for the provision of the respective service.

(6) 'Metering data administrator‘ or ‘MDA‘ can mean a different party depending on the national market structure and environment.

(7) ‘Congestion issue’ means a situation where the physical or structural congestion, as defined by the Regulation (EU) 2015/1222 are likely to occur.

(8) ‘Voltage issue’ means a situation when voltage is above or below or is likely to be outside of operational limits.

(11) ‘Connecting system operator’ means in this Network Code the DSO or TSO responsible for the grid to which a grid user or controllable unit is connected, directly or indirectly.

(12) ‘Requesting system operator’ means the DSO or TSO requesting data for detecting, forecasting and/or solving an issue (congestion, or overall ancillary services [frequency or non-frequency related],) on its own grid to initiate actions to solve those issues.

(13) ‘Procuring system operator’ means the DSO or TSO procuring congestion management or overall ancillary services (frequency or non-frequency related).

(14)‘Affected system operator’ means any DSO or TSO significantly affected by congestion or voltage issues, or whose data on its grid and the connected grid user are necessary to forecast, detect or solve such issues.

(16) ‘Flexible Non-firm connection agreement means a connection agreement where the grid user has agreed to not being granted with access to firm capacity for parts or the entirety of the grid connection.

(17) 'Flexibility Register' means an information system consisting of one or multiple and diverse platforms operated by one or multiple actors to support the registration and prequalification for the provision of balancing, congestion management and voltage control services and other relevant flexibility services, using a common front-door at least at Member State level.

(21)‘Small controllable unit’ means a controllable unit connected below 1000 V with an installed capacity lower than a predefined threshold set at national level, but not higher than 1MW.

(22) ‘Controllable unit’ or ‘CU’, means a single technical resource or an ensemble of technical resources behind the same single connection point, to be decided by the customer (or asset owner), if these technical resources can be commonly controlled.

(23) ‘Technical resource’ means an individual power generating module of type A, B, or C or D as defined according to Regulation (EU) 2016/631 connected to the distribution system, individual energy storage unit, demand units according to Commission Regulation (EU) 2016/1388 or any other consumption device.

(24) ‘Service provider’ or ‘SP’, means a market participant with a legal or contractual obligation to supply services from at least one SPU or SPG.

(29) ‘Service providing group’ or ‘SPG’, means an aggregation of controllable units connected to more than one connection point. SPG is defined by the service provider to provide flexibility services.

(32) ‘Product prequalification’ means the ex-ante process, where applicable, prior to participation of a potential SPU or SPG in balancing or congestion management or voltage control market, to verify the compliance of a potential SPU or SPG with the technical and data exchange requirements for the provision of a flexibility product. In the product prequalification the PPR may require the potential SPU or SPG to pass an activation test.

(33) ‘Product verification’ means the process after the delivery of specific flexibility services to verify the compliance of an SPU or SPG with the technical and data exchange requirements for the provision of such services.

(34) 'SP qualifying responsible party’ means a party responsible for qualifying a service provider for the delivery of a flexibility control product procured by systems operators. There shall only be one SP qualifying responsible per service provider and each product.

(37) ‘Dispatch limitation’ means a congestion management product whereby a service provider offers to limit the use of the firm connection capacity of a service providing unit or group prior to the determination of its dispatch

(40) ‘Table of equivalences’ or ‘ToEq’, means a mechanism defined in the national or European terms and conditions for service providers to simplify the participation of SPUs and SPGs in multiple markets. It provides a single national or European point of reference to store a common list of ‘comparable qualification attributes’ and defines how to make necessary data available to systems operators and market platform operators in the process of registering new SPUs or SPGs for the provision of particular products.

(47) ‘Rebound effect’ means the alteration of injection or withdrawal of electricity of an activated technical resource before or after the time frame of its delivery, as a recovery effect resulting from to the activation of a local or balancing service product.

(48) ‘Compensation effect’ means the alteration of injection or withdrawal of electricity of other non- activated technical resources in the time frame of a delivery of a local or balancing product, behind the same connection point, that compensate for the effects that the activation implies.

(49) ‘Temporary qualification’ means the default status granted to a SPU or SPG for provision of specific balancing or congestion management or voltage control services to allow their participation on the market, when an ex-ante prequalification is not required and this is based on an ex-post product verification process.

Article 3

10 Your views on Article 3:

Your comment on the article:

(1) We suggest to use the language from the Framework Guidelines for legal clarity when talking about regulatory authorities.

Your text proposal:

(1) The requirements set out in this Regulation shall apply to transmission system operators (‘TSOs’), distribution system operators (‘DSOs’) including closed distribution system operators, regulatory authorities (Whenever regulatory authorities is referred as the approval authority, it should be understood as any competent authority or authorities appointed with this task at the Member State-level), the Agency for the Cooperation of Energy Regulators (‘the Agency’), the European Network of Transmission System Operators for Electricity (‘ENTSO-E’), the European Distribution System Operators Entity (‘EU DSO Entity’),third parties to whom responsibilities have been delegated or assigned and other market participants, including customers and resource providers for demand response including load, storage and distributed generation whether aggregated or not.

Article 4

11 Your views on Article 4:

Your comment on the article:

- (1) Paragraph 1, (a) and paragraph 2 leaves out distributed generation, and it is also restrictive on demand as it only foresees demand curtailment (which refers to demand response in only one direction).

- (5) Suggest to add a provision which explicitly references the need for not distorting price formation or restricting the freedom of dispatch.

Your text proposal:

This Regulation aims at:

(a) setting out clear and objective principles for the development of rules regarding demand response and other relevant resources as defined in article 2, including rules on aggregation.

(b) Respecting the principles of non-discrimination and technology neutrality, whilst having due regard to the particularities of demand response, including rules on aggregation, energy storage and demand curtailment, and the potential needs resulting thereof for adapting current and future rules.

(g) refrain from distorting free price formation and respect the freedom of dispatch.

Article 5

12 Your views on Article 5:

Your comment on the article:

- (1) Paragraph 1 foresees a deadline of three months, after the publication of the legislation, for all the DSO and TSO within a Member State to present a process proposal for the development of national terms and conditions. Given that some states have many TSO and DSO, which takes some time to coordinate, a larger deadline is advisable.

For TSO and DSO to have the necessary time to coordinate a six-month period would increase the probability of a successful national debate and to the establishment of consensual process for the national terms and conditions.

Your text proposal:

By six months following the entry into force of this Regulation, all systems operators shall jointly submit to the competent national regulatory authority a proposal for a national process to develop national terms and conditions referred to in Article 6 (Common national terms and conditions). This is without prejudice to the right of the Member State or NRAs to define the national process on how systems operators jointly develop national terms and conditions pursuant to this Regulation.

Article 6

13 Your views on Article 6:

Your comment on the article:

- In Article 6, no description of the points that constitute the “National Terms and Conditions” is provided. However, in article 7 (“Approval of common national terms and conditions”) there is such description in paragraph 2.

For clarity, there should be a list of points that constitute the “National Terms and Conditions” in article 6. Therefore, we propose placing the description provided in Article 7 (2) in a new paragraph 3 of Article 6.

Your text proposal:

National Terms and Conditions constitute:

(a) the terms and conditions for service providers in accordance with Article 38 (Principles for national implementation);

(b) the terms and conditions for the market design for congestion management and voltage control services in accordance with Article 48(4) (National terms and conditions for17 market design for congestion management and voltage control services through active power); and

(c) the terms and conditions for TSO-DSO and DSO-DSO coordination in accordance with Article 69 (National implementation and condition for coordination)

Article 7

14 Your views on Article 7:

Your comment on the article:

- (1) and (2) Article 7 should consider the consultation of system operators but also market participants, and it should also consider, for transparency purposes the yearly publication of the status of implementation and content of national terms and conditions.

Your text proposal:

The competent national regulatory authority shall be responsible for approving the common national terms and conditions referred to in paragraph 2. Before approving the common national terms and conditions, the competent national regulatory authority shall revise the proposals where necessary, including proposed amendments, after consulting all systems operators and market participants, in order to ensure that they are in line with the purpose of this Regulation.
The proposals for the following common national terms and conditions and any amendments thereof shall be subject to approval by the competent national regulatory authority in each of the Member States.

Article 8

15 Your views on Article 8:

Your comment on the article:

- (2) Solutions regarding local areas should be prepared by the DSO and consulted with the TSO.

Your text proposal:

All system operators responsible for developing a joint proposal for common national terms and conditions may propose amendments to the competent national regulatory authority. For solutions specific to local areas, DSOs should prepare such associated amendments and these amendments should be consulted with the relevant TSO.

Article 9

16 Your views on Article 9:

Your comment on the article:

- (1) There is a mismatch between the referred article 9 number 1 (article 77) which the text refers to as concerning monitoring and the actual article referring to this topic, which is article 83 of this proposal.

- (2) Also, while paragraph 1 foresees that ENTSO-E and the EU DSO Entity shall develop T&Cs or methodologies for topics identified for harmonization, paragraph 2 only foresees TSOs (not ENTSO-E) may (instead of shall) develop a Union-wide proposal for the harmonisation of processes for prequalification of standard balancing products.

Considering that standard balancing products are already mature and pan-European platforms for energy balancing products are already in place (or expected) for different Member States to join, this should be more binding and clear.

- (3) Some stakeholder engagement must be mandated. Article 11 on amendments refers to Article 14 for consultation, but this article does not.

Your text proposal:

ENTSO-E and EU DSO Entity shall develop the Union-wide terms and conditions or methodologies, in case the relevant monitoring report produced pursuant to Article 83 (Monitoring Reports – Title X) identifies the need for harmonisation. ENTSO-E and EU DSO Entity shall submit them for approval to the Agency.
Without prejudice to paragraph 1, ENTSO-E shall develop a Union-wide proposal for the harmonisation of processes for prequalification of standard balancing products pursuant to Article 29, by no longer than 6 months after entry into force of this Regulation.

terms and conditions or methodologies pursuant to this Regulation shall closely cooperate. ENTSO-E and EU DSO Entity shall regularly inform the Agency about the progress of developing the Unionwide terms and conditions or methodologies pursuant to this Regulation. These proposals shall be submitted to consultation in accordance with the procedure set out in Article 14 (Public consultation for Union-wide terms and conditions or methodologies) and approved in accordance with Article 10 (Approval of Union-wide terms and conditions or methodologies).

Article 10

17 Your views on Article 10:

Your comment on the article:

Your text proposal:

Article 11

18 Your views on Article 11:

Your comment on the article:

- (1) Paragraph 1 foresees a period of 6 months, after ACER request for amendments, for ENTSO-E and the EU DSO Entity propose an amended version of the terms and conditions, which seems excessive.

- (2) We find that the vast majority of potential flexibility products in local areas are under the purview of DSOs and think this should be more well-reflected in text regarding the development of proposals.

Your text proposal:

In the event that the Agency requests an amendment to approve the Union-wide terms and conditions or methodologies submitted in accordance with Article 10(2) (Approval of Union-wide terms and conditions or methodologies), ENTSO-E and EU SO Entity shall submit a proposal for amended terms and conditions or methodologies for approval within 3 months following the request from the Agency. The Agency shall decide on the amended terms and conditions or methodologies within 2 months following their submission.

Article 13

20 Your views on Article 13:

Your comment on the article:

- (3) We very much welcome the following clause:

"In all cases, a justification for including or not the views resulting from the consultation shall be provided together with the submission of the proposal and published in a timely manner before, or simultaneously with the publication of the proposal for terms and conditions."

