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Adapting to the Changes Enforced by EU’s
Network Codes for Electricity
The Consequences for an Electricity Company from a Distribution
System Operator’s Perspective
Karolina Falk & Joel Forsberg
June 2014
Master’s Thesis LIU-IEI-TEK-A–14/01852–SE
Department of Management and Engineering (IEI)
Division of Energy Systems
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i
Abstract
To reach EU’s climate and energy target an integrated electricity market is considered to be required
(Klessmann, et al., 2011; Boie, et al., 2014; Becker, et al., 2013). As a result the European Commission
decided to form a set of rules, named the Network Codes, to create a single European market (ENTSO-E,
2013b). The Network Codes will affect Distribution- and Transmission System Operators, grid users and
production units as well as all the other actors on the electricity market (Eurelectric, n.d.a). Concerns
regarding what the Network Codes’ actual consequences are have been expressed within the line of
business (Swedish Energy, 2013a). Therefore the purpose of this master’s thesis was to determine and
furthermore illustrate the consequences the Network Codes will have, in current version, for a Swedish
non-transmission system connected electricity company and determine what actions need to be taken.
The purpose has been addressed by conducting interviews, document studies and by utilizing a change
management model, the Intervention Strategy Model, introduced by Paton & McCalman (2000). The
structured approach that is the nature of the model was used when determining the consequences the
Network Codes enforce and what actions a non-transmission system connected electricity company has to
take to cope with them. To further facilitate the determination of these actions this study was conducted
on a non-transmission system connected electricity company, in this thesis named Electricity Company A.
The investigation of the concerns expressed within the line of business illustrated that the concerns were
diverse but a majority of them might be incorporated into either of the following groups, simulation
models, demand side aggregator and information handling. Out of these groups information handling
was by far the area of greatest concern with issues primarily connected to the Distribution System
Operator. Consequently this thesis focused on the Distribution System Operator’s perspective.
The analysis of the area of greatest concern, presented in two flow charts, clearly showed the increased
amount of communication enforced by the Network Codes. This increased information handling results in
numerous possible organisational consequences for the Distribution System Operator, for example
might new systems be required and some existing systems be used with or without adaption.
Furthermore, the extra workload could possibly be handled by the existing personnel, in some cases after
complementary education, but it might also require new personnel. Finally the Network Codes open up for
the possibility for the Distribution System Operator to define certain details which may be conducted
individually or in cooperation with other Distribution System Operators. Which of these possible
consequences that will affect a specific company is, however, dependent on its preconditions.
The study on Electricity Company A reveals that the numerous actions required to handle the new
communication were not as significant as the line of business might have feared. For Electricity Company
A, primarily a new system is needed to handle the real-time values and some of the existing systems need
to be updated. Additionally the combined extra work load might require extra personnel for Electricity
Company A even though the individual work assignments are fairly small. The actions required should be
fairly similar for companies of approximately equal size but might be more extensive for smaller nontransmission system connected electricity companies. All companies need, however, to conduct an
individual analysis to determine which specific actions are required for them.
The conclusions of this thesis aspired, and partly succeeded, to be generalizable on a European level.
One example of this is the usage of the Intervention Strategy Model which proved applicable for determining
which specific actions are required for all European electricity companies. Furthermore the concerns
presented and the possible consequences of the increased information handling found, are generalizable
but not complete for all European electricity companies. This thesis focused on one part of the complex
Network Codes’ consequences and consequently further research is needed to fully understand the
consequences for the electricity business in total.
ii
iii
Acknowledgement
This is a master’s thesis in Energy and Environmental Engineering conducted as the final project at the
five year engineering program Energy – Environment – Management at Linköping University. The
intention of this master’s thesis is to bring clarity to a complex and highly debated subject in the industry
where concrete information is absent. We would like to express our gratitude to the people without
whose assistance the purpose could not have been achieved.
Jenny Ivner, our tutor at Linköping University, for good advice and valuable comments regarding the
structure of the thesis and how to reach the appropriate academic level. Christian Cleber, Tekniska verken
i Linköping Nät AB, for his valuable tutorship, for sharing his knowledge and for all the time and effort
he has contributed with. Johan Lundqvist, Swedish Energy, for his accessibility for consultation regarding
specific parts of the Network Codes and his valuable input. All interviewees who took the time to explain
the functions of an electricity company and present their views on the Network Codes.
We would also like to express a special thanks to Cecilia Mårtensson & Martin Skoglund, for their proofreading and valuable comments and remarks on the thesis.
Finally if you have any questions on the subject or are interested in getting an explanatory presentation
do not hesitate to contact us.
Linköping in June 2014
Karolina Falk & Joel Forsberg
[email protected] & [email protected]
iv
v
Table of Contents
1
2
3
4
5
6
7
vi
Introduction.................................................................................................................. 1
1.1
Aim ............................................................................................................................................ 2
1.2
Limitations................................................................................................................................ 2
1.3
Structure of report ................................................................................................................... 2
Background ................................................................................................................. 5
2.1
The content of the Network Codes ..................................................................................... 5
2.2
Current conditions in Sweden dealt with by the Network Codes .................................... 8
2.3
A non-transmission system connected electricity company in Sweden ........................10
Change management theory ...................................................................................... 11
3.1
Forces of change ...................................................................................................................11
3.2
The Intervention Strategy Model ........................................................................................11
3.3
Criticism against the use of solution models .....................................................................14
Method ....................................................................................................................... 15
4.1
Problem and solution methodology scoping ....................................................................15
4.2
Method used for answering the research questions .........................................................17
4.3
Discussion and Conclusion..................................................................................................26
An overview of Electricity Company A and its’ information handling ......................27
5.1
Description of Electricity Company A’s distribution network .......................................27
5.2
Electricity production ...........................................................................................................27
5.3
The Electricity retailing for EC-A.......................................................................................29
5.4
The handling of information ...............................................................................................29
The area of greatest concern ......................................................................................35
6.1
The quantity and size of simulation models ......................................................................35
6.2
The impacts of the demand side response aggregator .....................................................35
6.3
The administrative burden due to increased information handling ...............................36
Possible organisational consequences .......................................................................37
8
9
7.1
The information flows required due to the Network Codes ..........................................37
7.2
Formulation of objectives and generation of possible solutions for handling information
..................................................................................................................................................40
Actions required to deal with the information handling ...........................................43
8.1
Actions required in the implementation phase .................................................................45
8.2
Actions required in the ongoing phase ..............................................................................49
8.3
Actions of general nature that facilitate the transition .....................................................50
Discussion ..................................................................................................................53
9.1
The influence of the method ...............................................................................................53
9.2
The development potential of the ISM ..............................................................................54
9.3
The thesis generalizability ....................................................................................................55
10
Conclusion ..................................................................................................................57
11
Reference List.............................................................................................................59
vii
Figures, Tables and Appendix
Figure 1 Report structure
Figure 2 Network Code development
Figure 3 Network Codes in their different groups
Figure 4 Intervention Strategy Model
Figure 5 Method
Figure 6 EC-A flow chart
Figure 7 Production units flow chart
Figure 8 Demand units flow chart
Figure 9 Actions grouped in implementation and ongoing phase
3
6
7
12
18
30
38
39
44
Table 1 Associations consulted in identification of concerns process
Table 2 Interviewees and there postions in different companies
Table 3 Which version of the Network Codes have been analysed
Table 4 Interviewees and their positions for information gathering about EC-A
Table 5 Interviewees and their poistion for the evaluation phase
Table 6 EC-A’s production units and the productions in the grid of EC-A-Grid
Table 7 Analysis steps for possible solutions for the first objective
Table 8 Analysis steps for possible solutions for the eighth objective
Table 9 Chosen generated solutions for the first objective
Table 10 Chosen generated solutions for the eighth objective
19
20
21
24
25
28
41
41
43
44
Appendix 1 – Concerns
Appendix 2 – Information flows
Appendix 3 – Objectives, measures and solution generation
viii
ix
Glossary
ACER – Agency for the Cooperation of Energy Regulators (Participates in the development process of the
codes by translating the vision of each code to Framework Guidelines.) (ENTSO-E, 2013b) is the NRAs
of the EU
BRP – Balance Responsible Party (A market-related entity or its chosen representative responsible for its
imbalances.) (ENTSO-E, 2013c)
CACM – Capacity Allocation and Congestion Management (A market code that covers the cross border
electricity trading on the day-ahead and intraday market, methods for capacity calculations and bidding
zones among others.) (ENTSO-E, 2014a)
CHP – Combined Heat and Power (A technique where a plant produces both useful heat and power)
DCC – Demand Connection Code (A connection code that sets requirements for different demand facilities
and connections and introduces the concept of Demand Side Response (DSR) (ENTSO-E, 2014a)
DMS – Distribution Management System (A system that can handle the switching state of the electricity
distribution system among others and is connected to the NIS) (Tekla, 2014b).
DSO – Distribution System Operator (Operates the distribution networks and transports the electricity to
the end users.) (Inderberg, 2012)
DSR – Demand Side Response (“…demand offered for the purposes of, but not restricted to, providing
Active or Reactive Power management, Voltage and Frequency regulation and System Reserve.”) .”)
(ENTSO-E, 2012, p.11)
EB – Electricity Balancing (A market code that covers the rules for the different balancing services on the
market to ensure that supply always meets demand at the lowest possible cost.) (ENTSO-E, 2013d)
EC-A – Electricity Company A (The parts of the energy business group, that deals with electricity, are
considered Electricity Company A in this thesis. Electricity Company A has the electricity production,
electricity grid and electricity retailing.)
EC-A-Grid – Electricity Company A Grid (A subsidiary to EC-A that owns the distribution grids.) (EC-A,
2013a)
EC-A-Retail – Electricity Company A Retail (A subsidiary to EC-A that handles the electricity retailing,
including delivery of electricity to both private- and business customers. (EC-A, 2013a)
EC-B – Electricity Company B (An electricity company that is located in the south of Sweden and has
electricity grid, production and retailing within their ownership.) (EC-B, n.d)
EC-C – Electricity Company C (An electricity company that is located in the south of Sweden and has
electricity grid, production and retailing within their ownership.) (EC-B, n.d)
EC-D – Electricity Company D (The electricity company that owns the regional grid that EC-A-Grid is
connected to.) (NOC Engineer, 2014a).
