The paper outlines key considerations that should be taken on board in the European network codes currently being drafted by ENTSO-E within the scope of the ACER Framework Guidelines on System Operation published in December 2011.

1. September 2012
Network Codes for System Operation
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A EURELECTRIC position paper
Published in cooperation with

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3. Network Codes for System Operation
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TF System Operation
David TREBOLLE (ES), Chair
Thomas AUNDRUP (DE); Peter AYMANNS (DE); Sevket BALCI (TR); Ellen DISKIN (IE); Olgan DURIEUX (BE);
Bruno GOUVERNEUR (BE); Mikael HAKANSSON (SE); Derek HYNES (IE); Marc LAGOUARDAT (FR); Peter
MICHALEK (DE); Daniel NORDGREN (SE); Pablo SIMON CABALLERO (ES); Giovanni VALTORTA (IT); David
VANGULICK (BE); Graeme VINCENT (GB); Tomas VITOR DORES (PT)
In cooperation with
Marc MALBRANCKE (BE), Gerald HEISE (DE); Gert JUECHTER (DE); Mike KAY (GB); Johan LUNDQVIST (SE);
Javier MECO (ES); Jesus PECO (ES); Axel SANDNER (DE); Matthias WIELAGE (DE), Jorge TELLO GUIJARRO (ES)
Contact:
Pavla MANDATOVA, Advisor Networks Unit
pmandatova@eurelectric.org

4. 4
Table of Contents
Executive Summary..........................................................................................................................5
Introduction .....................................................................................................................................6
General Principles ............................................................................................................................6
Role of DSOs in System Operation...................................................................................................7
System Operation Issues in Detail ...................................................................................................8
Annex I – Distribution voltage levels in Europe (power lines).......................................................11

5. 5
Executive Summary
The paper outlines key considerations that should be taken on board in the European network
codes currently being drafted by ENTSO-E within the scope of the ACER Framework Guidelines
on System Operation published in December 2011.
Those considerations can be summarised as follows:
 Close cooperation between TSOs in system operation is a precondition for successful
achievement of an Internal Electricity Market by 2014. These network codes should
define common binding minimum rules for network operators and users necessary for
maintaining overall system security and well-functioning cross-border trade. Consistency
among all the network codes drafted within the Third Package is necessary.
 The continuous decentralisation of power systems, large amounts of distributed
intermittent generation, active customers and the development of smart grids will
require redefining roles and responsibilities of both network operators and users. DSOs
are to take up the role of market facilitators and active distribution system managers
and contribute to the overall system security managed by the TSOs.
 One size does not fit all – varying needs and technical capabilities of the network and its
users must be taken into consideration. In order to achieve the highest cost-efficiency
for society, requirements implying investments in new technology should be subject to a
mandatory cost-benefit analysis. New systems should correspond to the needs and be
defined in a cost effective manner. Recovery of the related DSO cost has to be
recognized in the network codes.
 European DSOs differ widely with respect to the voltage levels they operate and the
degree of penetration of distributed generation. These two variables play a key role in
defining the DSO impact on overall system security and the cross-border issues for which
the EU network codes should be developed.
 As regards requirements for information exchange, congestion management, voltage
control, outage management and scheduling, requirements for distribution network
users and for DSOs should also be agreed with DSOs, who are responsible for the
security of supply and quality of service of their network. TSOs should not act on any
individual DER embedded in MV or LV networks.