- (4) We propose a new paragraph 4 to provide a process for what happens if a regulatory authority requests an amendment to the proposed national terms and conditions.

Your text proposal:

The proposals for the common national terms and conditions or their amendments in accordance with this Regulation shall be published and submitted to consultation at least at Member State level, by no longer than 6 months after entry into force of this Regulation.
All system operators, responsible for developing the joint proposal for the common national terms and conditions shall duly consider the views of stakeholders resulting from the consultations prior to its submission for regulatory approval, by no longer than 3 months after the end of the consultation period foreseen in paragraph 1 of this article. In all cases, a justification for including or not the views resulting from the consultation shall be provided together with the submission of the proposal and published in a timely manner before, or simultaneously with the publication of the proposal for terms and conditions.
In the event the NRA request for an amendment to, according to the previous paragraph, approve the common national terms and conditions, national DSOs and TSOs shall submit a proposal for amended terms and conditions, for regulatory approval, within 3 months following the request from the NRA. The NRA shall decide on the amended terms and conditions within 2 months following their submission, after which those shall be published.

Article 15

22 Your views on Article 15:

Your comment on the article:

Clarity should be provided in the Code on what should be covered by this stakeholder involvement and why.

Your text proposal:

Article 16

23 Your views on Article 16:

Your comment on the article:

- (4) In Article 16 (4), it is stated that the Member State or the NRA may assign tasks or obligations entrusted to systems operators under this Regulation to one or more assigned parties. Given the particularities of each Member State and regulatory framework it is important to state that this redistribution must be carried out under the terms defined by national legislation.

Your text proposal:

Without prejudice to the tasks entrusted to systems operators pursuant to Directive (EU) 2019/944, a Member State, or where applicable a relevant regulatory authority, may assign tasks or obligations entrusted to systems operators under this Regulation to one or more assigned parties, including a TSO or a DSO, under the terms defined by national legislation. Prior to the assignment, the party concerned shall demonstrate to the Member State, or where applicable the relevant regulatory authority, its ability to meet the task to be assigned.

Article 18

25 Your views on Article 18:

Your comment on the article:

- (2) We suggest clarifying the confidentiality obligations apply to both natural and legal persons.

Your text proposal:

The obligation of professional secrecy shall apply to any natural or legal person(s) subject to the provisions of this Regulation.

Article 19

26 Your views on Article 19:

Your comment on the article:

We propose a rewording of this article which prioritises a focus on the imbalance settlement and compensation flows.

Your text proposal:

Proposed reword:

Aggregation models

The aggregation models that are described below aim at defining how the participation of service providers are allowed by limiting the impact on other parties, based on different ways to do imbalance settlement and on contractual relationships, while ensuring each market participant is responsible for the imbalances it cause.
Member States shall allow the aggregation models defined in the articles 13.4 and 13.5 for each flexibility services in the scope of this regulation, either one or the other or the combination of both.
Every aggregation model presumes the following base assumptions:

a. Aggregators (including independent) do not require consent from other market parties to participate in electricity markets;

b. Aggregators (including independent) are financially responsible for the imbalances they cause (which they may delegate under contractual agreement),

apart from possible derogations foreseen in article 5 of the Regulation (EU) 2019/943;

c. Compensations to suppliers may apply, regarding costs proven to be incurred as a result of demand response activation;

d. Compensations may also take into account the benefits brought by the independent aggregators, which means the compensation may only apply where and to the extent that costs exceed the benefits. This calculation method is subject to approval of the regulatory authority or another competent authority.

Besides the situation where the aggregator and the supplier are the same market participant, which can be considered as an integrated model, there

can be four base models:

a. Model A – Corrected model

b. Model B – Central settlement model

c. Model C – Contractual model

d. Model D – Information before day-ahead

Model A – Corrected model – assumes the following:

a. The allocated volume is corrected from the activation request, thus it neutralise the imbalance volumes;

b. Additional costs may apply referring to rebound effects or hedging costs;

Model B – Central settlement model – assumes the following:

a. There is no correction of the load curve of the consumer, but a financial correction of the imbalances in which the system operator charges the aggregator and pays the supplier an equivalent compensation to neutralize the imbalance effect caused by the activation, under a methodology to be approved by the NRA;

b. This compensation should be calculated based on the harmonized imbalance settlement methodology approved by ACER, and the decision adopted by the Member State in using single or dual price.

c. Additional costs may apply referring to rebound effects or hedging costs;

Model C – Contractual model – assumes the following:

a. There is no correction of volumes;

b. Any financial correction of the imbalances or compensation, which can also include additional costs, is established contractually between the two parties;

c. Costs included in the compensation may refer to imbalance costs, rebound effects or hedging costs.

Model D – information before day-ahead – assumes the following:

a. This model is only applicable for products whose activation is timely requested before gate closure time of day-ahead;

b. The supplier's BRP is informed from activation requests in a timely manner ahead of day-ahead, and thus can review the final position;

c. This information can be provided directly by the aggregator, by the SO requiring for activation, or by a central entity;

d. Additional costs may apply referring to rebound effects or hedging costs;

Relevant changes in the volumes may be considered for additional compensation (other the referring to imbalance settlement) when associated to fixed prices with hedged volumes, and where price variations result in a loss incurred by the supplier.
Changes in profile may refer to a rebound effect, where there is the load is merely shifted to a different time period, thus causing an imbalance that is indirectly caused by an activation request for another time period. Such effect may be considered for additional compensation.
The methodology to calculate the compensation shall be approved by the NRA and include:

a. Thresholds for relevant variations in the volumes;

b. Reference prices against price variations are determined

c. Maximum time window where rebound effects are to be considered and reference baseline methodologies associated to load variations (injection or

withdraw) from activation in specific technical units

All these different models can exist or co-exist in each Member State or as a combined version.
In any aggregation model:

a. The supplier shall receive the metered data without any adjustment from any activation request, so that it can bill the consumer.

b. The supplier shall be informed of activation requests so that it can incorporate such information in its forecasting tools, to provide accurate final positions and thus be able to strive to be balanced or help the electricity system to be balanced.

c. Each market participant shall be able to delegate their balance responsibility under contractual terms agreed by both parties. NRAs may define and approve minimum requirements for those contracts and, notwithstanding the parties may agree differently, the NRA may also define and approve standard templates to be used on a voluntary basis.

d. In case of contractual delegation of responsibilities, BRPs shall receive all the data necessary to be able to determine and validate each position associated to the respective settlement.

e. The rebound effect shall be included as one of the variables to be considered in the baselining methodologies, namely for thermal appliances or electric vehicles or charging stations where a variation for the baseline is likely to simply trigger a shift to a different time period.

f. The compensation mechanism for the transfer of energy or rebound effect shall be based on clear market price references, set by a methodology approved and published by the NRA.

Each of these models will also depend on whether additional measurement equipment is used, away from the connection point. The following variants can be considered:

15. Variant 1 prescribes all the following requirements:

a. no additional metering equipment for the technical resources is used to measure the provision of balancing, congestion management and voltage control services; and

b. the only metering equipment used for settling flexibility activations is the smart meter at the connection point, which is the only meter to perform measurements of the energy injected or withdrawn used by both the supplier(s) and by the service provider(s);

Variant 2 prescribes all the following requirements:

a. there is additional metering equipment, being either a submeter or a dedicated measurement device (DMD, as considered in the EMDR), associated with the technical resources which are involved in providing the balancing, congestion management and voltage control services. The metering equipment of the technical resource measures the withdrawals and/or the injections of the technical resources involved in the provision of such services; and

b. the metering equipment at the connection point can be a conventional meter or smart meter;

For simplification purposes, a simple version is assumed but the possibility of multiple suppliers and service providers behind the connection point providing balance or congestion management and voltage control services from different technical resources is possible. When multiple suppliers are active at the connection point, the allocation of imbalance between different BRPs of multiple suppliers is performed following national rules. The configurations and the responsibilities shall remain as they are in the simple version.
The interactions and data exchange remain the same in case of several service providers as it is in the simple version. Direct interaction and data exchange between the service providers are not envisaged.

Article 20

27 Your views on Article 20:

Your comment on the article:

- (1) If this applies for partial loads, this model seems incomplete and does not provide a clear view on the balance responsibilities of each party, not to mention it doesn't work for more than 2 agents (between "main supplier" and other). For purposes of verification, validation, settlement, accurate billing and proper incentives for balancing there should always be any type of metering for the partial loads, or at the very least some methodologies to calculate partial loads and split responsibilities.

- (2)(a) The baseline for a CU also includes as an additional variable: the rebound effect expected to occur associated to any change from a requested activation.

- (2)(c) We suggest to delete this point. In case of compensation effect, it could be difficult to assign the imbalances to the relevant parties.

- (3) It could be clarified in the text how to distinguish the volume for adjustment and the volume to supply the customer. The financial flows could be different and it is important to distinguish adjustment and "normal supply." It is also worth noting this still requires data of both parties for the purposes of validation of settlement.

- (4) The delegation itself of balancing responsibilities should not be a part of the network code nor this differentiation between being the supplier's BRP or another one. It only makes sense to refer to the delegation to define the data that the BRP is entitled to receive (for validation purposes) and the financial flows, when such roles are delegated, but it shouldn't matter if it's the BRP of the supplier or not. Even the supplier (or any other market participant) can delegate this into another market participant.

- (6) In the current proposal , it is impossible to distinguish "energy exceeding the requested amount" to a wrong forecast of BRP. Also, the “requested amount” will be on an SPG level, whereas any grid limitations are at the connection point, so these are quite different issues.

Your text proposal:

Article 21

28 Your views on Article 21:

Your comment on the article:

- (9) Where the supplier optimizes the customers’ portfolio intraday (in the case of large industrial customers), this data transfer from the service provider to the supplier (or its BRP) has to occur in real-time. This is necessary to prevent that the BRP counteracts the activated demand response in intraday markets due to the changed offtake.

The SP and their BRP needs continuous data so that they can, for example, check the baseline calculations.

"With exception of the specific data related to the activation" is an improvement on the previous wording, which seemed to suggest leaving gaps in the supplier’s data.

- (10) Suggest to change "supplier" to "grid user."

A BRP is linked to a grid user, not necessarily to a supplier.

Your text proposal:

The BRP associated to the grid user shall be responsible for bearing the imbalance caused by the assets in its portfolio, as defined in article 28 (Imbalance settlement).

Article 22

29 Your views on Article 22:

Your comment on the article:

- (1) In order to avoid any misunderstanding, it is needed to precise that the compensation can not be applied when the load curve paid by the customer is corrected. Indeed, on the one hand, it is possible to correct the load curve for the BRP in order to calculate the imbalances but in other hand only what is recorded on the meter is billed to consumers. The bill and the correction are two different things.

- (3) We suggest to strike this point, we find it to be an unnecessary rule.

- (4) Suggest to rephrase this paragraph to "The method for calculating the financial compensation shall always result of freely negotiated agreements between the involved parties." Any other "solution" means a form of regulation of the market and is in conflict with the Market Regulation / principle of free formation of prices.

- (5)(a) Clarity should be provided on what costs this covers (imbalance, hedging, rebound?) The section referring to negative prices being reallocated to service providers should be removed. It's not clear what's meant by "negative prices" or how they would be determined.

- (5)(b) This paragraph doesn't include flexibility from injection (generation or storage)? Or is it perceived as increased demand? Clarity is needed here.