EC-E – Electricity Company E (The electricity company that owns a distribution grid connected to EC-AGrid’s network.) (Customer Relations, 2014a).
x
Ei – Energimarknadsinspektionen, Swedish Energy Market Inspectorate (Is the Swedish NRA responsible for
regulating the energy market.) (Swedish Smartgrid, n.d.)
ENTSO-E – European Network of Transmission System Operators for Electricity (Are responsible for drafting
the Network Codes.) (ENTSO-E, 2013b)
EON – Energisation Operational Notification (A notification issued by the DSO to the PGM “…prior to
energisation of its internal Network. An EON entitles the…” the PGM “…to energise its internal
Network by using the grid connection.”) (ENTSO-E, 2013e, p.8)
EU – European Union
FCA – Forward Capacity Allocation (A market code closely related to the code CACM but dealing with
more long term issues considering the trade of cross-border capacity prior to day-ahead (ENTSO-E,
2014a).
FON – Final Operational Notification (A notification issued by the DSO to the PGM that entitles the PGM
to operate the PGM “…by using the grid connection because compliance with the technical design and
operational criteria has been demonstrated as referred to in this Network Code.”) (ENTSO-E, 2013e,
p.9)
GEODE – (An association for energy distribution companies that “...defends the interest of the local
distribution in front of energy authorities on national and international level...” (GEODE, 2013b)
including the drafting of Network Codes) (GEODE, 2013c).
Higher DSO – Distribution System Operator working on the higher voltage level.
ION – Interim Operational Notification (A notification issued by the DSO to the PGM confirming that the
PGM “…is entitled to operate the Power Generating Module by using the grid connection for a limited
period of time and to undertake compliance tests to meet the technical design and operational criteria of
this Network Code.”) (ENTSO-E, 2013e, p.10)
ISM – Intervention Strategy Model (A solution methodology with a systems approach (Paton & McCalman,
2000). In this thesis the ISM provides the foundation for the method.)
LFCR – Load Frequency Control and Reserve (An operational code that deals with the need of reserves and
sets rules on how these are to be located and what qualifications they have to meet) (ENTSO-E, 2013g).
Lower DSO – Distribution System Operator working on the lower voltage level.
NIS – Network Information System (Is a system that among others can be integrated to a GIS-functions and
have functions for documentation handling) (Tekla, 2014a).
NOC – Network Operation Centre A centre responsible for the daily monitoring, control and operation of
a network.
NRA – National Regulatory Authority (Is responsible for regulating the energy market within each country.
Energimarknadsinspektionen, or in English Swedish Energy Market Inspectorate, is the Swedish NRA) (Swedish
Smartgrid, n.d.)
OPS – Operational Planning and Scheduling (An operational code that deals with how the TSOs can
communicate and coordinate their planning and scheduling with each other in order to coordinate the
electricity production.) (ENTSO-E, 2013f)
xi
OS – Operational Security (An operational code that includes rules to ensure the security of supply in the
pan-European electricity network.) (ENTSO-E, 2013g)
PGM – Power Generating Module (Is a module of one or more electricity generators. The PGMs are
categorised into new and existing PGMs of Type A, B, C, D depending on their size and which voltage
level they are connected to.) (ENTSO-E, 2013e)
Relevant Asset – A Demand facility or a PGM “…which participate in the Outage Coordination
Process as its Availability Status influences cross-border Operational Security.” (ENTSO-E, 2013h, p.10)
RfG – Requirements for Generators (A connection code that regulates the behaviour of all new generators,
or the ones deemed significant by the TSO, that want to connect to the grid and introduces the
categorising concept for PGMs that is used in all of the Network Codes. (ENTSO-E, 2013g)
RPU – Reserve Providing Unit (“…an aggregation of Power Generating Modules, Demand Unit and/or
Reserve Providing Units connected to more than one Connection Point fulfilling the requirements for
FCR, FRR or RR.”) .”) (ENTSO-E, 2013i, p.12)
RQ1, 2, 3 – Research Question 1-3 (The aim is broken down into research question which are presented in
section 1.1)
SGU – Significant Grid User (Existing and new PGM or Demand facility “…deemed by the TSO as
significant because of their impact on the Transmission System in terms of the security of supply
including provision of Ancillary Services.” (ENTSO-E, 2013j, p.13)
SvK – Svenska Kraftnät or in English the Swedish National Grid (The Swedish TSO.) (Inderberg, 2012).
TSO – Transmission System Operator (Operates the national grid or the transmission grid. The Swedish
TSO is Svenska Kraftnät, or in English the Swedish National Grid) (Inderberg, 2012).
xii
xiii
1 Introduction
The European Union (EU) started in 1999 to progressively implement an internal energy market for electricity in
Europe (European Parliament; Council of the EU, 2009). Years later EU agreed on the climate and energy
targets for 2020 which made the need for a framework regarding the common electricity market even bigger
(ENTSO-E, 2013k). Therefore the European Commission decided in 2007 that a set of rules were to be
introduced as a part of completing an internal energy market within the union (ENTSO-E, 2013b).
The importance of integrating the electricity market within the union to be able to reach the
2020-targets is highlighted by multiple researchers. Klessmann et.al. (2011) point out that the
reduction of administrative and grid access barriers and the upgrading of the power grid is of
special importance. Boie et.al. (2013) point out that financing issues, grid development and
management need to be focused on to be able to reach the targeted amount of renewable energy
sources in the sector. They also highlight the importance of the harmonisation of the technical
network standards, the participation of the demand side and the amount of distributed
generators. Furthermore Becker et.al (2013) draw attention to the fact that an increase of the net
transfer capacity between countries will lead to substantial less need for backup electricity
production. These papers combined provide a clear indication of the significance of an internal
energy market.
After deciding that rules were needed the European Commission gave the Agency for the Cooperation of
Energy Regulators (ACER) the assignment to describe the vision of what each of the rules was to
consider. This resulted in the Framework Guidelines which were handed over to the European
Network of Transmission System Operators for Electricity (ENTSO-E) with the task to draft the Network
Codes1. To ensure that the codes follow the guidelines ACER assess the drafts when ENTSO-E is
done before they are handed over to the European Commission for the comitology procedure.
During this procedure the Network Codes will get agreed upon by the member states before the
Network Codes will enter into force in all member states. (ENTSO-E, 2013b)
The codes cover three key areas; grid connection, grid operation and cross-border electricity
markets (ENTSO-E, 2013k). The grid connection codes set out the requirements for actors who
wants to connect to the transmission grids (ENTSO-E, 2013l), the operational codes include
regulations on how to monitor that the electricity production meets the demand and that the
system can handle the flows (ENTSO-E, 2013m), and the market codes set out rules for crossborder trading of both electricity and capacity (ENTSO-E, 2013n). All the rules aim to “Promote
increased trading across Europe: Make it easier for companies to enter the market; Enhance
cooperation and security of supply; and Allow more renewable generation to be integrated into
the energy mix.” (ENTSO-E, 2013b). Currently ENTSO-E is working on and developing nine
codes that can be categorised into these three areas. Each of the codes are in different stages of
the development procedure with some already being in the comitology process and some have
recently been handed over to ACER (ENTSO-E, 2014b). Once the codes are adopted by the
European Commission they become EU regulation and are therefore a directly binding legislation in
all member states (GEODE, 2013a).
The Network Codes will affect Transmission System Operators (TSOs), Distribution System
Operators (DSOs), regulators, manufacturers and all significant market players, like big generators
There are Network Codes concerning both gas and electricity (ENTSO-E, 2013k). In this thesis only the codes for
electricity will be included and when using the word Network Code, it always refers to the electricity codes.
1
1
and loads (Eurelectric, n.d.a). At the moment it is hard to estimate exactly how the actors will be
affected, since the codes are currently in the development process (Swedish Energy, 2013a). This
has raised concerns from Swedish Energy , the trade industry for the Swedish electricity companies,
and its members on what measures they will have to take to adapt to them anyway. These 169
members represent electricity producers, grid owners as well as retailing companies (Swedish
Energy, 2014). Consequently the whole energy industry stands before presumably large and
unknown challenges and the presence of an understandable summary focusing on the practical
consequences would therefore be beneficial. Furthermore it would be truly useful to investigate
these consequences proactively since the Network Codes are approaching the final stages.
1.1
Aim
The aim of this master thesis is to determine how a Swedish electricity company will be affected
when the Network Codes enter into force. It will identify the concerns raised within the line of
business and further investigate the area of greatest concern for an electricity company.
Furthermore the investigation will determine which actions that need be taken to comply with
the rules related to the area of greatest concern. The aim is concretised and broken down into the
following research questions:
1. Which area within the Network Codes is of the greatest concern?
2. Which organisational consequences could this have for a Swedish electricity company?
3. Which actions will consequently be required by a Swedish electricity company?
1.2 Limitations
This thesis will focus on the consequences for a Swedish non-transmission system connected
electricity company. In this thesis an electricity company is a company that possess one or more
of the following functions: electricity production, electricity distribution or electricity retailing.
The focus will be companies that by themselves or through a subsidiary own a distribution grid
since that is an efficient way of relating the companies to each other.
The extent of the issue is investigated qualitatively and based on the drafts of the Network Codes
available prior to 2014-03-31. This thesis will look into the nine Network Codes that are prioritised
to be implemented in 2014 except for the Network Code on High Voltage Direct Current
Connections since the effect of this code on non-transmission system connected companies are
limited. Following the initial survey regarding the area of greatest concern and the following flow
charts the focus for the rest of the thesis will be on this area for one of the actors.
1.3 Structure of report
This section describes the structure of the report and the dependencies between the different
chapters and sections which are clearly illustrated in Figure 1. Firstly the background to the report
is presented by explaining why the Network Codes are needed in EU and what the concept and
content of them are. The Swedish electricity system and the company to be used as a reference in
this thesis are also introduced in the background. In the following chapter, about change
management theory, the reasons for making changes are explained and a model to be used when
facing changes is introduced, the Intervention Strategy Model. These first two chapters combined lay
the foundation for the method chapter. In the method chapter the method for answering the
different research questions and how the Intervention Strategy Model has been used in this thesis are
presented.