6. 6
Introduction
As emerges from the Third Energy Package, network codes are meant to lay down European-wide
binding rules for electricity wholesale markets, system operation and grid connection. The objective of
this position paper is to outline principles that should be taken into account by network codes within the
scope of the ACER FG on System Operation1
in order to achieve a set of harmonised network operation
rules that provide the basis for TSOs to operate the system in a safe, secure, effective and efficient way
and successfully achieve a single Internal Electricity Market by 2014. The system integration of
renewable generation represents an important challenge in this respect. As a large share of intermittent
RES-E will be connected to distribution networks, the paper addresses in more detail the TSO-DSO
interface issues and the role of DSO in system operation.
General Principles
EURELECTRIC believes that the priorities of system operation codes should be the following:
 Common binding minimum rules
The EU network codes should define common binding minimum operational rules for network
operators and network users. Where the networks codes foresee definition of detailed rules at the
national level, a transparent process with participation of network users should be defined.
Unilateral decisions by TSOs and national regulatory authorities without any consultation of DSOs
and network users are not possible.
 Focus on overall system security and impact on cross-border issues
The network codes should be developed for cross-border issues and market integration issues (Art
8.7 of Regulation 714/2009).2
System operation codes might thus for example include detailed
requirements for information exchange amongst the TSOs on frequency management. Voltage
management on the other hand is, under normal operation, a typically local phenomenon.
 Cooperation among TSOs and progressive harmonisation of rules
Well-functioning cooperation between TSOs is key for maintaining overall system security.
National/regional TSO responsibilities should progressively develop towards a coordinated European
responsibility for security of supply. To this end, TSOs must work together and move forward to the
concept of ‘TSOs acting as one’. A greater exchange of information and coordination between TSOs
will improve the efficiency in operating the electricity system and therefore security of supply.
 Consistency with other network codes
Parallel drafting of numerous network codes should not jeopardise their overall consistency and
coherence. The content of all codes must fit together and should be based on a common vision of
the system as a whole.
http://www.acer.europa.eu/Electricity/FG_and_network_codes/Electricity%20FG%20%20network%20codes/FG-
2011-E-003%2002122011%20Electricity%20System%20Operation.pdf
2
For more on cross-border issues see EURELECTRIC DSO Position on Draft network code ‘Requirements for
Generators’, December 2011, www.eurelectric.org

7. 7
Role of DSOs in System Operation
Most new generation, in particular renewable and CHP, is or will be connected to distribution networks.
Similarly, most of the demand side flexibility will be developed in distribution networks. Installed
capacity of distributed generation already exceeds current demand in some countries and distribution
areas.
The apparent trend towards decentralisation of the power production and the appearance of new
applications implies an evolution of the roles and responsibilities of both network users and network
operators. Distribution areas need to be considered as systems and no longer as ‘just’ networks. With
this development, DSOs will act as market facilitators and will be in charge of active local distribution
system management to ensure security of supply and quality of service in the distribution networks.
Taking this evolution into account, the system operation codes must clarify TSO and DSO roles in system
operation, as also required by the ACER FG on System Operation (Chapter 2).
Diversity of DSOs
DSOs differ from country to country in terms of the voltage levels they operate and the penetration of
distributed generation. In addition, in some cases the network owner is different from the system
manager. An overview of voltage levels used in different European countries is provided in Annex I.
Varying DSO impact on cross-border performance
It is key to consider the DSOs impact on both cross-border system performance and overall security of
supply, which are both necessary for proper functioning of the internal electricity market.
DSOs operating HV networks are not only in charge of operational security in their networks but often
also of operational planning and scheduling tasks, similarly to TSOs. They are responsible not only for
quality of service, but also for security of supply, as shown in the figure above. They are important for
maintaining the overall security of supply that could have a direct impact on the functioning of electricity
markets and cross-border trade. Significant grid users3
connected to HV networks may have an effect on
cross-border issues. All TSO requirements for these users should be agreed with DSOs.
As regards DSOs operating MV and LV networks, their influence on overall system security and cross-
border issues depends on the amount of generation facilities connected to their networks. Simultaneous
operation of these generation units may affect overall system security.
3
According to ACER Framework Guidelines, Significant Grid User means the pre-existing grid users and new grid users which are
deemed significant on the basis of their impact on the cross border system performances via influence on the Control Area’s
security of supply including provision of ancillary services.