- (6) The last sentence should be struck, since SOs may need to apply penalties as mentioned in previous paragraphs, which lessens their neutrality.

Your text proposal:

In order to neutralize the impact that balancing or congestion management and voltage control services activation might generate on market parties, a financial compensation may apply, only when the measurements that determine the load curve paid by the customer is not corrected.
The method for calculating the financial compensation shall always result of freely negotiated agreements between the involved parties.
If national rules foresee a financial compensation, the following provisions shall apply: (a) when service provider provides a demand reduction, a compensation to the supplier should apply being the party that indeed previously purchased that energy, according to national rules, for supplying to its clients;

(b) when service provider offers an increased demand, a compensation from the supplier to the service provider should apply, the supplier being the beneficiary of billing more energy to the customer, according to national rules.

Depending on the service, the systems operators may play the role of financial intermediary for invoicing the service provider or the supplier for the energy cleared and transferring the sums collected to concerned parties.

Article 23

30 Your views on Article 23:

Your comment on the article:

- (1) We strongly disagree with the application of compensations of the net benefits of the activation of DR being borne by suppliers. These net benefits apply to the system and all of its users and should be allocated as such, in a way to be determined at the Member State-level.

- (2)(a) We suggest rewording this point to "Compensation due to energy supply costs, including both energy and, where applicable, capacity costs, when consumption is reduced"

- (3)(a) and (b) We suggest striking these examples.

According to the FG, a description is sufficient. Any precising of the benefits should be done at Member State-level to reflect national market specificities. It is not clear what the implication is of defining the benefits of these actions. If it is to integrate them into the compensation to suppliers, this would create distortions as only impacted suppliers would pay for these benefits.

Your text proposal:

Costs for the supplier resulting directly from the activation of services by the Service Provider shall include the following:

(a) Compensation due to energy supply costs, including both energy and, where applicable, capacity costs, when consumption is reduced;

Article 24

31 Your views on Article 24:

Your comment on the article:

- (2)(a) We do not support the principle “buy your baseline” despite paragraph (31) pf the ACER FG is open to include it (“the baselining approach for validating the activation is not mandatory and SO can implement alternatives, such as taking the final position of the SP’s BRP as the baseline, to be used as reference of the delivery of service”). This leads to never ending discussion about gaming (see article 25(4)(c) and 26(2)) or even fraud instead of focusing on rigorous baseline methodologies, which shall be approved only by the NRA (amend accordingly article 26(6): SOs cannot approve their own methodologies).

Regarding the point "In some cases, baseline may be determined ex-post of service delivery," we think that a subsection here would be appropriate to put in place clear rules to avoid "manipulation" when the metered data is already known.

- (3) "The relevant systems operators or local market operator shall notify the service provider(s) whose bids have been selected" means activation in later articles. We would suggest precising the language used when talking about notifying when bids are selected and when those bids are activated.

Your text proposal:

Article 25

32 Your views on Article 25:

Your comment on the article:

General Comments:

As a general principle, imbalances should be attributed to the agents who caused them and they should not remain with the supplier.

This means that a supplier, unless he has access to information that can be timely incorporated into his own forecasting models, shall not be held responsible for imbalances that he could not foresee as they result from the action of a third-party (an independent aggregator). One basic principle is the Directive is that each market participant shall be financially responsible for the imbalances he causes, which implies some correction to neutralise DR activation by a third-party from the supplier’s imbalance.

When referring to financial compensation it is also relevant to distinguish between imbalance costs and other costs, such as hedging and rebound effect, that may exist even by correcting or compensating for imbalances caused by demand response activation.

This means that, it is not true that a financial compensation should apply, only when the measurements that determine the load curve of the customer is not corrected (as proposed in article 21). A correction only acts on imbalance costs, while there may still be other costs entitled for a financial compensation (e.g. hedging and rebound effect).

As for delegation of imbalance responsibility, this shall not be necessarily perceived as a delegation in the supplier’s BRP. An independent aggregator can delegate such responsibility in any entity under a contractual agreement and the NC should not have such a great focus on the delegation into the supplier’s BRP. After all, the delegation of imbalance responsibility is of relevance for the system operator so that he can know who to bill and exchange data, disregarding of being the supplier’s BRP or any other entity.

Regarding the existence or not of metering, we question the models where there is DR for partial loads but no measurement behind.

If this applies for partial loads, without metering, there is no visibility on the balance responsibilities of each party, not to mention it doesn't work for more than 2 agents (between "main supplier" and other). For purposes of verification, validation, settlement, accurate billing and proper incentives for balancing there should always be any type of metering for the partial loads, or at the very least some methodologies to calculate partial loads and split responsibilities.

Also, by measuring only the controllable units at the connection point in isolation to the rest of the assets, this can only work for simpler flexibility services like load shifting, interruptibility, load reduction, etc, but not for most of ancillary services including aFRR or mFRR.

Finally, regarding baselines, these should also include as an additional variable the rebound effect expected to occur associated to any change from a requested activation.

These articles shall all be reviewed following the proposal presented above for article 19, with a complete shift of the starting point to define aggregation models.

Specific Comments:

- (3), (4), and (5) Baselining shall also consider the rebound effect, which means the recovery effect associated to a change in the profile due to an activation for flexibility services in one time unit and how that translates into a symmetric (or close to it) change in another time unit.

For instance, if a consumer (or service provider) reduces demand in an EV charger, in a certain hour, because the system is procuring that flexibility service (either for a frequency service, or congestion management, or something else), that EV will instead charge that same load it would need before, but in a different hour. This shift in demand that results from activation is what we refer here as the rebound effect.

Of course, this rebound effect is not necessarily symmetric (meaning a shift in the exact same level of the activation) for all forms of loads. For example: it might not even happen in lightning, in H&C might not be in the full level of activation as there is also some thermal inertia but it should occur in some extent, it should be symmetric (or close to it) in EV charging, it is very likely to be symmetric (or close to it) in some industrial processes, … so it very much depend on the type of load/use.

Not all markets are at the same starting point and the use of distributed flexibility is still in early stages in most markets, where this may be negligible for now. But with increasing use of distributed resources this tends to be very different.

The rebound effects should be approached in 2 perspectives:

For the system operators’ decision to activate: by activating a certain load (reducing demand) the baseline for other hours will not be the same as if no activation occurs, and this might even cause other issues to the grid in hours where no congestion (for instance) was foreseen before, because now the load reduction in a previous hour will translate in a load increase in another hour. This effect should also be taken into account by SOs when deciding activations (meaning the price to reduce the load vs. the potential new cost in other hours where a flex service might be needed due to this previous activation) and even something that can be part of the product definition (including when/how to “rebound” while minimizing the effect to the grid).
For the supplier’s forecasting and cost/pricing: the action of third-parties like an independent aggregator, to activate load changes, result in an imbalance for the hour (or other period) of activation but also in other periods where this rebound effect occurs. Therefore, the effect of the activation doesn’t end in the period for which the activation takes place but also in other periods where other baselines occur as a result from this previous activation.

This effect should be captured in baseline methodologies.

This means that, besides the baseline as the load forecast if no activation had occurs, when considering an activation, a new forecasted curve should be assessed to capture the rebound effect in other hours (where there is no direct activation per se but the forecast needs to be corrected to reflect the change from an activation in a certain previous moment).

It’s like a “second-run” in the forecast ahead incorporating the possible activation needed in previous moments.

- (4)(c) We suggest rewording this paragraph. No approach to baselining makes gaming impossible. What the robust methodologies do is make it expensive and easily detectable. It’s using robust methodologies combined with some policing by the NRA that prevents gaming.

- (4)(f) Clarity should be provided about which sources may be used from "existing available data"

- (5) We advocate for a more ambitious approach regarding harmonization of baselining methodologies. Governance of this article 25(5) must be reinforced and led by ACER. Regarding the final sentence, the data used for determining the activation of a service must be always based on measurement, although different methodologies can be devised based on these data.

Your text proposal:

The national TCs referred to in paragraph 1 shall include at least the following:

(a) the roles and responsibilities of the stakeholders involved in the process of balancing, congestion management and voltage control services regarding the development and implementation of baselines;

(b) the approval process of an individual baselining method by the NRA, or by the systems operators if the or NRAs so decides, which will also consider the costs and benefits of the implementation of the specific baselining method;

(d) the methodology to reassess the baseline considering the ‘rebound effect’ from a possible activation;

(e) the process of re-evaluating proposing and approving new methods for baselining, and to set cross-border mutual recognition;

(f) the minimum set of data necessary to deliver and validate the respective balancing, congestion management and voltage control services;

(g) an obligation to share necessary data with all relevant stakeholders for executing processes of the respective balancing, congestion management and voltage control services;

(h) a procedure to support new and innovative approaches to the methods; and

(i) the obligation for the relevant entity for publishing a list of accepted baseline methods and their applicability.

The baselining methods shall be based on the following principles: (...)

(d) the methods may consider the impact of a delivery of a balancing, congestion management and voltage control service, outside the time of activation but within contracted times, such as the rebound effect;

By 2 years, and after that on a yearly basis, after the entering into force of this Regulation, ENTSO-E and the EU DSO entity shall make a common assessment which considers costs and benefits of whether further standardisation of the baselining methods brings benefits in achieving the aims of the Electricity Regulation. In this process ENTSO-E and the EU DSO entity shall consult the stakeholder and consider their feedback. Final report will be published by not more than six months after starting the assessment. Based on this report further steps shall be taken into account on national level if needed.

Article 26

33 Your views on Article 26:

Your comment on the article:

- (1) The reference to the imbalance settlement period doesn’t seem to make sense in the context it is proposed in this article. One may have 15' metering data while that Member State has, for instance, a 1h ISP. Or, for instance a service with a 4 second MTU (requiring higher resolution) should not be using data with the ISP which is in some Member States it is still 1h and all converging to 15' in 2025. Measurement and ISP don't have to be (and usually aren't) aligned.

- (2) Also, in paragraph 2, we suggest to be more objective in the terminology and avoid references such as “deception”.

- (6) The way this provision is written and how it is understood by different parties is quite divergent. As written, it applies to the validation of the baseline methodology per service, which is an approval process which should be conducted by the NRA. However, if the intent is that this is to be related to the application of the baseline methodology, that should be laid out in a separate article on applying the methodology per service.

Your text proposal:

If the data used for determining the activation of a service is based on measurement, the granularity of the data used shall be at least the metering period. Services with shorter control cycles may require a meter able to provide a higher resolution for determining the activation of a service.
The system operators have the right to require all data needed to secure a proper activation of services and to set requirements designed for verification and monitoring, and assessment of accuracy.

Article 27

34 Your views on Article 27:

Your comment on the article:

- (2)(a) and (4)(a) This article refers, in several paragraphs, the ISP as minimum granularity. The reference to the imbalance settlement period doesn’t seem to make sense in the context it is proposed in this article.

One may have 15' metering data while that Member State has, for instance, a 1h ISP, which would be less granular than the need for a service. It also has no relation to the product features. Measurement and ISP don't necessarily have to be aligned, neither do the MTU for a specific service and ISP.

-(4) Clarity could be provided on who decides whether the measured values from the MDA are aggregated or not.

- (7) and (8) Additionally, paragraphs 7 and 8, refers to the right for system operators to receive individual metering data and baselines, from each controllable unit, which refers to each resource. If the SPU includes several devices behind one metering point, that should not require one meter per technical resource. A submeter for all those technical resources should be accepted as enough. Even if there are meters per device, the SO should only need the metered data of that partial load, and be able to verify that against the main meter at the physical connection point, but not necessarily by device.