The method leads to the chapter about Electricity Company A. Here the aspects of Electricity
Company A, that are required by the third research question, are presented, including the
2
company’s structure, number of production units and information handling procedures.
Subsequently the analysis chapters are presented with the answers to the different research
questions. The answer to the first question supplies the foundation for the second one and so on
and they are therefore presented in this order. Consequently the greatest area of concern is
presented first followed by the possible organisational consequences for a Swedish electricity
company. In the last analysis chapter the actions required by Electricity Company A are presented
and how these are applicable for other non-transmission system connected electricity companies.
The final part of the thesis is the discussion part. This part starts with the investigation if the
answers are generalizable outside of Sweden and for transmission system connected companies.
Subsequently some improvement suggestions for the Intervention Strategy Model are presented. The
thesis ends by presenting the most important conclusions and answers to the research questions
and the need for further research in the Conclusion chapter.
Background
Change management theory
Method
RQ1
RQ2
RQ3
Overview of Electricity
Company A
Analysis
The area of
greatest concern
(RQ1)
Possible
organisational
consequences
(RQ2)
Actions needed to
be taken (RQ3)
Discussion
Generalizability
Development potential of ISM
Conclusion
Figure 1 This figure illustrates the structure of the report and how the different chapters are linked to each other.
3
4
2 Background
This chapter presents the basic background to the problem and provides the foundation for both Chapter 3
“Change management theory” and Chapter 4 “Method”. It starts by explaining the background to why the
Network Codes are needed in the EU. Subsequently a brief introduction to the concept and content of the Network
Codes is presented (section 2.1). After that the related areas within the Swedish electricity system is presented
(section 2.2). Finally the definition of a non-transmission system connected electricity company and the company
that will be used in this thesis is introduced (section 2.3).
The energy market in Europe is diversified where most of the countries are self-sufficient and
have their own electricity regulations (ENTSO-E, 2013b). This can clearly be illustrated by the
fact that 11 of EUs 27 countries have non-regulated prices of electricity (ACER, 2012). Even price
to consumers on the different non-regulated markets vary immensely, both pre- and post-tax. For
example the price in Germany is twice as high as it is in Latvia. These price differences can
somewhat be explained by the different generation mixes. Some of the European countries are
connected by cross-border transmission lines whose economic benefits are presented in a study
by ACER (2012). Some of these connected countries also form larger coupled markets (Newbery,
et al., 2013). The market liquidity on these European electricity markets is increasing over time
but is still far from perfect (ACER, 2012).
Research in the field of energy markets indicates the significance of an integrated European
energy market when trying to reach the 2020-target. The importance of decreasing the barriers on
the market is highlighted by Klessmann et.al. (2011), and Boie et.al. (2013) specify the
significance of harmonising the technical standards in Europe. Furthermore Becker et.al (2013)
describe the positive effects from increased transfer capacity between different countries. To be
able to deal with these issues in a systematic manner a new set of rules was established by the
European Commission together with other stakeholders (ENTSO-E, 2013b). This set of rules is
named the Network Codes.
2.1 The content of the Network Codes
The Network Codes are a set of rights and obligations that applies for all parties working within the
electricity sector (ENTSO-E, 2013b). They are based on the third energy package which was
designed by the European Commission to create an internal market for electricity. The European
Commission then gave ACER the mission to develop a vision for what needs to be changed in the
European electricity sector (ENTSO-E, 2013b). This resulted in the Framework Guidelines.
ENTSO-E then started to draft the Network Codes based on these guidelines and a priority list
containing nine different Network Codes, which are presented later in this chapter (ENTSO-E,
2014c). The drafting process generally takes up to 12 months for every code during which
stakeholders have the possibility to influence the development (ENTSO-E, 2013b). Subsequently
ACER controls the draft’s conformity with the corresponding Framework Guideline and submits it
to the European Commission. Before the Network Code enters into force the European Commission
takes the code through a comitology procedure. An overview of the development process and
the state of the individual Network Code is presented in Figure 2. The implementation time, before
the Network Code fully applies, varies greatly (ENTSO-E, 2013o). The code on Operation
Planning and Scheduling for example is fully implemented already after 18 months while for the
Electricity Balancing code the implementation will be phased over the course of six years.
5
Figure 2 This figure illustrates the Network Code development and the time frame. The forward-looking dates are
provisional until confirmed (ENTSO-E, 2013o). It can be seen in the figure that the various Network Codes are in
different parts of the development process.
The overall aim of the Network Codes is to be a coherent set of rules in the electricity area where a
lot of neighbouring countries did not have matching rules before. More specifically the Network
Codes are supposed to increase trading, make it easier to enter the market, enhance cooperation,
communication and security of supply and safely include more renewable energy sources in the
system. The codes are closely related but can be divided into three groups with different focus
areas namely the market codes, the connection codes and the operational codes. In Figure 3 the
prioritised Network Codes included in each of these groups are presented. (ENTSO-E, 2013b)
6
Figure 3 This figure shows the Network Codes in their different groups in the order they are prioritised as mentioned
earlier this section.
2.1.1 The market codes
The market codes cover the trade of power in different timescales, including the balancing
power, to ensure a single European market for electricity (ENTSO-E, 2014c).



The code on Capacity Allocation and Congestion Management (CACM) covers the cross border
electricity trading on the day-ahead and intraday market, methods for capacity
calculations and bidding zones among others (ENTSO-E, 2014c). It aims to increase
competition, enhance stability, reduce risks and provide more choices for consumers
when creating the largest electricity market in the world (ENTSO-E, 2013p).
The code on Forward Capacity Allocation (FCA) is closely related to the first one but it is
dealing with more long term issues considering the trade of cross-border capacity prior to
day-ahead (ENTSO-E, 2014c).
The third market code, Electricity Balancing (EB) covers the rules for the different
balancing services on the market to ensure that supply always meets demand at the lowest
possible cost (ENTSO-E, 2013d). It makes sure that TSOs have access to sufficient
balancing services by having the ability to reserve space on transmission lines and by
either decreasing or increasing the production or consumption. When this balancing is
carried out on a European level the renewable energy sources have increased possibility
to back each other up.
2.1.2 The connection codes
The connection codes involve the connection of different kinds of equipment to the grid
(ENTSO-E, 2014c).

7
The code on Requirements for Generators (RfG) regulates the behaviour of all new
generators, and the existing ones deemed significant by the TSO, that want to connect to
the grid. Furthermore it introduces the categorising concept for Power Generating
Modules (PGMs) that is used in all of the Network Codes (ENTSO-E, 2013g). The PGMs
are classified as type A, B, C or D according to the installed capacity per connection point
to the grid. In the Nordic region all PGMs larger than 30 MW or connected at a voltage
level higher than 110 kV is type D. Furthermore PGMs larger than 15 MW are type C,
larger than 1.5 MW are type B and larger than 800 W are type A. These rules aim to ensure


that the grid remains stable when connecting new generators also with a larger amount of
intermittency in the net (ENTSO-E, 2013q).
The Demand Connection Code (DCC) sets requirements for different demand facilities and
connections and introduces the concept of Demand Side Response (DSR) and the term
aggregator. (ENTSO-E, 2014c). DSR can be offered by a demand unit for the purpose of
providing active or reactive power management, voltage and frequency regulation and
system reserve (ENTSO-E, 2012). An aggregator is in charge of the operation of multiple
demand units (ENTSO-E, 2012).
Finally the High Voltage Direct Current Code regulates the High voltage direct current
connections and offshore generators connected with DC cables (ENTSO-E, 2014c).
2.1.3 The operational codes
The operational codes cover security of supply and the operation, planning and scheduling of the
grid (ENTSO-E, 2013g).



The code on Operational Security (OS) includes rules to ensure the security of supply in
the pan-European electricity network (ENTSO-E, 2013g). Due to the increasing
importance of the micro production of electricity this code does not only cover the
cooperation between TSOs but also the cooperative obligations between DSO and TSO
(ENTSO-E, 2013r).
The code on Operational Planning and Scheduling (OPS) deals with how the TSOs can
communicate and coordinate their planning and scheduling with each other in order to
coordinate the electricity production (ENTSO-E, 2013f). It also explains the
responsibilities for the different market participants.
Finally the code on Load Frequency Control and Reserve (LFCR) deals with the need for
different kind of reserves and sets rules on how these are to be located and what
qualifications they have to meet (ENTSO-E, 2013g).
2.2 Current conditions in Sweden dealt with by the Network Codes
The Swedish electricity grid can be divided into three different categories; the national grid, the
regional grids and the distribution grids (Inderberg, 2012). The distribution grids are operated by
local network operators commonly referred to as DSOs and they transport the electricity to the
end user. Today there are approximately 170 DSOs in Sweden (Swedish Energy, 2012a). The
regional grids transport the electricity between the transmission system and the distribution grids
and are mainly operated by the three largest DSOs. The national grid or the transmission system
is operated by the TSO, in Sweden that is Svenska Kraftnät, or in English the Swedish National Grid
(Inderberg, 2012).
Since SvK is the TSO in Sweden they control and rule the whole Swedish electricity system and
are responsible for maintaining the security of supply (Nord Pool Spot, n.d.a). This means that
they are responsible for ensuring that the electricity arrives to the end users and that the
frequency remains stable at 50 Hz. To be able to keep the grid operating at this frequency SvK
has regulations regarding the performance of electricity production facilities (Swedish National
Grid , 2005). These regulations include how long and with how large power reduction a facility
shall remain connected to the grid at certain frequencies and voltage levels. Which rules that
apply for a certain production unit is determined by the energy source and the size of the
generator. The generator’s size is related to 1.5 MW, 25 MW and 50 MW or 100 MW depending on
the energy source. Consequently all power plants larger than 25 MW shall be able to supply SvK
with information regarding voltage level, active and reactive power, operational status and
8
regulation capacity in real-time. Furthermore shall any changes regarding the technical data of the
production facility be communicated to SvK.