8. 8
A one-size-fits-all approach cannot be applied, due to both diversity of distribution systems and
differences in penetration of intermittent distributed generation. The network codes for system
operation should take this into account when defining DSO. New requirements in the codes deviating
from the existing ones should be subject to a mandatory quantitative cost-benefit analysis at national
level.
DSO as contributor to overall system security & renewables integrator
The system operation codes should serve as a firm basis for coordinated control actions. The TSOs are in
charge of overall system security and have the right to act whenever it is justified to ensure overall
security of supply.
DSOs will have to play a role of active system managers in order to integrate the rising share of
distributed generation while maintaining security of supply and quality of service in their networks.
When possible DSOs will procure under market-based conditions flexibility services and other services
from suppliers who have entered into contracts with customers with the objective to change under
commercial terms and via appropriate tools (smart meters, ripple control application, etc.) the off-take
of these contracted customers. The mechanism under which DSO procures and pays for these services
should be established and the regulation should ensure recognition of these costs and adequate
remuneration of DSOs.
DSOs should generally accomplish the established requirements at the TSO-DSO interface in order to
keep the system stable and provide the TSO with all relevant information. Any action on distribution
network users requested by the TSO should be agreed with the DSO(s) as system operators.
Any direct order from TSOs to distributed energy resources (DER) embedded in distribution networks
targeted to safeguard operation of the system will be executed by the DSO, not the TSO. TSOs should not
act on any individual DER embedded in MV or LV networks: individual DER do not influence transmission
networks or directly affect security of supply and cross-border issues.4
System Operation Issues in Detail
The following section details the abovementioned principles with respect to system requirements for:
 Information exchange
 Congestion management
 Voltage control
 Security Analysis & Outage Planning
Affected articles in each network code (NC) are mentioned where available (general principles can also
be applied to the Load Frequency Control and Reserves Code whose drafting was in the preliminary stage
at the time of publication of this paper).
4
Where national law already requires direct contracts in relation to system management between large distributed generation
connected to HV distribution networks and the TSO, this legislation – or the TSO with NRA approval should set the threshold for
such direct contracts to be allowed.

9. 9
Information exchange
(Articles referred to in the draft Operational Security NC: 16.4, 19-20, 24-27, 295
& in the draft
Operational Planning and Scheduling: 13, 30, 34)
1. TSOs should not have direct access to operational information of significant grid users connected
to distribution networks. Operational data or measures from DER embedded in distribution
networks should not be directly transmitted to the TSO. DSOs will collect the information and pass
on the necessary information to the TSO in appropriate and commonly agreed manner.
2. DSO(s) will provide the TSO with the operational information on significant grid users, both
generators and demand facilities. For users connected to MV and LV networks, DSO(s) should
provide only the necessary aggregated information. It is of utmost importance that DSOs have full
knowledge of these operational data to ensure security of supply and quality of service in their
networks.
3. There is not a one-size-fits-all solution for the level of information exchange. As noted above,
distribution networks are rather heterogeneous in terms of distributed generation density at
different voltage levels and grid equipment. Current technical capabilities of the network must be
taken into consideration and investments in new technology to cope with new requirements in the
codes deviating from the existing ones should be subject to a mandatory cost-benefit analysis at
national level. New systems should correspond to the needs and be defined in a cost effective
manner. Network codes should not prescribe installation of equipment for DSO network monitoring
to acquire information other than that directly related to the secure operation of the overall system.
If in future such monitoring is necessary to allow more embedded generation onto the network,
DSOs could undertake this activity and its availability to the TSO needs should be defined in national
legislation. Any additional DSO costs recovery should be recognized by the NRA.
4. DSOs must provide TSOs with Significant Grid Users’ information on active but not on reactive
power. TSOs need information about active power to facilitate system balancing. TSOs and DSOs
collaborate to maintain reactive energy exchange at a reasonable minimum in order to minimize
technical system losses. On the other hand, under normal operation voltage management is a local,
not a cross-border issue. DSOs should be in charge of voltage control in their networks (see below).
Information from distribution grid users about reactive power is generally not needed for cross-
border system analysis. The extent of distribution grid users’ data exchange between DSOs and TSOs
in relation to reactive power should be thus left to description in national legislation.
5. Relevant DSOs should be provided the necessary structural, operational planning & scheduling and
regal time data from TSOs, DER and neighbouring DSOs. Relevant DSOs need information about DG
forecast, schedules, planned outages, active dispatch & real-time to improve their visibility and to
assist with constraint management in their networks that could have adverse impact on the overall
system security.
Congestion management
(Articles referred to in the draft Operational Security NC: 11.5, 11.10, 12.11, 12.19)
1. DSOs are responsible for maintaining operational security in their networks. DSOs need to execute
instructions by the TSO, modified in line with capabilities and security of their networks. When
necessary, the DSO should generally accomplish the requirements at the TSO-DSO interface in
order to keep the system stable. Any activation of adjustment capacity by TSOs shall not be
detrimental to the operation of the distribution network. Every congestion management action on
users connected to distribution networks requested by TSOs will be agreed with DSOs. DSOs will
5
ENTSO-E Draft Network Code for Operational Security, version of 25 June 2012.