The same rationale applies to baselines. The system operator should only require the baseline for each SPU or SPG, necessary to validate the activation of the service.

We suggest deleting these paragraphs. However, if paragraphs 7 and 8 are to be kept with further clarification, the above comments regarding ISP also apply.

- (9) Paragraph 9 refers to the need for the system operator to receive information regarding grid limitation for the correct settlement.

This is very unclear and should either be eliminated or reworded for more clarity on the reach of such paragraph:

On one hand, grid limitation is an information the system operator owns, so it’s not clear from whom should it receive this information from. If this refers to the activating system operator to request info from connecting system operators (where resources are connected) that should be further specified.

Also, there doesn’t seem to be a relation between grid limitation and settlement. In the settlement phase any activation should already had occurred, thus grid limitation should not have any influence here. Again, this needs to be further clarified or deleted.

- (12) Balancing should also apply to this paragraph.

Your text proposal:

(...)

(a) each market time unit as defined in the product characteristics;

(...)

(a) each market time unit as defined in the product characteristics;

Each service provider shall ensure that the delivery of the flexibility services is registered at the connection point(s)

Article 28

35 Your views on Article 28:

Your comment on the article:

General Comments:

It's not clear whether this article is compliant with Article 49 of EB GL (Regulation (EU) 2017/2195) - "1.Each TSO shall calculate an imbalance adjustment to be applied to the concerned balance responsible parties for each activated balancing energy bid"

Specific Comments:

- (4) "For services where the position of the concerned BRPs is not corrected ex ante in the wholesale market " could be further clarified.

- (4)(b) The provision is particularly muddy and could be broken down into several parts to improve clarity.

"requested value of the service" could be more precise. Does this refer to the volumes or the price?

Your text proposal:

Article 29

36 Your views on Article 29:

Your comment on the article:

General Comments:

Provisions regarding bid granularity should take the form of amendments to the EB GL (Regulation (EU) 2017/2195), not a new article

Specific Comments:

- (2), (3), and (4) Paragraphs 2, 3 and 4 should refer to the provisions and timeline foreseen in paragraph 1 (instead of referring to paragraph 2), which we assume is just a typo.

Still in paragraph 3 and also in paragraph 4, there is a reference to a cost-benefit analysis of the reduction of the bid granularity, and further reassessment.

It is not clear though under which methodology tis CBA should occur and how such methodology should be set. Considering this may be the argument for some Member-States applying this bid reduction and other don't, the methodology for this CBA should be harmonised.

In paragraph 4 it is also defined a maximum period for initial derogation but, after reassessment it only foresees that the TSO may request further derogation, with no time limitation clearly defined.

- (3) Clarification on whether the conditions are cumulative or alternative is needed.

- (3) (a) and (b) For the CBA, we recognise the need for a European-level harmonisation and application.

Review of balancing bids granularity in article 29 lacks development of principles to perform the CBA of paragraph 3(a). Paragraph 3(b) should be included in that, not dealt separately

It is unclear how one would assess a negative impact on the implementation of the EB GL here.

- (4) Lacks correct development: approval of derogations, maximum time of derogations, etc.

Your text proposal:

The implementation deadline of the requirement set in paragraph 1 shall be at least 2 years after the entry into force of this Regulation.
A national regulatory authority may, at the request of a TSO or at its own initiative, grant the relevant TSOs a derogation from the provision set out in paragraph 1 for all or some standard balancing products if the implementation is judged inefficient based on next condition:
Where the relevant national regulatory authority grants a derogation, it shall specify its duration. The derogation may be granted for a period maximum of two years, after which the TSO(s) of the concerned MS(s) shall reassess the implementation of the provision set out in paragraph 1. (…) • Clarify the CBA methodology (foreseen in both paragraphs 3 and 4), namely how this should be defines, and the same for the reassessments to be
made, under which a derogation could be granted.

• Review paragraph 4, regarding the derogation time limit, as follow:

(…) As a result of that reassessment, TSO(s) may ask to extend the derogation period, for a period no longer than 2 years.

Article 30

37 Your views on Article 30:

Your comment on the article:

General Comments:

We suggest not using undefined acronyms like ICT and TCMs for legal clarity.

Specific Comments:

- (1) In Article 30 (1), it is stated that the service provider shall successfully pass qualification requirements before being granted access to markets. In order to increase market liquidity, it should be stated that it this would only be applied if required by the market operator.

- (5)(e) The rebound effect is something to plan for, it is not something which can be managed. We suggest rewording this point.

Your text proposal:

The service provider, when requested by the market operator, shall successfully pass a service provider qualification with the requirements laid down in paragraphs 2, 3, 4 and 5 before being granted access to markets for balancing, congestion management or voltage control services. In case the service provider is already qualified for one or more markets for balancing, congestion management or voltage control services and applies for the participation in another market for balancing, congestion management or voltage control services, a simplified qualification process shall be foreseen further specified in the national TCMs for service providers.

5. (...)

(e) the expected rebound effect.

Article 31

38 Your views on Article 31:

Your comment on the article:

- (3) We do not agree with the simplification of the prequalification for specific balancing products in general, although article 31(4) provides exceptions. These specific products compete with standard ones and hence must follow the same rules to the maximum extent for the sake of harmonization across EU.

- (4) (a) It is not clear if these are cumulative or alternative conditions. We would recommend they be alternative Furthermore, a definition of "continuity of supply" is missing.

- (5) This article sets the conditions under which system operators can request a prequalification, for either specific balancing products or local products, such as voltage control and congestion management.

However, some of the terms would benefit from a more precise and objective definition.

For instance, it refers to specific balancing products when “the expected contribution for guaranteeing the system balance is particularly relevant”. The same applies for local services in situations where “the expected frequency of activation is particularly relevant” or “the expected contribution to resolve a congestion or voltage constraint is particularly relevant”.

It is very subjective to define what “relevant” means in such situations and, therefore, a clarification is needed, as the default rule should be to request for an ex-post verification and only in very particular circumstances to require an ex-post pre-qualification.

If these conditions aren’t clearly defined, these may result in having pre-qualification as the standard if the expected impact is always considered relevant, without any definition of such circumstance.

To avoid a misuse of such conditions it is advisable that the NRA would need to approve the circumstances under which an ex-post verification would not suffice for such products, thus requiring for an ex-ante prequalification.

Your text proposal:

(...)

(a) for specific balancing products, where an SPU or an SPG does exceed a prequalified power
threshold specified in the national terms and conditions of
service providers, or where either:

i. the expected contribution for guaranteeing the system balance is particularly relevant;

ii. an inadequate activation could compromise the continuity of supply that shall not be covered with other balancing products.

The right to require a product prequalification on SPU or SPG level, in addition to the possible product verification, as foreseen in paragraph 4, is

subject to the approval of the national regulatory authority.

Article 32

39 Your views on Article 32:

Your comment on the article:

- (1) We assume that the intended default threshold, set in paragraph 1, is the 10% and the 3MW are intended to prevent the reassessment each time the 10% are reached, but with negligible volume variations.

- (4) We suggest deleting this paragraph. Paragraph 4 seems to be redundant and even inconsistent with paragraph 5. In fact, paragraph 4, without further framework seems to imply that paragraph 1 only applies to small CUs and standardized devices, while paragraph 5 also covers how to address those units, with simplified criteria.

- (6) This provision should be transferred to the following article and clarified that it refers to the entrant SP, not the existing.

Your text proposal:

The PPR shall have the right to reassess and potentially require a repetition of the product prequalification or product verification, following the steps indicated in article 31 (Pre- Conditions and Applicability of the product prequalification and product verification processes), of an SPU or an SPG, when one of the following criteria applies:

(a) if the prequalified or verified capacity of the SPU or the SPG changes by more than the minimum between 10% and 3 MW compared to the previously prequalified or verified SPU or the SPG due to additions or removal of controllable units. If the PPR requires a repetition of the product prequalification or product verification, the service provider shall be entitled to participate in the market with the previous qualified set-up of the SPU or SPG;

(b) if the prequalified or verified capacity of the SPU or the SPG changes by more than the minimum between 10% and 3 MW compared to the previously prequalified or verified SPU or the SPG due to significant modernisation or updates of controllable units. The service provider shall provide on request by the PPR evidence of the modernizations or updates to the PPR;

Article 33

40 Your views on Article 33:

Your comment on the article:

General Comments:

Controllable units could not just be the final customers, but all kind of resources, included generation. Article 33 of the draft NC does not cover this reality. Hence, the term “final customer” must be replaced by “owners of controllable units” Same for articles 41, 43 and 45 and Table 2.1 of Annex 2.

Specific Comments:

- (1) We suggest rewording this paragraph to avoid the reference to technical aggregator: Owners of controllable units shall have the right to choose the service provider for their unit(s) and delegate in third parties owners' duties for interaction with service providers and for combining and controlling multiple controllable units

- (7) Article 33(7) must focus on impeding technological lock-ins in mass-produced devices by using controllability standards (e.g., IEC-62747) and publicly available technical documentation about how the controllable unit operation can be switched from a service provider to another easily, without giving relevance to the so-called “switching of technical aggregator”.

Your text proposal:

To avoid lock-ins, mass-produced devices need to follow a European standard (e.g., IEC-62747) for controllability of CUs. In addition, manufacturers of mass-produced devices must make available technical documentation about how controllable unit operation can be switched to another service provider within three weeks, easily and without improper impediments. Three years after entry into force of this act, the operator of a flexibility register platform with a CU module shall ensure technical switching processes for technical aggregators within 1 business day.

Article 34

41 Your views on Article 34:

Your comment on the article:

- (1) As foreseen in previous articles of this Network Code, product prequalification is applicable for standard balancing products and, under specific circumstances, it is also optional for specific balancing products, voltage control or congestion management services. Therefore, product prequalification doesn’t always apply.

- (9) & (10) Paragraph 7 foresees a simplified procedure whenever SPU or SPG are formed by CUs identical to other prequalified already under other SPU or SPG for the product declared by the potential service provider.

This concept of identical CUs must be further defined in a more objective way, or at least, the NC must foresee such definition is a precise and objective way within national T&Cs to be approved by the NRA.

Additionally, paragraphs 9 and 10 foresee that ENTSO-E shall report on the pre-qualification requirements and processes for standard balancing products across the EU and assess the need for further harmonization, after which (according to the results if such an assessment) a joint proposal may be submitted to ACER, to harmonize the prequalification process.

Considering this refers to standard balancing products, which should be traded in pan-European platforms, and for markets and products that should already have a high maturity level (unlike other products such as local congestion management, for instance), we see no point in having all these intermediate steps.

Standard balancing products, which are traded in pan-European platforms, must evolve for standard prequalification processes across the EU, and overcome the current barriers. It is evident the significant differences in rules required between different Member States and there is no reason to postpone this harmonization, in particular with the approach of the go-live of most TSOs in the pan-European platforms (e.g. Picasso), under common implementation frameworks.

Your text proposal:

Whenever product prequalification applies, and when multiple systems operators are potential buyers of the same product for the same SPU or SPG under prequalification, the systems operators shall agree on one PPR.
ENTSO-E shall recommend a harmonized implementation framework to the prequalification process for standard balancing products, within 12 months after the entry into force of this Network Code, and submit it for approval to the Agency.
This proposal shall be supported by a description of the prequalification process for each standard balancing product in each EU Member State, including the main steps, lead times as well as information and technical requirements, and build on existing best practices.