Another possibility for SvK to ensure that the frequency remains in the close proximity of 50 Hz
is to disconnect the users. There are two types of demand disconnection, manual and automatic
disconnection. According to the Swedish law every DSO should be prepared to perform a manual
disconnection in the area, and to the extent, ordered by SvK within 15 minutes. Furthermore the
DSO should consult the affected municipalities when determining in which order different users
are to be disconnected, in order to respect the functions with great importance to the society.
The automatic disconnection is done in steps when the frequency drops below certain levels.
Only transmission system connected DSOs are obliged to have this equipment according to the
Swedish law. (Swedish National Grid , 2012a)
Since the operation of the distribution grids is a natural monopoly the DSOs’ revenues are
regulated by the Swedish NRA, Energimarknadsinspektionen or in English the Swedish Energy Market
Inspectorate (Ei). Therefore a revenue cap for four years in advance is introduced. The current
revenue cap contains the years 2012-2015. Before Ei determines the actual revenue cap each DSO
provides a reasonable estimation. Ei then makes a decision based on the estimation combined
with historical values and the forecasted development of the grid and the costs. If the DSO is not
satisfied with its revenue cap there is a possibility to appeal the decision. (Swedish Energy, 2012b)
2.2.1 The Swedish electricity market
In Sweden electricity can be traded in three different time frames which are handled by Nord Pool
Spot (Nord Pool Spot, n.d.a). These three markets are called the intraday- (Nord Pool Spot,
n.d.b), the day-ahead- and the financial-market (Nord Pool Spot, n.d.a). The Nordic intraday
market is called Elbas which takes place after the day-ahead market has closed until one hour
before delivery (Nord Pool Spot, n.d.b). On this market players buy and sell electricity in realtime for a specific hour in order to compensate for incorrect prognoses. The financial market on
the other hand is for long-term contracts and provides possibilities for price hedging and risk
management (Nord Pool Spot, n.d.a). Here different actors can agree upon contracts for volumes
and prices for a specific month in the future in order to ensure cost-effective delivery.
The Nordic day-ahead market is called Elspot and takes care of both congestion management and
electricity trading (Nord Pool Spot, n.d.a). Elspot is called a double auction market since both
buyers and sellers submit their bids simultaneously the day before delivery. The orders are then
aggregated on a North-Western Europe level to one supply- and one demand-curve, for every
individual hour. The intersection between the two curves determines the price for different areas
through a complex algorithm. (EPEX Spot, et al., 2013) Once the price is set, the different TSOs
in every country have a few minutes to validate the price until it is confirmed and communicated
to the market participants (Nord Pool Spot & N2EX, 2014).
When the hour of operation has passed a settlement is done where the actual consumption and
production is determined for every Balance Responsible Party (BRP) (Nord Pool Spot, n.d.a).
Any mismatches between bought or sold electricity and actual outcome for the BRPs are
compensated by SvK buying or selling balance power on the BRP’s expense. Balance power
should not be confused with the power reserve where producers provide extra power or
consumers provide less consumption (Swedish National Grid , 2012b). In the power reserve
consumers and producers tell SvK how much and to what cost they can regulate their power.
Then, in case of power shortage, SvK has the means to solve the situation using the cheapest
power reserves.
9
2.3 A non-transmission system connected electricity company in Sweden
As mentioned earlier there are about 170 DSOs in Sweden (Swedish Energy, 2012a). Only eight of
these companies are connected to the transmission system (Carlstrand, 2014). One of the
remaining companies is the subsidiary electricity distribution company within an Energy business
group. This Energy business group is owned by a municipality and manages services within the
areas water, waste disposal, electricity, electricity distribution, broadband access, biogas and
district heating and cooling for this municipality (EC-A, 2013a). The business group is a member
of Swedish Energy which is a Swedish trade association of approximately 380 companies in the
electricity industry (Swedish Energy, 2014). This Business group has an environmentally friendly
approach which can be seen in its vision “…to build the most resource-efficient region in the
world, which benefits both the environment as well as the economy.” (EC-A, 2013b) . The
organisation is built up by a parent company where the services district heating and cooling, the
electricity production, the wastewater treatment, the water distribution and the waste disposal is
managed (EC-A, 2013a). The Electricity retailing, including delivery of electricity to both privateand business customers, on the other hand is handled by a subsidiary. Two other subsidiaries
manage the electricity distribution and street lighting in these networks depending on the
geographical location. One of the subsidiaries only owns the grid in one location and contracts its
personnel from the other company. Since the two subsidiaries share personnel they are tightly
linked and everything that applies for one of them also apply for the other and they are therefore
treated as one company in this thesis if not clearly stated otherwise. The three parts of the Energy
business group, electricity production, electricity retailing and electricity distribution are the only
parts of the business group that will be affected by the Network Codes. They will in this thesis go
under the name of Electricity Company A (EC-A). Since the retailing company and distribution
company are subsidiaries they will go under the names Electricity Company A Retail (EC-A-Retail)
and Electricity Company A Grid (EC-A-Grid).
10
3 Change management theory
This chapter is based on the content of Chapter 2 “Background” and treats the theory regarding change
management which provides the foundation for Chapter 4 “Method” that follows. It begins by explaining the
reasons for an organisation to make changes followed by an introduction to the different types of changes (section
3.1). The chapter continues by discussing how to tackle different kinds of change. Thereafter it introduces the ISM
which is a model that can be used especially when faced with a change that has been classified as hard (section 3.2).
Lastly criticism is raised towards the use of models (section 3.3).
Today’s organisations face a constantly changing environment (Nahavandi, 2014) and to be able
to survive in this environment, an organisation needs to assess the environment correctly
(Sinclair-Hunt & Simms, 2005) and adapt to the changes (Nahavandi, 2014). Nahavandi (2014)
goes further and suggests that the very survival of an organisation is dependent on how well it
can adapt to change. The purpose of this chapter is therefore to choose a suitable solution
methodology for the research question two and three in this thesis.
3.1 Forces of change
There are two different forces that drive an organisation to make changes, internal and external
forces (Nahavandi, 2014). The nature of these forces must initially be analysed in order to be
dealt with successfully (Paton & McCalman, 2000). There are a vast amount of external forces;
for example forces connected to rapid technology advances, new political leadership, scarcity of
natural resources or changes in government legislation (Paton & McCalman, 2000; Sinclair-Hunt
& Simms, 2005). The legal structures, for example EU-directives, which aim to harmonise the
conditions between the member states, are the most common factors in the organisation’s
environment that limits its manoeuvring possibilities (Furusten, 2007). Change in leadership,
performance gaps within the organisation (Nahavandi, 2014) or a loss of market share are
examples of internal forces for change (Sinclair-Hunt & Simms, 2005).
There are different ways of coping with a change. Both Nahavandi (2014) and Paton &
McCalman (2000) emphasise the importance of first identifying the nature of the change and its
environment in order to choose the right method management. Nahavandi (2014) also
emphasises the importance of the right leader. She states that the organisation’s survival is
dependent on a good management of change and that it is important that the leader provides the
organisation with a clear vision to follow. Moreover the knowledge of the surroundings’
importance is further emphasised in this quotation: “In this new age staying marginally ahead of
the game could be considered not only an achievement but also a prerequisite for survival.”
(Paton & McCalman, 2008, p.6). An early identification of the change facilitates the management
of it (Paton & McCalman, 2000). In this constantly changing, dynamic environment it is difficult
to predict the changes though. Paton & McCalman continue by categorizing changes into two
categories, soft or hard changes. A hard change is purely of technical nature and does not affect
the surrounding environment while a soft change involves people and is surrounded by a
dynamic environment. Paton & McCalman emphasise that the change usually is neither one nor
the other but have similarities with both. For a purely hard change a more system based solution
methodology is recommended while for a soft change a methodology that is sprung from the
organisational school of thought is more suitable. Once the nature of the change is determined
the most suitable solution methodology can be chosen.
3.2 The Intervention Strategy Model
The Intervention Strategy Model (ISM) is presented in this section and the description of the model is
taken from Paton & McCalman (2000), but shortened by the authors. Consequently Paton &
McCalman (2000) is the source of all information in this section (3.2 The Intervention Strategy
11
Model) if not stated otherwise. First an overview of the model is presented and then the different
phases of the model are explained in more detail. The first two phases of the model are explained
more thorough than the third since only the two first phases will be utilized in this thesis.
The ISM is a solution methodology with a systems approach which is most suitable for hard
changes but will also provide a meaningful result for changes that are classified as softer. It might
need some alterations and complementation to fit a specific situation though.
The model is divided into three phases; the definition phase, the evaluation phase and the
implementation phase. Each is in turn divided into different stages. In the end of every phase
there is a review activity where all the participants decide if they are ready to move on to the next
phase. Before initiating the three phases there is a stage named problem initialization. This stage
includes identification of the change situation and the selection of the change management team
and the problem owner. All the stages in the methodology can be seen in Figure 4.
Figure 4 This figure presents the different phases and stages of the Intervention Strategy Model. The arrows indicate
possible ways to proceed at the different stages (Paton & McCalman, 2000, p.85).
12
When using the ISM an iterative way of thinking is to be used to include changes in the
surroundings that may occur along the way. It is even suggested that a shorter, not as detailed,
analysis of the change should be performed prior to the more detailed one to save time on the
iterations. A screening where some of the found options are rejected must also be performed
prior to the more detailed analysis.
3.2.1 The definition phases
Paton & McCalman suggest that if a big effort is put into the definition phase, it will pay of later
in the process by making it easier to analyse and identify the change’s impact on corporate culture
for example. This phase is divided into three different stages;



The problem/system specification and description
The formulation of success criteria
The identification of performance indicators
In the problem/system specification and description stage the aim is to understand the nature of
the situation and describe the problem and the systems affected by it. To gather the relevant
information and to map the present stage and how the systems are connected, interviews and
meetings can be held and relevant data can be reviewed. A diagramming tool can be used during
this stage to specify the problem and make the presentation of the situation clearer. An example
of a diagramming tool is a flow chart which illustrates the processes and the activities in a system.
The reasons for a manager to use diagramming tool is for example that the diagramming tool
brings structure to a chaotic situation and that it can help with the process of communicating the
ideas and options. The importance of communicating a coming change is highlighted in this
stage. The problem owner needs the employees to cooperate in order to truly define how the
change will affect the organisation and an inadequate problem description will lead to issues in
the later stages.