10. 10
execute it to DER. There will generally not be any direct contact between TSO and DSO customers,
save in the case where existing national law already allows or requires it for large generators or
demand facilities.
In emergency cases, TSO and DSO information relationships should be as direct as possible in order
to maintain/restore the security and quality of supply. For instance, the TSO will specify the amount
of load to be shed and the DSO will then decide what loads can be shed on the predefined basis. For
under-frequency tripping the TSO will decide the frequency bands and the amount of load to be shed
per band.
2. Congestion in relevant DSO networks may cause an incident that could spread up to transmission
level. Relevant DSOs should thus be able to modify distributed generation programmes if security
standards are not fulfilled and/or to minimise the risk of islanding operation. This will be applicable
as a measure of last resort, when the situation cannot be resolved by switching actions or modifying
other DSO setpoints. The network codes should thus include constraints on the relevant DSO
network that TSOs must recognise in scheduling significant grid users.
Voltage control
(Articles referred to in the draft to in the draft Operational Security NC: 9.4, 9.11)
1. Voltage control is essential to keep the voltage inside the contractual range for customers. However,
it is a typically non-cross border variable with a much smaller range of influence than frequency
under normal operation state. Voltage influence ‘fades’ across long distance feeders and through
different voltage network levels, and there is no European‐wide common voltage mode. The
criticality of a given facility’s contribution to voltage stability is highly dependent on the local
network conditions and local system management. In addition, voltage optimisation requires a
system approach that would enable to minimise the overall cost (investment & losses) while
maximising efficiency. That means that any order given by the TSO in terms of reactive power
exchange at the TSO-DSO connection point will not cause an increase of the technical system losses.
2. The TSO should not have any responsibility for voltage control in the DSO network provided DSOs
deliver voltage within an agreed bandwidth at the transmission-distribution interconnection points.
Any voltage requirement specified by the TSO will be applied at the TSO-DSO connection point. Any
order from the TSO applicable to significant users embedded in DSO networks will be agreed with
the DSO and executed by the DSO.
To prevent voltage instability in their networks, Relevant DSOs should be allowed to settle down
voltage, reactive power or power factor setpoints to significant grid users connected to distribution
networks in order to maintain voltage values within the security standards and/or minimise reactive
power flows, and therefore, the overall system cost (investment & losses). TSOs will deliver a safe
voltage margin, agreed with DSOs (not higher than +10%), at the TSO-DSO connection point.
Security Analysis & Outage Planning
(Articles referred to in the draft Operational Planning & Scheduling code: 11, 17-226
)
1. Coordination in HV outage management is a key issue to maintain overall security of supply.
Relevant DSOs will need outage management & scheduling information from the TSO, relevant
neighbouring DSOs and significant users.
2. Similarly to above, TSOs should not order or act on any DER embedded in MV or LV networks for
outage management purposes because these grid users do not influence individually transmission
6
ENTSO-E Draft Network Code for Operational Planning and Scheduling, version of 18 July 2012.

11. 11
networks and are not related to security of supply and cross-border issues. The TSO should receive
aggregated data from the DSO. Coordination required by the ACER FG should not result in a
confusion of responsibilities: TSOs should not be in charge of operational control of parts of the
distribution network or its connected users.
Annex I – Distribution voltage levels in Europe (power lines)
* According to federal legislation. Regional legislation specifies that 30-70 kV (included) are operated by
TSO.
** The network is owned by cities, which delegate operation to DSOs.
*** DSO owns the 150 kV or 132 kV substations including the HV lines circuit breakers which are
operated by DSO control centres on TSO request.

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