Article 35

42 Your views on Article 35:

Your comment on the article:

This article should be an amendment of EB GL.

Your text proposal:

Article 36

43 Your views on Article 36:

Your comment on the article:

General Comments:

Elaboration is necessary in the case that participation in congestion management is mandatory.

Specific Comments:

- (1) & (2) The time, foreseen in this article, for confirmation by the PPR to the formal application of a potential service provider is excessive (4 weeks to assess if the application is complete or require further information + 3 months after completeness confirmation to assess if it meets the requirements).

Your text proposal:

When the criteria of Article 31 (4) (b) (Pre-Conditions and Applicability of the product prequalification and product verification processes) are met and as a result product requires prequalification, the potential service provider shall submit a formal application to the PPR together with the required information of potential SPU or SPG. Within no more than 2 weeks from receipt of the application, the PPR shall confirm whether the application is complete. Where the PPR considers that the application is incomplete, the potential service provider shall submit the additional required information within at most 2 weeks from receipt of the request for additional information. Where the potential service provider does not supply the requested information within that deadline, the application shall be deemed withdrawn.
Within no more than 2 weeks from confirmation that the application is complete, the PPR shall evaluate the information provided and decide whether the potential SPU or SPG meet the criteria for a given congestion management and voltage control services. The PPR shall notify its decision to the potential service provider.

Article 37

44 Your views on Article 37:

Your comment on the article:

- (1) Not sure to be so open. Specific balancing products sometimes are in competition with standard ones.

- (2) We suggest rewording this paragraph for accuracy.

- (3) We suggest deleting "act as the PPR to" as it is unnecessary

Your text proposal:

A potential SPU or SPG for specific balancing products and congestion management and voltage control services shall have a temporary qualification for the participation in the respective market, until the verification process is performed.
The national terms and conditions for service providers shall clarify which systems operators will conduct the product verification process pursuant to Article 38 (Product Verification Process).

Article 38

45 Your views on Article 38:

Your comment on the article:

Suggestions below for legal clarity.

Your text proposal:

The PPR shall perform product verification and may request relevant data from service providers for evaluating a compliant delivery of the product as specified in national terms and conditions for service providers.
The PPR shall verify, based on the behaviour of the relevant SPU or SPG during the activation of the product, whether this SPU or SPG proved full compliance with product requirement and the verification criteria defined in national terms and conditions for service providers.
National terms and conditions are the framework to define the verification criteria, irrespective of the SOs proposing them, for each product based upon the minimum percentage of service deliveries or upon minimum percentage of quantity delivered from all activations or upon minimum percentage of the quantity delivered from a single activation or by combination of these criteria.

Article 39

46 Your views on Article 39:

Your comment on the article:

- (3) Data portability between flexibility register platforms should be a requirement disregarding of these being or not managed by a system operator.

Your text proposal:

To avoid vendor and operator lock-ins, and to facilitate competition and innovation, data stored by flexibility register platforms shall be portable to other flexibility register platforms, particularly

in cases where Member States or system operators decide to migrate towards new flexibility register platforms. (…)

Article 40

47 Your views on Article 40:

Your comment on the article:

Your text proposal:

Article 41

48 Your views on Article 41:

Your comment on the article:

- (1) & (2)(e) Access to platforms must be public: no need to specify different actors in paragraphs 1 and 2(e).

- (4) The Paragraph is not clear. Please, explain the purpose and the extent of this requirement and the reason why it is optional.

Your text proposal:

Article 43

50 Your views on Article 43:

Your comment on the article:

- (1)(d) Considering that, in a Member State, aggregator switching might be managed centrally by a designated entity to maintain and manage the database of aggregators, and respective switching, this article should also consider the possible link with such an entity’s platform.

Your text proposal:

(...)

(d) a ‘switching procedure’ allowing for service providers (or final customers) to request the assignment of existing controllable units to their portfolio on behalf of and with the consent of the final customer, or ensuring interoperability with existing platforms of designated entities managing aggregators’ switching;

Article 44

51 Your views on Article 44:

Your comment on the article:

We suggest moving this article to the beginning of its chapter.

Your text proposal:

Article 45

52 Your views on Article 45:

Your comment on the article:

General Comments:

We think this article should be merged with Article 5.

Specific Comments:

- (2), (4)(a), 4(g), 7(b) suggested rewording below for clarity.

- (9)(c) It's not clear that these should be different from (9)(a)

Your text proposal:

Systems operators may develop the national terms and conditions for service providers in each Member State separately
(...)

(a) requirements and procedures for flexibility register platforms, systems operators’ coordination, market platform operators and other relevant actors
to cooperate with service providers and procuring systems operators to perform end-to-end training tests;

(...)

(g) A process for assigning, switching or removing the aggregator for a controllable unit as set in Article 33 (Switching of Controllable Units) paragraph 7.

(...)

(b) the condition to perform an ex-post verification test pursuant to Article 32 (Criteria for reassessment of product prequalification and product
verification);

Article 46

53 Your views on Article 46:

Your comment on the article:

- (4) Clarity is needed on what constitutes "in due time" and "without undue delays."

Your text proposal:

Article 47

54 Your views on Article 47:

Your comment on the article:

- (3) To align better with paragraph 104 of the FG, as well as other relevant legislation (SOGL, Electricity Regulation Art. 13, among other), we suggest explicitly starting that market-based procurement should be prioritised as far as possible.

- new (5) Additionally, this article refers to the assessment of market-based procurement vs. other tools, and to the cost-efficiency assessment to decide on the most appropriate tool. However, it lacks clear rules on the governance regarding such an assessment.

Your text proposal:

Non-market based redispatching may be applied within a bidding zone and/or network area, if an exception set forth in Article 13(3) of Regulation 2019/943 applies, however, market-based options should be privileged by principle.

(new) (a) Non-market based redispatch as foreseen in paragraph 3, or any redispatch related to grid prequalification where SPU or SPGs are under a firm connection agreement or license (or where the redispatch exceeds the conditions for non-firm connection agreements or license), shall be financially compensated, as set in Article 19.

For the purpose of paragraphs 2, 3 and 4 in this article:

a) By one year after entry into force of this Regulation, the system operators shall, at national level, present to the NRA a common proposal with a methodology under which they shall assess marketbased procurement of local system services and compare it with other tools such as those foreseen in paragraph 2.

b) The NRA shall pursue a public consultation for at least one month, after which it shall decide to approve or the request for amendments, which must occur no longer than two months after the closure of the public consultation.

c) In case the NRA request for amendments, the system operators shall incorporate them and submit a new revised proposal for approval by at most one month after the NRA request.

d) After receiving a revised common proposal from system operators, the NRA shall either approve or amend and publish a methodology to be pursued by all system operators, that should be the base to assess between market-based procurement of local system services and other options, namely grid investments under the NDPs.

Article 48

55 Your views on Article 48:

Your comment on the article:

- (6)(a) We suggest to reword to "whether locational information is needed;“

There is no need to couple rules on different markets. DA/ID markets must be on portfolio basis, whereas balancing and other SO services can require to some extent some locational information, after due justification, in order to promote aggregation/flexibility to the maximum extent.

- (6)(k) Additionally, we propose to delete (k) in paragraph 6 as this should be out of scope of the system operator assessment.

- (7)(f) Suggest to replace "long-term, day-ahead, intraday and balancing markets" with "electricity markets" given existing definition in Directive (EU) 2019/944.

- (10) The combination of bids has severe implications for pricing, liability and adjustments. We do not understand why the combination of bids is necessary.

Your text proposal:

When preparing the national terms and conditions referred to in paragraph 4, DSOs and TSOs shall consider the national context at least including:

(a) whether, in any electricity market, locational information is needed or available;

(...)

(f) The coordination with operators of electricity markets;

System operators shall present a common proposal for market-based congestion management mechanisms to the national regulatory authority that complements the existing non –marketbased mechanisms in line with paragraph 4. This proposal shall describe interactions with existing non-market-based mechanisms.

Article 50

57 Your views on Article 1:

Your comment on the article:

- (1) (a) This paragraph should reflect the possibility of applying penalties.

- (3) "certain conditions" should be elaborated and specific.

Your text proposal:

Article 51

58 Your views on Article 51:

Your comment on the article:

General comments:

A clarification if needed from ACER/EC on how to deal with non-firm connection agreements, that they can be seen as a way to minimize congestion relief needs or, alternatively, be defined as a product. We caution about the approach of considering them while defining the pre-conditions to participate in services because can have complexity in the definition of products and ways of procuring them.
Any provision regarding non-firm connection agreement shall be dully adjusted to the final wording to be agreed within the trilogue negotiations regarding the electricity market design review, in particular in what concerns flexible connection agreements.

Still, it makes sense to include the concept in the network code, namely considering the coordination and links between such tools and flexibility procurement.

It is also important to foresee that flexible connection agreements shall also be subject to marketbased rules, through competitive procedures, and a clear framework shall be set to ensure a fair assessment of different options, and even how they should interplay in a complementary approach. Additionally, it must be clear that any limitations should apply differently under a flexible connection agreement, than they would under a firm connection agreements, and which compensations shall apply.

Finally, Article 51 defines that non-firm connections can have the possibility to participate in congestion and voltage markets. However, a non-firm connection was given because of the need to limit the power requested, or injected, by the non-firm client due to grid limitations, in agreement with the client. To that end the non-firm connection agreement was established which contains requirements for the system operator to limit the client non-firm power. Any set of measures to avoid grid congestion undertaken by the relevant system operator should necessarily begin with limiting the non-firm clients. Therefore, it does not make sense for non-firm clients to be participating in congestion markets, otherwise, there would be no difference between non-firm clients and firm clients.

Your text proposal:

If flexible connection agreements are allowed in a member state, the relevant national authorities shall define at national level the framework for non-firm connection agreements” including their applicability, scope, limitations and conditions for compensation if any.
National terms and conditions, subject to the NRA approval, or other applicable national regulation shall ensure that flexible non-firm connection agreements do not lead to marketdistortion by providing rules following these principles:

(a) When flexible connection agreements are allowed in a Member State, market-based and competitive procedures shall be privileged as far as possible.

(b) When flexible non-firm connection agreements are established, transmission and distribution system operators shall not unduly limit the possibility for grid users to provide services in other markets, nor shall flexible connection agreements distort flexibility procurement by system operators, including the system operator to which the resource is connected;

(c) When non-firm connection agreements are allowed, an assessment methodology and the conditions for systems operators to choose non-firm connection agreements shall be specified;

(d) When non-firm connection agreements and markets for voltage control services co-exist, the interaction between the two options shall be specified;

(e) When non-firm connection agreements and markets for congestion management services coexist, the interaction between the two options shall be specified, namely the priority given to limiting the flexible connection agreements, up to the extent of the flexibility terms defined and unless the costs of doing so exceed the cost from additional procurement;

(f) SPU or SPGs under flexible connection agreements may be limited to participate in local or balancing markets for the relevant timeframes and to the extent of the terms established in the connection agreement; and

(g) When the provision of services by units affected by flexible connection agreements is allowed at national level, the connecting and intermediate system operator shall be able to communicate restrictions, to the extent of non-firm level foreseen in such agreements, by setting limits during applicable grid prequalification process or following short term procedure defined in Title VII article 74 (Short-term procedures to account for DSO limits).