The best and most common way of formulating the success criteria is by setting objectives and
constraints. Usually the reason for the change provides the objectives. The lack of resources, for
example money or time, is associated with the constraints on the other hand. In this stage it is
important to cover all the objectives and constrains and not to overlook any sub-objectives or
constraints associated with them. One way of setting the objectives and constrains is by creating a
prioritised objectives tree. This is a tool that illustrates the relationships between the objectives
and constraints.
The next stage, once the objectives and constrains are defined, is the identification of
performance indicators. This consists of the formulation of measures connected to each
objective. It is recommended that the measures are quantified (time, cost and labour etc.)
otherwise the measures should be graded.
3.2.2 The evaluation phase
The evaluation phase is divided into three stages:



Generation of options and solutions
Selection of evaluation techniques and option editing
Option evaluation
There are many different techniques that can be used when generating options and solutions for
example; interviews and comparison analyses, the usage of focus groups or structured meetings.
It is advised to have a wide perspective when generating the options and solutions and to
13
consider multiple options and solutions for each measure. Furthermore the group of people
working with the generation process have a big influence on the result.
Secondly the evaluation technique is to be selected. In this stage the identified options are to be
edited by using the chosen evaluation techniques. A variety of techniques that can be used and
combined to evaluate the options and to avoid sub-optimisation exists. Simulations, cost-benefit
analysis and environmental impact analysis are examples of these techniques. There is no need
for the chosen technique to be quantifiable though.
The last stage in this phase, the option evaluation, consists of an application of the chosen
evaluation technique when evaluating the different options. The final product of this stage is a set
of solutions to implement. Consequently the implementation stage corresponding to every option
has to be considered. This can be accomplished by adding implementation objectives when
formulating the success criteria.
3.3 Criticism against the use of solution models
Abrahamsson (2000) describes a solution methodology that is also sprung from the opinion that
different parts in the organisation can be changed separately without affecting each other. This
model is also divided into different stages. Like the ISM it has phases were the objectives are
defined, alternative measures are determined and weighed against each other, followed by a
choice of the strategy.
In Abrahamsson (2000) a few strengths and weaknesses are presented for this type of linear
models where the objectives are directly linked to the measures. He states that an individual or
group of individuals might be limited to act rational when defining objectives and might not
choose the most beneficial one. The limitations can both be connected to the individuals, for
example lack of knowledge, or be connected to the surrounding. Furthermore he stresses that the
process of breaking down the objective to sub-objectives always will be affected by the
individual’s personal beliefs. The process of choosing measures is affected in the same way and
will consequently never be neutral. On the other hand Abrahamsson point out that breaking
down large objectives into sub-objectives can make the objectives more concrete and the
objectives can act as a driving force for the organisation’s work.
14
4 Method
This chapter is based on chapter 2 “Background” and Chapter 3 “Change management theory” and provides the
method used for answering the research questions of this thesis presented in Chapter 6 “The area of greatest
concern”, Chapter 7 “Possible organisational consequences” and Chapter 8 “Actions required to deal with the
information handling”. First the scoping process is described which includes how information was gathered, how the
change management model was chosen and which alterations that were made to the model (section 4.1). Then the
method used for answering the research questions is described (section 4.2). This section begins with an overview of
which analysis stages are connected to which research question followed by a more detailed description of each stage.
Lastly the discussion and the solutions is described (section 4.3).
To answer the research questions in this thesis the study was conducted in two parts followed by
a discussion and conclusion part.
1. Problem and the solution methodology scoping (explained in more detail in section 4.1):
a. A document study to gather background information on the problem and the
current conditions in Sweden.
b. A literature study where the change management model, to be used for answering
RQ 2 & 3, was chosen.
2. Answering the research questions (explained in more detail in section 4.2 and Figure 5)
a. Combined interview and document study to gather concerns within the line of
business and determine the area of greatest concern. (RQ1)
b. Used the stages in the definition phase and the first stage in the evaluation phase
of the ISM to determine the organisational consequences the area of greatest
concern will have on an electricity company. (RQ2)
c. In order to determine actions that are required to cope with the area of greatest
concern the preconditions were determined by using EC-A as the baseline
example. The current conditions of EC-A were defined by using the first stage of
the definition phase of the ISM and the analysis of the actions was done by using
the last two stages in the evaluation phase of the ISM. (RQ3)
3. Discussion and Conclusion (explained in section 4.3)
a. Discussion of the generalizability of the outcome and how the choice of method
has affected it as well as the development potential of ISM.
b. Conclusions were drawn from the results and the discussion.
4.1 Problem and solution methodology scoping
As explained in the beginning of this chapter the study was divided into two parts. The first part,
which is explained in this section, was conducted with the purpose of determining the problem
background and to determine a methodology for how to tackle the problem.
4.1.1 Document study for the background
A shorter survey and analysis of the Network Codes were conducted in parallel with a survey of the
current conditions in Sweden and the functions of a Swedish non-transmission system connected
electricity company.
The survey of the Network Codes was conducted mainly using documents and information found
on ENTSO-E’s homepage. Because of the Network Codes’ complex and extensive content this
phase focused on investigating the summaries and supporting documents. For the survey of the
current conditions in Sweden the background was determined mainly using information from
Nord Pool Spot, which is the power market where Swedish companies trades most of their
electricity (Swedish Energy, 2012c), SvK which is the Swedish TSO (Inderberg, 2012) and Swedish
15
Energy which is the trade industry for the Swedish electricity companies (Swedish Energy, 2013a).
The results from this survey was also used later when creating “EC-A’s flow chart” in Section
4.2.4.
For the survey of the functions of an electricity company a study was done on a non-transmission
system connected electricity company in south east of Sweden. The electricity company was
chosen based on the presence of production, distribution and retailing within the same business
group and is in this thesis named Electricity Company A (EC-A). The grid company is among the 410 largest Swedish grid companies and is therefore assumed to have resources to investigate the
consequences of the Network Codes (Swedish Energy Market Inspectorate, 2013a). The
information required for the scooping process was primarily retrieved by reading relevant
documents on the company’s homepage and the annual report.
4.1.2 Choice of change management model
The ISM was chosen as the underlying method for answering research question two and three in
consultation with researchers in the field. The model was selected due to the similarity of
problem the electricity companies are faced with and the problems the ISM was created for.
The adaptations made in the Intervention Strategy Model
Which of the stages in the ISM that were used for answering which question can be seen in
Figure 5 and is explained in more detail in section 4.2. A few adaptations were made to the
original model which are described below (The original ISM can be seen in Figure 4):




16
In the first stage of the definition phase the diagramming tool flow chart was used, as
suggested in Paton & McCalman (2000), when describing the current conditions for ECA and to define the change situation. The information presented in the flow chart was
gathered through document studies and interviews.
In the second stage of the definition phase the success criteria for change was
formulated as objectives and constrains, as Paton & McCalman (2000) recommend, but
the prioritised objective tree was not used. The changes that are required are the results
of legislation and therefore all the objectives have to be fulfilled and no prioritising was
required.
In the third stage of the definition phase the formulation of measures was done without
quantification due to limited benefits in comparison to required effort.
In the evaluation phase the solution generation and evaluation was conducted by the
authors together with the employees of EC-A-Grid. The employees were chosen to be
involved since Paton & McCalman (2000) states that it is important to consider the
implementation phase when choosing the solution. The assumption was made that the
employees have a greater knowledge than the authors regarding the difficulty to
implement different solutions into the organisation of EC-A-Grid.
4.2 Method used for answering the research questions
As explained in the beginning of this chapter the study was divided into two parts. The second
part, which is explained in this section, was conducted with the purpose of answering the
research questions of this thesis and was performed in the following analysis steps. The steps can
also be seen n Figure 5 and are explained in more detail in the corresponding sub-sections.
1. Determine the “Area of greatest concern” (RQ1)
a. A “Document study on concerns” was conducted to identify areas where
concerns had been expressed.
b. “Interviews on concerns” were held to identify additional areas where concerns
had been expressed.
To answer research questions two and three the structured approach and the analysis steps of the
ISM were utilized. For the second question stages 1-4 were used and for question three stages 1
and 5-6 were completed (see Figure 5).
2. Determine the organisational consequences of the network codes by doing a
“Generation of possible solutions”(RQ2)
a. To describe and visualise the area of greatest concern in the “Network codes’
flow chart”, in the first stage of the ISM, a “Network code study” was conducted.
This study collected everything written in the Network Codes that are linked to the
area of greatest concern.
b. The information flows from the flow chart were broken down and the
“Formulation of objectives to cover the flows” was conducted which is the
second stage of the ISM.
c. The “Formulation of measures to deal with the objectives” was conducted by
breaking down each objective to a number of measures which is the third stage of
the ISM.
d. The “Generation of possible solutions”, which is also the answer to research
question two, was conducted by creating a number of solutions for each measure.
This is the 4th stage of the ISM and was partly done through a “Dialogue with
internal personnel”.
3. “Formulation of the action list” consists of the actions an electricity company has to
take to cope with the change (RQ3)
a. To describe and visualise the current conditions of the company in the “EC-A’s
flow chart”, in the first stage of the ISM, “Interviews at EC-A” were held. The
document study on the background was also used to accomplish this flow chart
and to ensure that everything related to the area of greatest concern within EC-A
was collected.
b. For the “Formulation of the action list”, which is the answer of research question
three, the generated possible solutions were compared with the current conditions
at EC-A. This was conducted through a “Dialogue with internal personnel” and
the solutions most suited for EC-A were chosen. This is the 5th and 6th stage of the
ISM.
17
Document
study on
concerns
Interviews on
concerns
Area of greatest concern (RQ1)
Interviews at
EC-A
Document study
on current
conditions
Network code study
Definition Phase
Stage 1
Network Codes’ flow chart
EC-A’s flow chart
Stage 2
Formulation of objectives to
cover the flows
Stage 3
Formulation of measures to deal
with the objectives
Evaluation phase
Stage 4
Generation of possible solutions
(RQ2)
Dialogue with internal personnel
Stage 5 & 6
Formulation of the action list
(RQ3)
Generalizability
Method’s influence
ISM’s development potential
Conclusion
Figure 5 This figure shows the method that was used for addressing the aim of this thesis. It consists of different
steps that are illustrated with boxes. The arrows between the boxes illustrate how the analysis steps are connected.