Article 52

59 Your views on Article 52:

Your comment on the article:

- (2) For the sake of transparency, information of the expected needs and characteristics of services to be provided shall be made available without restrictions.

- (5) This information should also be published in the transparency platform (with harmonized formats and data sets), that already discloses info for balancing products.

- (6) This paragraph 6 must be merged with the previous one. No need to involve „local market operators“. The obligation is from SOs, who can delegate in local market operators.

Your text proposal:

The systems operators shall publish:

(a) indicative but non-binding information on the different product needs, whether it is up- or downregulation, the foreseen utilization patterns, expected volumes or other information, with sufficient granularity and detailed per different time horizons; and

(b) locational information for the participation of assets to provide the needed services, and where relevant other information such as the impact factor.

Article 53

60 Your views on Article 53:

Your comment on the article:

- (1) We suggest to replace “long-term, day ahead and intraday as well as balancing markets” by “other electricity markets”, as “electricity markets” is a concept already defined the internal electricity market Directive.

Also, because most of these markets are not confined to national markets and benefit from crossborder trading (which is the case for day-ahead, intraday and balancing), it doesn’t seem reasonable to consider requirements for interoperability and portability at national level.

- (4) Additionally, paragraph 4 foresees the possibility to “transfer” or reuse bids between markets. We consider this chapter needs to be further developed, especially as this relates to markets that already exist and that are not fit for defining rules at national level because these are not mere national markets. There are coupling mechanisms for both day-ahead and intraday, there are paneuropean platforms for balancing products, and even for those where no platforms are foreseen, they also assume cross-border trade (e.g. FCR assumes a need defined at the level of the synchronous area and then detailed at national level; non-standard balancing are also used to solve cross-border issues).

Additionally, it is necessary to consider at least 2 elements:

• Using bids between markets requires voluntary consent from the market participant for each bid, to allow for bid transfer and to agree on pricing conditions.

• Reusing bids or transferring bids need to take into account the products associated, namely if they are capacity products, energy products or if they comprise both.

We therefore suggest to further detail the rules regarding this bid transfer or reuse, or to include further assessment to be made under articles 83 and 84, and to ensure 3 basic principles regarding:

• EU harmonised rules, compatible to the current functioning of electricity markets such as DA, ID and BAL

• Voluntary participation and consent per bid and price conditions

• Incorporate interlinks of product characteristics, namely capacity products, energy products or products encompassing both capacity and energy components.

Besides this general remark to the need to further clarify we suggest the following amendments to:

• Incorporate the above mentioned principles;

• Link with compliance with REMIT and competition Law, which address topics such as capacity withholding and market abuse

• Take into account the provisions from the IEM Directive (art 15, 5, d)), that foresees "Member States shall ensure that active customers that own an energy storage facility: (...) (d) are allowed to provide several services simultaneously, if technically feasible".

- (5) We suggest deleting this provision - markets will optimise themselves over time; allowing regulation to limit the number of available marketplaces risks another kind of market inefficiency.

Your text proposal:

When defining the national terms and conditions for the market design for congestion management and voltage control services the following principles shall be respected for the coordination of and interoperability between local markets and other electricity markets as defined in the Directive (EU) 2019/944:

(a) interoperability and portability, in line with paragraph 2(f) between local markets and other electricity markets

4. (...)

(a) Specify whether and under which conditions bids offered in day-ahead, intraday and balancing markets can be used for congestion management, and under which terms. Even if this is an option it shall be possible to organise additional local markets. This only applies regarding day-ahead, intraday and balancing markets, where further EU wide rules are specified under articles 83 and 84 of this Regulation;

(b) Describe how markets for congestion management and voltage control services shall interact with day-ahead, intraday and balancing markets, under the EU wide terms and conditions specified under articles 83 and 84;

(c) Comply with existing regulation namely regarding market integrity and transparency (Regulation (EU) 1227/2011), and general Competition Law;

(...)

(e) Allow bids that are not procured in one market to be offered to another market, given they are qualified for that market. To achieve this the service provider may offer their services in another market themselves including by means of an intermediary or a market operator may forward the bids, given that the concerned service provider has given its consent, for each bid to be transferred and agreed with the terms and conditions (namely pricing). Aggregation of bids for forwarding to meet the requirements of other markets shall be possible; and

(f) Prevent the same bid from being selected twice, unless technically feasible, in particular where the same SPU/SPG is active in different markets, and the responsibilities for guaranteeing that.

(new) (g) Take into account the specificities associated to the bids made for different products and markets, namely considering these may be capacity or energy products or products that encompass both components.

Article 54

61 Your views on Article 54:

Your comment on the article:

- (2)(b) For consistency in the sentence which seems incomplete we propose the following rewording.

Your text proposal:

(...)

(b) The procuring system operators shall not exchange preferential, confidential and sensitive information with affiliated companies and other service providers; and

Article 55

62 Your views on Article 55:

Your comment on the article:

We suggest to delete this article.

Management of resources by SOs must be set up on robust but simple governance: the interface for structural, scheduled and real-time data exchange with TSOs and DSOs of any kind of resources (not only demand response) and the necessary market arrangements must be established at national level without double reporting requirements and by avoiding overlap of roles or unnecessary creation of new regulated ones. Hence, definitions and tasks described for the roles of “CU Operator”, “technical aggregator” and “local market operator” must be removed, because the delegation right is already present in the SO GL and replicated in article 16 of the draft NC, and Regulation (EU) 2019/943 and Directive (EU) 2019/944 do not include these roles.

Only general principles about interfaces for data exchanges and delegated tasks aligned with current KORRR framework and general requirements of any kind of solutions of market platforms should be set up in the draft NC.

Your text proposal:

Article 56

63 Your views on Article 56:

Your comment on the article:

General comments:

The concept of a local operator appears in the draft Code (not as a national operator, but an operator within a specific area of a given DSO network), which we stress that it should be a DSO, and only in exceptional circumstances it may also be a TSO, which should only be possible in strictly defined local conditions and regulated at the national level. The very wording of this proposed provision, like many others in the draft Code, does not reflect the current situation of decentralization of the power sector and development of local areas based on the DSO network.

Specific Comments:

- (1) to (3) Local market operators shall be designated or be authorized by NRAs, and not be selfdefined or self-appointed by system operators by default, as a NRA may decide to set one single common local market operator, or define which system operator(s) or other entity(ies) shall take such a role.

Your text proposal:

National Regulatory Authorities, or another competent authority at Member State level, shall describe in terms and conditions referred to in Article 48(4), functional requirements of local market operators and a process for nomination of local market operators, or assess and approve a proposal presented by system operators.
The process for nomination of local market operators shall result from national regulatory authority’s assessment or take duly into account proposals of each procuring system operator (and including the national regulatory authority’s assessment) ensuring that the local market operators meet the general requirements described in Article 55 of this Regulation and in national terms and conditions referred to in Article 48(4).
(...)

Article 57

64 Your views on Article 57:

Your comment on the article:

General Comments:

It should be avoided that we end up with different local market operators for each DSO. To avoid fragmentation (for example in Germany where there are hundreds of DSOs), the network code should give TSOs, DSOs, NRAs and local market operators a mandate to cooperate and to at least create a common interface for market participants, ideally only a limited number of local market operators (each operating multiple locations of course).

Specific Comments:

- (3)(c) LMOs must not be able to validate delivered services in any circumstance.

We do not support to confer the task of neither validation of delivered services to third parties nor activation as explained in footnote 8. Validation is a core task of SOs and then not possible to delegate. As regards activation of bids, it must rely on the service provider in general, although it can be possible arrangements with direct activation of the connecting SO, but never dealt by a market platform. Otherwise, we could face double reporting, multiple business interfaces and the deployment of additional procedures to implement those activities.

Your text proposal:

(...)

(b) (...)

iii. the information to service providers, system operators and the market transparency platform, on the market results;

The platforms referred to in paragraph 1 shall integrate or communicate as applicable with the flexibility register platform(s).

Article 58

65 Your views on Article 58:

Your comment on the article:

The way congestion product is activated is a key attribute: redispatching or schedule adjustment in the energy markets. If redispatching is used, the way to rebalance the redispatch is an important complementary attribute but cannot be defined as balancing.

Avoidance of fragmentation of products at national level must be reflected (as a principle in Article 59), and governance in Article 58 must endeavour to promote common practices and align attributes within Member States to the maximum extent. Otherwise, we risk of having a circular task at EU level without any added value because it is aimed to update a catalogue of national practices. Moreover, process described in article 58 must include public consultation.

Your text proposal:

Article 59

66 Your views on Article 59:

Your comment on the article:

Avoidance of fragmentation of products at national level must be reflected as a principle in Article 59. Otherwise, we risk of having a circular task at EU level without any added value because it is aimed to update a catalogue of national practices.

Article 59 must differentiate local products used by DSOs (i.e. in a particular bus bar) from national products managed by TSOs (i.e., same rules and procedures for congestion issues at bidding zone level although the congestion arises at local/zonal level). The task of standardization referred to in Article 59(1) is too vague and can lead to a blockage of valuable DSO initiatives.

Your text proposal:

Article 60

67 Your views on Article 60:

Your comment on the article:

Your text proposal:

If the products from other day-ahead, intraday or balancing markets are used for congestion management, as foreseen in Article 53 (Principles for the coordination and interoperability between local and day-ahead, intraday and balancing markets), then those products shall be included in the list of standardised products for congestion management as referred to in Article 58 (List of attributes).

Article 61

68 Your views on Article 61:

Your comment on the article:

Regarding SO-owned storage, we believe that articles 61-63 of the draft NC do not satisfactorily comply with section 2.5 of ACER FG, for the following

reasons:

(a) The principle of “first-market” must be further developed, especially in the case of TSO ownership of storage as reflected in paragraph (38) of the ACER FG and Electricity Directive. These aspects must be carefully checked by ACER and EC during the approval process of the draft NC.

(b) Those articles must be focused on ownership, not cover “develop, own, operate or maintain storages”, as referred in a recurrent manner across the wording. and eliminate wording showing clear vested interests. Examples:

· Article 61(1)(c): generic reference to efficient, reliable, and secure operation.

· Article 61(3): right of SOs to opt for co-owned storage, instead of stating that it is a second-best as referred in paragraph 39(b) of the FG GL.

· Article 61(8): decision by SOs of discard co-owned storage during the tender procedure.

· Notification of NRA to ACER according to article 61(10) shall be compulsory irrespective of the SO (TSO or DSO).

· Article 62(1)(b) does not impose a real firewall to implicitly breach the prohibition of participation in electricity markets.

· Any real right is conferred to the third party in article 62. Moreover, there is no reference to crosssubsidy in both senses, only from SO to the third party.

· Article 62 does not elaborate interactions between third-party and SO when managing jointly a co-owned storage.

· Article 62(5) must elaborate conditions to transfer ownership to the third party. This must be referred to in article 63(2) as part of the proposal of transfer. Conversely, condition under article 63(2)(d) must be deleted: it is an unfair balance commitment.

· The condition of “technically possible” in article 63(1) must be defined accurately. Otherwise, it must be deleted.

· Article 63(4)(a) comes up to a circular situation: no open, transparent and market-based flexibility services can take off in this context.

(c) There are several mandates of ACER FG not sufficiently fulfilled by the wording. Instead, the wording in unduly focused on principles and ways of conducting derogations according to the Electricity Directive, or preconditions to launch the tender, or any decision after the tender or in parallel. Those aspects are exclusively managed by NRAs, hence out of the scope of the draft NC. Examples of vague development:

· “criteria to be fulfilled by the tendering procedure in order to be approved by the NRA” (paragraph 39 of the CER FG).

· “ownership and contractual relations (for use of the facilities, distribution of costs, etc) between the SO and the third (paragraph 40 of the ACER FG)

· Guidance for the scope of the CBA as mentioned in paragraph 41 of ACER FG.

According to the framework guidelines, this article (or a new article) should also specify criteria to be fulfilled by the tendering procedure to be approved by the NRA. These criteria are lacking in this network code and should include:

(a) Participation conditions that shall enable participation of demand response and other relevant resources that can deliver the services needed by the SOs to fulfil their obligations, in addition to storage participation.

(b) The tender shall include the possibility of shared ownership and operation of a storage facility between the SO and a third party, as a “second best” solution to the SO procuring the total needed service from a third party.

(c) Selection criteria shall be technology-neutral and select the best techno-economic option, maximizing social welfare including when comparing to an SO owned storage facility.

(d) Transparency of the selection criteria and the results of the tender.

(e) Clear communication on the technical conditions of the tender, including as much information as possible for the potential SPs to prepare an adapted offer, such as the foreseen utilisation pattern and expected volumes, and with sufficient granularity.

(f) Clear communication on economic conditions of the tender. The transparency on the economic conditions shall be balanced against the potential impact on the pricing of the offers.

The specifications of the tender shall be submitted to public consultation and to NRA approval prior to the tendering process. Further criteria to be fulfilled by the tendering procedure shall be defined at national level. After the tender, the NRA may grant a derogation or a partial derogation (for shared ownership) if a third party cannot deliver the service at a reasonable cost and in a timely manner. In this case, the partial derogation shall be preferred if economically efficient.

This Network Code should also define the governance to set an assessment methodology under which it should define how to evaluate what is considered a reasonable price for service delivery.

The Framework Guidelines set for SO-owned storage included several elements that don’t seem to be considered in the Network Code, while some of the provisions in the Network Code are redundant, regarding what is already foreseen in the IEM Directive (therefore do not be to be replicated in the network code) and are confusing.

For instance, the Framework Guidelines foresee that the new NC rules shall specify criteria to be fulfilled by the tendering procedure in order to be approved by the NRA, including a series of elements. Such criteria are not being considered in the draft proposal of the Network Code.

Also, Article 36 of the IEM Directive already sets the conditions under which Member States may grant a derogation for owning and operating storage facilities, by system operators, and they do not be to be repeated in the network code.

Your text proposal:

By way of derogation Member States may allow distribution system operators to own, develop, manage or operate energy storage facilities, when the conditions set in the Directive (EU) 2019/944 are fulfilled. (Strike remaining paragraph 1 not included above, paragraph 2, and paragraph 4)
In addition, where a derogation in line with Article 36 or 54 of Directive (EU) 2019/944 has been granted, systems operators may consider sharing ownership and operation of such storage facilities. This is without prejudice to the systems operators’ rights, if such a right is given by Member State, to develop, own, operate or maintain fully integrated network elements as regulated in articles 36 and 54 of Directive (EU) 2019/944. In case systems operators consider implementing a shared storage ownership or operation, systems operators shall submit to public consultation the general terms and conditions of tenders, including the intended shared ownership agreement, it will perform, then submit the tendering process to NRA approval prior to the tendering takes place. Such tendering process may be specific to each systems operators and each assets.
System operators shall publish information on economic conditions of the tender for shared ownership and operation.
The tendering procedure shall ensure the selection criteria and results of the tender are open, transparent, and non-discriminatory.

9. (...)

(a) Discard the possibility of shared ownership, and grant the systems operators a time-limited derogation to own, develop, operate and manage the storage facilities; or

(b) Approve, if relevant, the final shared ownership agreement and grant the systems operators a time-limited derogation to own, develop, operate and manage the storage facilities under shared ownership and operations agreement.

The NRA shall notify the decision to grant a derogation to the Commission and ACER together with relevant information about the request and the reasons for granting the derogation.

Article 62

69 Your views on Article 62:

Your comment on the article:

General comments:

Elaboration is necessary on interactions between third-parties and SO when managing jointly a coowned storage.

Specific comments:

- (1)(a) Suggest to reword to "shall use its part of the storage facility to only fulfil its obligations (under Articles 36 and 54 of Directive (EU) 2019/944) for the efficient, reliable and secure operation of its grid; and"

- (1)(b) It does not impose a real firewall to implicitly breach the prohibition of participation in electricity markets.

- (2) As in any other resource owned and managed by a market party, third-parties with shared storage have no way to operate (or not) based on whether they may (or not) cause congestion or other issues to the grid, and the terms for operation by the system operator shall be very clear in the operations agreement from the beginning of the shared ownership. This type of requirements shall not be imposed as, an asset owned and managed by a market party needs to be in level playing field with the remaining resources/service providers in the market.

Your text proposal:

(...)

(a) hall use its part of the storage facility to only fulfil its obligations (under Articles 36 and 54 of Directive (EU) 2019/944) for the efficient, reliable and secure operation of its grid; and

In case of shared ownership or operation of the storage facility, the third party shall own and operate its part of the storage without further constraint, as concerns shared ownership and operations. The third party shall be responsible for the imbalance they cause and for the purchase or the sale of the energy for its part in line with national terms and conditions. The third party shall be treated as any other participant while operating its part of the storage.

Article 63

70 Your views on Article 63:

Your comment on the article:

- (1) It is not clear why it wouldn't be technically possible to transfer SO storage activities to a third party. As currently written, this could then limit the provisions foreseen in the Directive regarding periodic assessment of market interest.

- (2)(d) We suggest deleting this provision. This condition isn't necessary. As in any other resource owned and managed by a market party, third-parties with shared storage have no way to operate (or not) based on whether they may (or not) cause congestion or other issues to the grid, and the terms for operation by the system operator shall be very clear in the operations agreement from the beginning of the shared ownership. This type of requirements shall not be imposed as, an asset owned and managed by a market party needs to be in level playing field with the remaining resources/service providers in the market.

- (3) The NRA should have the final decision after the assessment of the SOs

- (4) "sufficient interest for third parties to take over the system operators owned storage, and if there" should be deleted because if at least one 'acceptable offer' is present, this should trigger the process. NRAs, not system operators, must drive this process

- (4)(a) Why? This can also be done by another aggregator as with any other asset/technical resource

- (5) to (10) Additionally, the Framework Guidelines (paragraph 41 b), also foresee the possible phase-out of the SO storage and purchase the necessary services from third parties, if a CBA shows that it is preferable rather than continuing the SO storage activity.

In fact, the market may be able to provide the required services to the system operators, in a more cost-effective way, and thus the system operators shall phase-out own storage activity even if no market parties are interested in acquire such ownership, as the technologies might already be outdated, the associated cost and historic assumed obligations might be excessive, for the existing conditions in the market at the time, the location is not favoured by the market parties in association with other resources they own, or for any other reasons.

There is no reason to impose and keep a less efficient solution and this seems to be addressed in paragraphs 5 to 9 of this article. However, it’s not entirely clear as some of these paragraphs keep references to the tender regarding the transfer the property, to the transfer in itself and resulting compensation, which should not apply in those conditions (where simply the existing market services are more cost-efficient and thus no transfer of the assets need to occur but simply a phaseout of the activity and potentially a decommissioning of the assets), and there are also a few incorrections in some of the links.

Your text proposal:

Where it is technically possible to transfer systems operators storage activity to third party and where storage is not a fully integrated network component, the regulatory authorities shall perform a public consultation on the existing energy storage facilities in order to assess the potential interest in investing in such facilities. Such consultation shall take place at least every five years as prescribed in article 36.3 or 54.4 of Directive (EU) 2019/944 and shall be aligned as much as possible with applicable grid planning processes such as NDP. Systems operators shall define the criteria needed in §7, to select the best offer from third party. Those criteria shall be published before the tendering.

2. (...)

(b) their offer regarding the take-over of systems operators’ owned storage and operations;

Where the public consultation referred in paragraph 1 of this article shows there is at least one acceptable offer as per §3, systems operators shall engage a process in line with Title IV...
This cost-benefit analysis shall pursue a methodology approved by the NRA and subject to prior public consultation.
NRA shall assess whether the overall cost benefit analysis concludes it is preferable to phase out of the systems operators’ storage and purchase the necessary services from third parties rather than continuing the systems operators’ storage activity based on the information from paragraphs 5 of this Article.
The NRA shall ensure that systems operators phase out storage activity within 18 months if at least one of the following all two three criteria are fulfilled:

(a) if there is at least one acceptable offer as per §3 which revels to be more cost-efficient than procuring the necessary services from third-parties;

(b) if third parties are willing to provide the services that the systems operators needs and the CBA foreseen in paragraphs 6 and 7 concludes it is preferable to phase out of the systems operators storage and purchase the necessary services from third parties rather than continuing the systems operators storage activity

If one of the two all three conditions for the phase-out described in §76 are fulfilled;

(a) NRA decides on the start date of the 18 months phase out period;

(b) Where applicable, the systems operators shall decide on the best acceptable offer according to the criteria set forth in §1 and assessment in §3."

Within 18 months from the date of the NRA set forth in §8 of this Article:

(a) system operators shall phase-out activity on that facility

(b) where applicable, system operators transfer the storage activity to the selected third party(ies), and shall receive compensation according to the proposals received;

(c) where applicable, the systems operators contract the congestion management and voltage control services that match in a timely manner the systems operators needs in price or cost, and in volume, or discard these offers. Systems operators shall publish the outcome of the tender in line with Title IV article 52 (Publication of information).

Article 64

71 Your views on Article 64:

Your comment on the article:

General Comments:

The regulations regarding the network development plan clearly show that the center of gravity of the provisions of the Code lies in the local area, i.e. for DSO. In addition, Eurelectric studies – “Power System for the future - Keys to delivering capacity on the distribution grid - October 2023”, “The Coming Storm - Building electricity resilience to extreme weather - December 2022” and others indicate where this key area (i.e., the DSO area) is. Local DSO forecasting is crucial in the context of the need to ensure practically 100% power supply when all activity is based on electricity. It would be important to write down the rule for the use of a given flexibility product/service to be as close as possible to the place of its origin.

Specific Comments:

- (3) Chapter 11 of the proposed network code, and in particular article 64.º establishes a complex and thorough process regarding the Distribution Network Development Plan (DNDP). It is important to notice that the Directive (EU) 2019/944 already addresses the issue of the DNDP, particularly in article 32 of such document. Besides this, the directive establishes only some guidelines and provides the member states with the possibility to implement the DNDP in a way that is more convenient for them. Thus, it is very important that the proposed network code should not go beyond what is already in the Directive (EU) 2019/944.

Also, because some member states already have established their own process for DNDP, it is important to ensure some stability and avoid introducing new, disruptive and conflicting processes like the one being proposed in this network code. For instance, the number 3 of article 64.º states that before DSOs could submit the DNDP proposal to the regulatory authority they shall run a public consultation following the principles laid down in article 68. In the case of Portugal this does not makes sense because the process that was approved assigns the regulatory authority with the task of performing the public consultation. Therefore, to be compliant with national legislation and the proposed network code, it would require two public consultation processes.

Because of this, we consider that, although it is important to establish the need for the DSOs to do a DNDP, the processes and content should be left for the Member State to define. In fact, the distribution network is local in nature and thus is beneficial to have the flexibility to adjust different processes and contents to address local issues.