The two dashed boxes show the parts of the method that are based on the ISM and the brackets illustrate which of
the ISM’s stages corresponding to each box. .
4.2.1 The “Document study on concern”
In order to determine the area of greatest concern a thorough document study was conducted to
first identify concerns within the line of business. The opinions from the stakeholder
organisations were gathered by searching their homepages for documents. The organisations that
were used can be seen in Table 1. The reason to why the identification process was done in this
way, and not by studying the Network Codes straight away, is based on the assumption that people
within the line of business and stakeholder organisations who work in the sector and with the
Network Codes have a greater understanding of the differences from today and consequently the
concerns.
18
Table 1 In this table the associations that have been used in the identification process of areas of concerns are
presented.
Organisation
Description
GEODE
An association for distribution companies that “...defends the interest of the local distribution
in front of energy authorities on national and international level...” (GEODE, 2013b) including
the drafting of Network Codes (GEODE, 2013c).
Eurelectric
An association that represents the electricity industry’s common interest at a pan-European
level (Eurelectric, n.d. b). They are following the drafting process of the Network Codes and are
involved in discussions with the drafting organisation ENTSO-E (Eurelectric, n.d.c).
4.2.2 The “Interviews on concerns”
To identify additional areas of concern interviews were held with people within the line of
business. First an identification process was conducted, in cooperation with the tutor at EC-A,Grid to identify relevant contacts to interview. Other non-transmission system connected
electricity companies and Swedish Energy were identified and the person responsible for the
Network Codes was contacted. Employees within EC-A were also interviewed based on their
knowledge of the current conditions. Meetings and interviews were set up and held with the
identified people. In this study all of the companies have been anonymised since the opinion’s
origin is unimportant for the results. The working title of the interviewees and information about
the companies and what type of meeting it was can be seen in Table 2.
The series of interviews and meetings started off with a meeting with Lundqvist (2014).
Lundqvist works at Swedish Energy and is responsible for Swedish Energy’s activities related to the
Network Codes and he also participates in ENTO-E’s reference group (Swedish Energy, 2013b).
(Swedish Energy, 2013b). During this meeting Lundqvist expressed the concerns he supported
and a few open ended questions, based on other concerns found in the document study, were
asked. Because of Lundqvist’s extensive knowledge about the Network Codes he has been
consulted regarding uncertainties during the course of the study.
Interviews were held with a number of employees at EC-A who work within the areas where
concerns had been identified during the document study. The questions were open-ended and
the answers were taken into account when determining the area of greatest concern.
A telephone interview was held with the grid planning manager at Electricity Company B (EC-B).
Open ended questions were asked similar to “what concerns can you see with the Network Codes”
since he had monitored the development process of the Network Codes for some years (Grid
Planning Manager, 2014). The meeting with Electricity Company C (EC-C) was held later in the
study. Here the authors presented the already found concerns and a discussion was held with the
participants from EC-C about them. They shared their opinions on the concerns already
identified and also expressed concerns of their own. Both EC-B and EC-C are similar to EC-A and
have electricity grid, production and retailing within their business group (EC-B, n.d).
Additionally the electricity grids owned by these companies are among Sweden’s 4-10 largest
(Swedish Energy Market Inspectorate, 2013a) and are located in the southern part of Sweden.
19
Table 2 This table contains information regarding the interviewees. It states the interviewees position, which
company or organisation they work for and how and when the information was gathered. It nothing other is stated
information was gathered through an interview.
Title
Company/ Organisation
Interview Date
Johan
Lundqvist/Regional
Manager West
Swedish Energy
Meeting: 2014-02-05
Business Developer
EC-A
2014-02-28
Energy Strategist
EC-A
2014-02-25/2014-04-09
Plant Engineer
EC-A
2014-03-06
Customer Relations
EC-A-Grid
2014-02-06/2014-03-31
Measuring Responsible
EC-A-Grid
2014-02-15
NOC Engineer
EC-A-Grid
2014-02-05
Power Engineer
EC-A-Grid
2014-03-07
Analytics and Risk Manager
EC-A-Retail
2014-03-03
Business Development Manager
EC-A-Retail
2014-02-24
Grid Planning Manager
Electricity Company-B (EC-B)
Phone interview 2014-02-27
Business Environment Analyst
Electricity Company-C (EC-C)
2014-03-10
Planning Engineer
EC-C-Grid
Meeting: 2014-03-10
Balancing Responsible Electricity
trader
EC-C-Retail
Meeting: 2014-03-10
4.2.3 The selection process of the “Area of greatest concern”
To determine the greatest area of concern and answer the first research question a screening
process was conducted. This was done since not all of the concerns could be investigated within
the time frame of this thesis.
Similar concerns that had been found during the document study and expressed during the
meetings and interviews were grouped together in different steps. Firstly the concerns from
different stakeholders were grouped together according to similarities but within the same
Network code. For example concerns regarding the grid model in CACM were grouped together in
this step. These groups can be seen in Appendix 1. Certain similarities could be seen between
different groups, especially in the measures needed to cope with them. Consequently the groups
were added together accordingly in the next step and formed areas of concern. This step was
conducted in cooperation with the tutor at EC-A-Grid and was influenced by the number of
concerns from stakeholders that made up each group. The areas of concern that were formed
were “information handling”, “simulation models” and “demand side aggregator”. For example
“information handling” is based on the groups regarding monitoring of different facilities and the
communication of information between different actors and all the administrative work that is
linked to this. Finally “information handling” was determined to be the greatest area of concern
based on the number of stakeholders that expressed concerns regarding the different areas.
20
4.2.4 The definition phase
After the area of greatest concern had been identified further analysis was conducted to answer
the two last research questions. The different stages in the definition phase were mostly utilized
for answering research question two but a part of the first stage, which addresses the current
conditions within EC-A, was utilized for answering research question three.
The “Network Codes study”
The document study on the Network Codes was conducted to define the change problem and to be
able to create a flow chart in the first stage of the definition phase as part of the analysis to
answer research question two.
Drafts to eight of the prioritised Network Codes were studied in more detail and everything that
was linked to information handling or communication was identified and gathered. The ninth
code was excluded according to the limitations in Section 1.2. Drafts were read since the
development process of the Network Codes was not finished and therefore the final Network Codes
may differ from the ones analysed here. There are a number of drafts on each code, therefore
Table 3 illustrates which drafts this thesis conclusions are based on. The aim was to read the
documents most recently drafted.
Table 3 This table displays the Network Codes that have been analysed in this study and which draft that has been
studied for each code.
Network Code
Abbreviation
Draft studied
Capacity Allocation and
Congestion Management
CACM
Network Code on Capacity
Management (2012-09-27)
Forward
Allocation
FCA
Network
Code
(2013-10-01)
EB
ENTSO-E Network Code on Electricity Balancing (2013-12-23)
RfG
ENTSO-E Network Code for Requirements for Grid Connection
Applicable to all Generators (2013-11-19)
Demand Connection Code
DCC
ENTSO-E Network
(2012-12-21)
Operational Security
OS
Network Code on Operational Security (2013-09-24)
Operational Planning and
Scheduling
OPS
Network Code on Operational Planning and Scheduling
(2013-09-24)
Load Frequency Control &
Reserves
LFCR
Network Code on Load-Frequency Control and Reserves
(2013-06-28)
Capacity
Electricity Balancing
Requirements
Generators
21
for
on
Allocation
Forward
Code
on
and
Congestion
Capacity
Allocation
Demand
Connection
The creation of the “Network Codes’ flow chart" used for specifying the problem
The diagramming tool flow chart was used in the first stage of the definition phase to get an
overview of the problem. This was done as part of the analysis to answer research question two.
The flow chart was created by analysing the information from the “Network Codes’ study” and
based on the following assumptions:





Article 21 and 23 in OS were not clearly written and may consequently be interpreted in
a few different ways. The interpretation used in this thesis is that these articles only
apply to power generating modules (PGMs) that are connected to the transmission
system.
In some of the articles in the Network Codes it is stated that the path of the information
flow is to be determined by the TSO and the DSO together and that it can either go
straight from the PGM to the TSO or via the DSO. In these cases, if nothing else is
stated later on, the assumption was made that the flows will go through the DSO. This
way all possible information flows for the DSO are covered.
The imbalance settlement was assumed to be conducted in the same way as today, were
the DSO receives data from clients and send to the BRPs.
In OS the term Significant Grid User (SGU) is introduced. The definition of a SGU
opens up for multiple interpretations according to the authors. The interpretation used
for this study was that all existing and new PGMs type B, C and D are SGU. This is based
on the interpretation from article 1:5 and 2. Furthermore article 9:4 rules out the
possibility that only significant PGMs are SGU. Moreover the text in 8:2:1 in the
supporting document of OS was interpreted to be the conditions for making the
definitions in article 1:5 OS.
Finally only information flows where the electricity company is affected has been taken
into account. Consequently all information that flows between other actors were not
covered, for example communication between the TSO and the NRA.
In order to achieve an understandable flow chart a few intermediate flow charts were drawn
before ending up with the ones presented in this thesis:
1. A flow chart was drawn where all different actors specified in the Network Codes were
present and every article affecting the communication had one arrow. The number of
actors and information flows presented in this flow chart were high and therefore also
the complexity.
2. A new flow chart was drawn where both actors and information flows were grouped
together to some extent. The actors were grouped according to similarities found when
further analysing the Network Codes and synchronous PGMs and Power Park Modules of
the same size were grouped together as just PGMs for example. Furthermore the
information flows between the same actors were grouped together based on occurrence.
For example the data exchanges between PGM type A and the DSO in real-time formed
one group and data that only has to be sent once formed another group. Now the
amount of information flows and actors were lower but the diversity of information to
be exchanged in each flow was still an issue.
3. In the last flow chart the information flows were split up again according to
dissimilarities in the data exchange. Here the information that had so to be dealt with
only once were split up into new installation data and derogation data for example.
4. To further increase intelligibility the actors were split up into two different flow charts
based upon if the actors were production or demand units. These flow charts are the
22
ones presented in the thesis with a fairly limited number of arrows without including too
diverse data exchanges.
The “Formulation of objectives to cover the flows”
The formulation of objectives to cover the information flows is the second stage of the definition
phase. It was conducted in order to start breaking down the problem specified in the first stage
of the definition phase as part of the analysis to answer research question two.
For this part the DSO’s perspective was used and objectives were only formulated for the
information flows where the DSO was involved. The reason for choosing the DSOs perspective
was that the largest number of individual concerns were expressed regarding the consequences
for the DSO and the fact that the flow chart indicated that the DSO had more communication to
deal with. The different types of information flows were broken down into 35 objectives with
corresponding constrains. Information flows were grouped together when it was deemed
possible to handle them in the same way. One example is the administrative burden for new
installations of a PGM. The DSO has to provide and administrate new installation forms and rules
for new PGMs of all types and therefore they were grouped together as one objective. Some of
the information flows were split up into two objectives since the data they represent can be dealt
with in different ways. One example of a split is the flow that has to do with compliance. This
flow represents both the reception of notification if the PGM plans on changing its technical
specifications and the reception of notification if something has gone wrong. These two types of
information flows should be handled in different ways and therefore this flow has been broken
down into two objectives.
The constrains that were set are constrains regarding how fast after the code enters into force
that the objective has to be fulfilled.
The “Formulation of measures to deal with the objectives”
The measures associated with each objective were formulated to cover the whole process of the
objective. This is the third stage of the definition phase and is conducted as part of the analysis to
answer research question two. One example of an objective that has been broken down is the
objective for new installation of PGMs. This objective was broken down into three measures:
1. Analyse and decide what information is to be included in the forms.
2. Create different forms for the different types of unit.
3. Receive and put the information from forms into a system.
This was done to cover all the different work assignments that are associated with the objective.
The “Interviews at EC-A”
Interviews were held with employees of EC-A to be able to define the current conditions and to
be able to create the “EC-A’s flow chart” in the first stage of the definition phase as part of the
analysis to answer research question three.
The employees that were chosen to be interviewed were people who work within the areas were
concerns had been identified. A list of their positions can be seen in Table 4. The questions had
the origin in the concerns that had been identified and were both open-ended and more detailed.
These people were also involved in order to establish the change firmly within the organisation
and prepare it for change.
23
Table 4 This table contains information regarding the interviewees. It states their position within EC-A and how the
information was gathered. Some of the employees were interviewed twice and this is indicated by the different dates
in the last column.
Title
Part of the EC-A
Interview Date
Business Developer
EC-A
2014-02-28
Energy Strategist
EC-A
2014-02-25/2014-04-09
Plant Engineer
EC-A
2014-03-06
Customer Relations
EC-A-Grid
2014-02-06/2014-03-31
Measuring Responsible
EC-A-Grid
2014-02-15
NOC Engineer
EC-A-Grid
2014-02-05
Power Engineer
EC-A-Grid
2014-03-07
Analytics and Risk Manager
EC-A-Retail
2014-03-03
Business Development Manager
EC-A-Retail
2014-02-24
The creation of the “EC-A’s flow chart” used for specifying the system
The diagramming tool flow chart, in the first stage of the definition phase, was not only used to
define the problem enforced by the Network Codes but also to provide an overview of the current
conditions at EC-A. This was part of the analysis to answer research question three. The
information that was used when putting together the flow chart was the information gathered in
the “Document study for the background” in section 4.1.1 and the “Interviews at EC-A” treated
earlier in this section. At this stage one additional assumption was made:

Since the Network Codes state that the size of the PGM is calculated per connection point
the assumption was made that one connection point is equal to one measuring point.
Consequently multiple generators can be connected to one connection point and be one
PGM which is the case for some of EC-A’s PGMs.
The different types of information flows were grouped together in the same way as in the final
flow charts describing the Network Codes explained earlier in this section. This was done to
facilitate any comparison between the different flow charts and to determine the actions required
by EC-A.
4.2.5 The evaluation phase
The results from the definition phase were analysed further in the evaluation phase to answer
research question two and three. The fourth stage was used for answering research question two
and the fifth and sixth stages were used for answering research question three.
For each measure formulated in the third stage of the definition phase a few possible solutions
were generated in the fourth stage (“Generation of possible solutions”). This was done with the
aim to include all solutions that could be sensible. Consequently this provides all the possible
organisational consequences for an electricity company which is the answer to research question
two. The process started with a brain storming session where solutions for each objective were
suggested by the authors. The employees at EC-A-Grid then got the chance to add additional
solutions during meetings that were held with them. The employees that were asked to join were
24
the employees that work in the organisation that will be affected by the change (see Table 5).
Once the additional suggestions were added the list with possible solutions, for the different
objectives, provided the answer to the second research question.
Table 5 This table includes the employees that were used in the dialogue in the evaluation phase to evaluate the
generated solutions.
Title
Part EC- A
Meeting or Interview/Date
Business Area Manager Grid
EC-A-Grid
2014-04-08
Customer Relations
EC-A-Grid
2014-04-10
Measuring responsible
EC-A-Grid
2014-04-14
NOC Engineer
EC-A-Grid
2014-04-10
NOC Manager
EC-A-Grid
2014-04-09
Responsible of Sales
EC-A-Grid
2014-04-09
In order to evaluate the solution based on the conditions at EC-A-Grid and answer the third
research question a few assumptions had to be made:




In DCC it is stated that the transmission system is to be defined on a national level. In
this thesis the authors assume that the transmission system equates to the Swedish
national grid, owned by SvK. Since EC-A-Grid is not directly connected to SvKs grid ECA-Grid is a non-transmission system connected DSO and therefore a justified case to
study.
None of EC-A’s units are assumed to be considered a Relevant Asset by SvK. This since
OPS states that a Relevant Asset’s availability status shall have an influence on Crossborder operational security and which is assumed to not be the case for EC-A.
The existing PGMs owned by EC-A or located in the grid of EC-A-Grid are not assumed
to be deemed significant by SvK since they are assumed not to have an impact on crossborder system performance.
DCC applies to distribution networks that are significant and it is stated that a significant
distribution network is among other things a network that is connected to another
distribution network. Since EC-A-Grid is connected to another distribution network they
are therefore deemed significant in this study.
The same employees were also involved in the ”Formulation of the action list” through a
“Dialogue with internal personnel” which is the fifth and sixth stages in the model and lead up to
the answer of research question three. The generated solutions were presented to the employees
and they shared their opinions on which were the most suitable ones. The employees were
involved in the evaluation phase both for use of their knowledge and to firmly establish the
problem in the organisation and prepare for the coming change. During the analysis it was
recognised that further information was required on the current conditions at EC-A-Grid.
Therefore during the dialogue held with the employees at EC-A-Grid additional questions
regarding the current information handling processes in the company were asked. This
information was then added to the “EC-A’s flow chart”. Following the identification of the most
suitable solutions for the objectives, an action list was put together. This was done with the
purpose of achieving a more structured view of what the company in fact needs to do to cope
with the new information flows. This is furthermore the answer to research question three. The
25
suggested solutions for each objective were reviewed to try to identify similarities between them.
Solutions that were related were grouped together. The different solutions were also grouped
together depending on in which phase they are required. For example some of the actions are
only necessary in an implementation phase, while others are required in the ongoing work
processes. The action list that finally was put together involves actions that describe if new
systems are needed, if systems that are already in place can be altered, if the resources that are
needed already exist within the company or if new personnel has to be hired among others.
In order to fully answer the third research question the action list of EC-A-Grid had to be
analysed. Here the similarities between EC-A-Grid and other Swedish non-transmission system
connected electricity companies were analysed according to preconditions and size etc. This was
conducted to examine if the results based on the study of one case, EC-A-Grid, actually were
applicable for all Swedish non-transmission system connected electricity companies, as specified
in the introduction.
4.3 Discussion and Conclusion
After the research questions had been answered a discussion was held on the “Generalizability”
of the results to companies excluded in the limitations of this thesis. The “Method’s influence”
on the results was also discussed and if another method might have given different results. Finally
the “ISM’s development potential” was discussed and if the model actually was applicable for this
problem. From this discussion the conclusions of the thesis were drawn.
26
5 An overview of Electricity Company A and its’ information
handling
This chapter provides a more detailed description of EC-A and its subsidiaries, which provides the foundation for
Chapter 8 “Actions required to deal with the information handling”. It starts with presenting the distribution
system owner EC-A-Grid (section 5.1), then it goes on to presenting the production units owned by EC-A and the
production units in the grid (section 5.2). Then the balance responsibility of EC-A (section 5.2) and EC-A-Retail
are described (section 5.3). Lastly the information handling of these companies is presented, first with a flow chart
and then divided into the four categories, real-time information, applications, information due to unusual
circumstances and information with fixed intervals (section 5.4).
5.1 Description of Electricity Company A’s distribution network
EC-A-Grid is a subsidiary to EC-A and is, as mentioned earlier, a non-transmission system
connected electricity company with two separate grids both located in close proximity of each
other and away from the Swedish national border (EC-A, 2013a). The company has about 100
employees (Alla branscher, 2012) and combined the two separate grids consist of more than 3000
km low voltage cables and more than 2000 km of high voltage cables (Swedish Energy Market
Inspectorate, 2013a) and substations and secondary substations working with voltage levels
between 130 kV and 400 V (NOC Engineer, 2014a). Instead of having any connections to SvK’s
transmission system the two grids have five connection points to the regional grid of Electricity
Company D (EC-D) (NOC Engineer, 2014a). Electricity Company E (EC-E) on the other hand owns
a distribution network functioning on a lower voltage level. This grid is only connected to EC-AGrid’s distribution network (Customer Relations, 2014a).
Combined the two grid companies have over 90000 customers and 15 of these customers use
individually more than 1.5 MW of power (Measuring Responsible, 2014a). The maximum
transferred power is about 300 MW and the delivered energy is in total 1.5 TWh per year (Swedish
Energy Market Inspectorate, 2013a). The grid is dimensioned to handle the maximum power
from all production units simultaneously (Business Area Manager Grid, 2014). For demand units
on the other hand the grid cannot handle that all loads use their full capacity simultaneously
(Responsible of Sales, 2014).