In case the decision is to keep articles 64.º through 68.º, detailing the process regarding the elaboration and approval of the DNPD, number 3 of article 64.º should make reference that only one public consultation process is required, whether it is made by the DSO, prior to submission to the NRA, or by the NRA after submission by the DSO.

- (6) Also, considering that the NDP should assess grid investment also taking into account other alternative solutions, we propose to make a slight amendment in paragraph 6.

Your text proposal:

The DNPD should have a public consultation procedure following the principles laid down in the TITLE VI Article 68 (DNDP public consultation and publication), whether it is done by the DSO before submitting the DNPD to the NRA, or by the NRA after submission of the DNPD by the DSO.
System operators within Member State shall ensure, where relevant, that their development plans are coordinated and the necessary information to prepare the network development plans is exchanged during the development process in order to identify the need of grid investments or implementation of other solutions.

Article 65

72 Your views on Article 65:

Your comment on the article:

- (2)(h) Considering that the NDP should assess grid investment also taking into account other alternative solutions, besides flexible connection agreements namely flexibility procurements which is the main focus of this network code, we propose to make a slight amendment in paragraph 2(h).

Your text proposal:

(...)

(h) consider alternative solutions such as flexible connection agreements, flexibility procurement and other, where applicable; and

Article 66

73 Your views on Article 66:

Your comment on the article:

- (3) There is a reference missing to existing planning exercises - the scenario(s) developed should be consistent with existing exercises like the TYNDP.

Your text proposal:

The scenario(s) assumptions shall be described comprehensively for stakeholders and publicly consulted.

Article 67

74 Your views on Article 67:

Your comment on the article:

- (3) & (5) We suggest these paragraphs should be merged and a clause should be added ensuring public availability of the information.

Your text proposal:

Article 68

75 Your views on Article 68:

Your comment on the article:

- (1) and (2) Article 68(1) and (2) should be merged and refer to stakeholders, including relevant grid users (not system users).

- (9) Incomplete paragraph, should refer to the NRA (for coherence with the rest of the document) and should elaborate further what the amendment request process looks like.

Your text proposal:

Article 69

76 Your views on Article 69:

Your comment on the article:

General comments:

It should be explicitly stated in this article that there should be no double reporting obligations for service providers and relevant grid users.

Specific comments:

- (3) There should be a clarification when referring to "another competent authority" that this excludes system operators (we understand in some Member States system operators may be delegated this responsibility, and we are concerned about the possibility of a system operator being in a position where they may be approving their own proposals)

Your text proposal:

Article 74

81 Your views on Article 74:

Your comment on the article:

- (1)(f) (new) In case of unplanned outages in the DSO network it may be necessary to feed affected clients through alternate grid configurations. To replenish service to most clients it might be necessary to impose limits to market participants.

Similarly, congestion is forecasted assuming a generation and load profile. If any generator, or consumption client, experiences an internal outage the forecast might change and require emergency actions by the DSO to avoid outages to many clients.

Therefore, it is advisable that the DSO has the possibility to apply emergency limitation to market participants even if their bids have already been accepted. The proposal is that in case of such emergency limitation that the market participant should be rewarded by its accepted bid.

- (5) (new) When bids or contracted capacity are not activated or are limited, due to temporary limits in the connecting or intermediating grid, service providers that are limited in that regard shall be financially compensated in the same terms foreseen in article 13 of Regulation (EU) 2019/943. Such limitations to bid or redispatch shall be compensated, ideally under market-based procedures or, even if using non-market based these shall foresee a financial compensation at least equal to the higher of the following elements or a combination of both if applying only the higher would lead to an unjustifiably low or an unjustifiably high compensation:

(a) additional operating cost

(b) net revenues would have otherwise generated; where financial support is granted to powergenerating, energy storage or demand response facilities based on the electricity volume generated or consumed, financial support that would have otherwise been received shall be deemed to be part of the net revenues.

Your text proposal:

(...)

(f) In emergency actions necessary to avoid an outage or damages to clients the DSO can impose immediate limits on the power injected or demanded from the network by any client. If a bid has already been activated the SPU will conform with the DSO imposed limits and will in no way be financially harmed having its bid paid in full by the market operator.

Bids and volumes not activated due to temporary limits shall be subject to financial compensation by the system operator imposing such limits, in the terms foreseen in article 13 of Regulation EU (2019/943), namely considering the net revenues that would have otherwise been generated.

Article 75

82 Your views on Article 75:

Your comment on the article:

- (10) (new) Similarly to article 74, when bids or contracted capacity are not activated or are limited, due to grid prequalification status that inhibits such participation, set by connecting or intermediating grid, service providers that are limited in that regard shall be financially

compensated in the same terms foreseen in article 13 of Regulation (EU) 2019/943. Such limitations to bid or redispatch shall be compensated.

Your text proposal:

Bids and volumes not activated, due to grid prequalification status set by connecting or intermediating system operators that inhibits such participation, those shall be subject to financial compensation by the system operator imposing such restrictions, in the terms foreseen in article 13 of Regulation EU (2019/943), namely considering the net revenues that would have otherwise been generated.

Article 77

84 Your views on Article 77:

Your comment on the article:

Reference to Article 41 for national terms and conditions, but in this Code, Article 41 refers to principles and requirements for operators of flexibility register platforms.

Your text proposal:

Article 78

85 Your views on Article 78:

Your comment on the article:

General Comments:

Some provisions in Articles 78-80 can take the form of amendments of the corresponding ones of SO GL or be introduced directly in the SO GL always with the DSO perspective for the sake of completeness.

Specific Comments:

- (7) Suggest to merge with paragraph 2.

Your text proposal:

Article 79

86 Your views on Article 79:

Your comment on the article:

- (2)(b) This structural data must be provided by the DSO.

Your text proposal:

Article 80

87 Your views on Article 80:

Your comment on the article:

This article foresees that grid users that are either SGU or participate in congestion management or voltage control issues, shall provide individual data of schedules for day-ahead (and any changes) or baselines, and real-time data.

This article should be eliminated considering that:

• Requirements for SGU are already addressed in Regulation (EU) 2017/1485

• Baselines are already covered along this network code for the purpose of providing the hereby considered services, and no additional data should be required, and even less at individual level as it should be provided in aggregated way where appropriate (which is also considered in the network code)

• Real-time data should be under the scope of action of the system operator in itself for observability and management of his own grid and no additional burden should be required to grid users in that regard.

We therefore propose to eliminate article 80.

Your text proposal:

Article 81

88 Your views on Article 81:

Your comment on the article:

General Comments:

Voltage services must be jointly developed in the draft NC, for the sake of clarity. They can be procured through congestion management (via redispatching of active power) or with use of reactive power (i.e. contracted as capacity & energy). These services are the real novelty of this draft NC. As there are very local by definition, it is important to set clear and ordered rules in the draft NC.

Specific Comments:

- (1) It is not clear why this is in the Network Code as it is already established in the SO GL (an amendment to include DSOs in the SO GL would make more sense)

- (2) When procuring voltage control services, mandatory capabilities must be remunerated for the sake of market coherence. These must be defined as a minimum requirement set uniform for all service providers. Article 81(2) must be reworded in that sense: SOs cannot assume that capabilities required to new facilities set up in connection codes (for generating, demand and storage) are delivered to SOs for free. This affects the investment signal for delivering additional ones by implementing new technological solutions and for disclosing new capabilities within existing or new facilities.

Mandatory requirements for the purpose of reactive power are only considered in the connection network codes, setting obligations regarding the type of equipment some resources must have so they’re able to provide reactive power services.

The SO GL determines the voltage levels within which the system shall remain and the levels until which the resources shall remain connected (RfG and DCC), similarly to what is also set for frequency levels.

However, there is no obligation to some resources having to mandatorily provide reactive power to the system and without proper compensation.

By the contrary, the Regulation (EU) 2019/943 determines that ancillary services overall (including non-frequency ones) shall be procured under market-based rules, which implies this should be provided voluntarily and remunerated.

- (3)(a) (i-iv) Whether these conditions are fulfilled should be decided by NRA.

Your text proposal:

(...)

(b)(...)

ii. the procurement of reactive power in addition to the mandatory requirements through a congestion management and voltage control services; or

Article 82

89 Your views on Article 82:

Your comment on the article:

- (3) Steering Committees of national concepts with participating market participants must be foreseen.

Your text proposal:

Article 83

90 Your views on Article 83:

Your comment on the article:

Articles 83 and 84 refer, both, to monitoring, assessment and further harmonization, which seems to lead to some overlap.

Also, while Article 83 refer clearly to monitoring reports to be produced by ACER, article 84 is not clear to that regard, namely who’s responsible for: setting this European process for monitoring the implementation within the Member States and include recommendations in the defined areas, for conducting and publishing the European monitoring report, for deciding on recommendations to implement and monitoring such implementation.

Another aspect to highlight is that, Article 5 refers to national terms and conditions, which are also referred in most topics foreseen in the Network Code, with detailed rules linking to terms and conditions to be defined at national level. All national "Terms and Condition" foreseen across the NC should be included in the assessment foreseen in these articles for further harmonization, as the target should be to harmonize as much as possible the different products and processes, to foster a simpler access by DR and also more liquidity into markets, with the expected benefits from that.

Baselining methodologies should also be included. ENTSO-E and EU DSO Entity should conduct an analysis on a yearly basis, and present the results to ACER to assess whether it is feasible to converge to European baseline methodologies (even if just for some technical resources / services) or to a model of cross-border equivalence of baseline methodologies to be accepted by other SOs In that regard we propose:

• To merge the 2 articles to avoid overlaps.

• To better define the roles and responsibilities for assessment, monitoring reports, recommend on further harmonization, and approve implementation of further harmonization.

• Include the monitoring regarding the implementation and compliance of all national terms and conditions foreseen in this Network Code.

• Yearly report on implementation status to be published by ACER.

Your text proposal:

Article 86

93 Your views on Article 86:

Your comment on the article:

Exceptions for regulatory sandboxes are missing in the same manner derogations are established in Article 82.

Your text proposal:

Annex 1

95 Your views on Annex 1:

Your comment on the annex:

- Table 1.1:

- Line 10: Certificate of origin not needed for the purpose of this NC.

- Line 12: MTU resolution of 15 minutes is missing

- Line 16: Clarify the difference between FDT and FAT as defined in Implementation Frameworks under EB GL.

- Line 26: Replace cost of start for a generic reference to any other economic parameters apart from Activation price (field No. 25).

- Line 30: Clarity is needed on what a "dual data connection" is in this context.

Your text proposal:

Annex 2

96 Your views on Annex 2:

Your comment on the annex:

- Table 2.1, line 3 and Table 2.3, line 2 and Table 2.4, line 3: It must be used as a unique identifier at EU level, not at national one.

Your text proposal:

Eurelectric pursues in all its activities the application of the following sustainable development values:

Economic Development

• Growth, added-value, efficiency

Environmental Leadership

• Commitment, innovation, pro-activeness

Social Responsibility

• Transparency, ethics, accountability

eurelectric

Union of the Electricity Industry - Eurelectric aisbl Boulevard de l’Impératrice, 66 – bte 2 - 1000 Brussels, Belgium Tel: + 32 2 515 10 00 - VAT: BE 0462 679 112 • www.eurelectric.org EU Transparency Register number: 4271427696-87

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欧洲电力行业联盟-欧盟DSO实体和ENTSO-E关于网络法规草案的协商（英）-2023-WN11