5.2 Electricity production
In the grids owned by EC-A-Grid there are production units owned by EC-A as well as by other
actors (Energy Strategist, 2014a), (Measuring Responsible, 2014a). EC-A owns Combined Heat
and Power (CHP) plants, hydro power plants and wind power plants which all are located in the
proximity (Energy Strategist, 2014a). The CHP-plants mostly burn waste and biomass but when
the need for the limiting factor, heat, is high, they also use oil and coal. For the CHP-plants ECA-Grid has a measuring point for every generator (NOC Engineer, 2014b). The hydro power
plants on the other hand usually have multiple generators (Energy Strategist, 2014a) but EC-AGrid only has one measuring point per plant (NOC Engineer, 2014b). All of the hydro power
plants are controlled from the operations centre in one of the CHP-plants (Plant engineer, 2014).
In EC-A-Grid there are also multiple micro production facilities, which are consumers on a yearly
basis but have a certain amount of production (Measuring Responsible, 2014a). EC-A has
promoted micro production by net billing them per month which is one of the reasons for the
fairly high amount (Measuring Responsible, 2014a). The net billing model is going to be replaced
with a Swedish national model based on tax deduction. In Table 6 all of the production units
owned by EC-A or located in EC-A-Grid’s grid are presented.
27
Table 6 In this table the PGMs owned by EC-A and the other PGMs in EC-A-Grid’s grid larger than 800 W are
presented. The definition of PGM can be seen in sub-section 2.1.2. The production units are presented according to
type, size, which grid and what voltage level it is connected to and the owner of the units.
Size [MW]
Type
plant
≥30
CHP
10≤…<30
of
Number of
PGMs
Owner
Grid
Voltage
level
of
connection point[kV]
4
EC-A
EC-A-Grid
<110
CHP
1
EC-A
EC-A-Grid
>110
10≤…<30
Hydro power
3
EC-A
Other
<110
1.5≤…<10
CHP
2
EC-A
EC-A-Grid
<110
1.5≤…<10
Hydro power
4
EC-A
Other
<110
<1.5
Hydro power
21
EC-A
Other
<110
<1.5
Hydro power
10
EC-A
EC-A-Grid
<110
<1.5
Hydro power
4
Other
EC-A-Grid
<110
<1.5
Wind power
4
Other
EC-A-Grid
<110
<1.5
Wind power
1
EC-A
Other
<110
<1.5
Wind and solar
park
1
Other
EC-A-Grid
<110
<1.5
Micro production
~100
Other
EC-A-Grid
<110
5.2.1
EC-A’s balance responsibility
EC-A are the BRP for all its production and consumption (Energy Strategist, 2014a). This means
that they have to report their planned total production, consumption and trade to SvK the day
before. If the actual outcome does not match the planned this has to be regulated with SvK. The
balance is calculated per individual hour and depending on in which direction an eventual
imbalance is, EC-A has to pay or get paid corresponding amounts. The hourly values,
prognosticated by EC-A, are changed to 15-minute values by the Cactus system which are
transferred to SvK (Energy Strategist, 2014b). This data also includes the amount of bilateral
trade. A weather dependent production complicates the possibility to maintain the balance for
every individual hour (Energy Strategist, 2014a). The balancing responsibility includes the
obligation to trade on the Elbas to compensate for imbalances before they happen and as long as
the BRP is less than 4% out of balance over the course of a month only a regulating fee has to be
paid.
EC-A has a bilateral agreement with EC-A-Retail which means that most of the electricity is sold
for spot price to EC-A-Retail. The agreement states that EC-A-Retail should be informed of ECA’s plan for sold electricity for the coming week, every week. The surplus electricity is sold on
Elspot and the bids have to be reported to Nord Pool Spot before 12 noon. Within one hour the
verdict regarding the amount of traded electricity is received and the information regarding the
production and consumption of EC-A is sent to SvK. EC-A makes more long term production
planning every year for the following five years. The compliance with the plan is highly
dependent on the weather though. A plan for when the different production sites of EC-A will be
28
taken out of production for maintenance etc. also exists. Both of these plans are merely for
internal use and are not communicated to other parties. (Energy Strategist, 2014a)
5.3 The Electricity retailing for EC-A
All electricity retailing for EC-A is done through the subsidiary business group of EC-A-Retail
(EC-A, 2013a). EC-A-Retail is co-owned by 10 regional electricity companies where EC-A is the
majority owner with over 50 % of the stocks (EC-A-Retail, 2013). The approximately 250 000
customers (Business Development Manager , 2014) combined with the turnover makes EC-ARetail one of the five largest electricity retailing companies in Sweden, delivering almost 6 TWh of
electricity (EC-A-Retail, 2013). EC-A-Retail is balancing responsible for its owner’s production
except for EC-A which manages its own balances (Analytics and Risk Manager, 2014). The other
owners continuously send plans to EC-A-Retail over planned weekly and daily production. These
plans are then aggregated together with the planned consumption and a bid is sent to Nord Pool
Spot. The production of EC-A is also sold on Elspot by EC-A-Retail even though it is bought
bilateral. Overall EC-A-Retail is a net buyer of electricity on Nord Pool Spot though.
5.4 The handling of information
Currently EC-A and EC-A-Grid handles multiple different types of information communicated by
different actors. This includes information sent and received in real-time (NOC Engineer,
2014b), information that only needs to be sent once (Responsible of Sales, 2014), information
that has to be handled in case something happens (NOC Engineer, 2014a) and information that
needs to be sent on a scheduled basis (Measuring Responsible, 2014a). An overview of the
different types of information flows and the actors involved can be seen in Figure 6 and a more
detailed description on the handling of the information can be read in the sub-sections that
follow.
29
Demand
Facilities
<1kV
y ah
: Da
BRP
Nord Pool
(Market)
ead
Day ahead,
energy & price
ta
lla
tio
ns
&p
in
s
ew
Monthly planned & outcom
e cons/BRP
ns
d co
nne
a
l
p
rn
ork
from framew
Derogation
(DSO)
n
pla
es
er
tag
u
O
pow
e
v
i
Act
new a
BRP EC-A:
for ch dat
ns/
n
o
o
c
i
t
te
e
lica ge
com
App Chan
out
&
d
nne
pla
y
l
data
h
nt
ge etc. Change tech
Mo
er, votla
w
o
p
e
d
v
eacti
cons & pro
Active/r
d planned
ea
ah
ay
D
BRP:
Ei
es statistics
Yearly Outag
EC-A
Ap
Change tech
BRP: Day ahea
da
d planned cons ta
& prod
D
en ay a
erg he
y & ad,
pri
ce
fo
ew
Production
Plants >25 MW
or
m
at
io
n
rn
Production
Plants <25 MW
wer
EC-A: Active po
an
pl
s
ge
ta
Ou
data
Change tech ome cons/BRP
ned & outc
an
pl
ly
th
on
M
new
plication for
In
f
fo
EC-E
(Lower DSO)
NOC-NOC
ion
at
lic
ec
Da
km
ily
ee
m
new
ee
te
rin
te
gf
rin
or
g
Dail
80
y me
Possib
%
eter
ing
le mo
nitor
ing
Contracts NOC-NOC
Delivered power &
Energy
fo r
Notification of larger work
Ch
Contracts
power of each source
App
lica
tion
Homepage
(Higher DSO)
p
Ap
Demand
Facilities
>1kV
EC-D
(RNA)
SvK
(TSO)
rod
Retailing
companies
Figure 6 This figure illustrate the information flows connected to the different actors around EC-A. The colour of the arrow indicates type of flow, red is real-time, yellow is
scheduled, green is “in case of” and blue is data sent only one time. The dashed arrows show that the information flow might exist. To be able to have complete view this flow chart
should be read together with 5.4.1, 5.4.2, 5.4.3 and 5.4.4 seen below.
30
5.4.1 The handling of real-time information for EC-A and EC-A-Grid
The Network Operation Centre (NOC) is continuously manned and is in charge of the operation
of the grid and handles the fault reports for the whole concern (NOC Engineer, 2014a). There
are two main IT-systems in operation in the NOC, the Distribution Management System (DMS)
that is part of the Trimble NIS2 , where a real-time image of the electricity grid down to 400 V is
available, and Netcontrol for remote control of the switches (NOC Engineer, 2014a). These two
systems are closely connected and communicate with each other concerning all equipment
between 6 kV and 130 kV. Netcontrol is the central system for communication with the substations
and the secondary substations and a vast majority of them can therefore be controlled remotely
from the NOC. When a switch has gone off the information will be sent from Netcontrol to the
DMS where it is stored, to ensure that the real-time image always is up to date. Information
regarding the production facilities is also stored in the NIS and it is possible to add additional
information (NOC Manager, 2014). If something abnormal happens an alarm goes off to notify
the dispatcher on duty (NOC Engineer, 2014a). According to NOC Engineer (2014a) Netcontrol is
a vivid and extensive system and a lot of different components can be handled by it.
Active and reactive power for almost all hydro power plants and CHP-plants owned by EC-A or
connected EC-A-Grid’s grid can be seen in real-time in the NOC (NOC Engineer, 2014b). EC-A’s
hydro power plants connected to other grids can only be seen in the Operation Centre of EC-A
(Plant engineer, 2014). This real-time information is not communicated to anyone but only used
for internal control. The communication with other actors in real-time is limited (NOC Manager,
2014). At the connection points between different grid owners, both companies have equipment
present to monitor the grid and therefore no real-time communication between these parties is
needed. For all demand facilities connected to the high voltage grid the meters are viewable in
real-time. 80 % of the low voltage meters can be checked for real-time values on demand, which
can take a few minutes, a few of them can continuously send real-time information if their
software is updated. (Measuring Responsible, 2014a)
5.4.2 The handling of information that needs to be dealt with once
All new customers and production units that want to connect to the grid owned by EC-A-Grid
have to send in an application (Responsible of Sales, 2014). This is to ensure that the existing grid
can handle the new power flows (Business Developer, 2014) and that the production unit meets
the requirements (Measuring Responsible, 2014a). Information regarding the application and the
requirements for certain facilities is visible on EC-A’s homepage (Responsible of Sales, 2014). For
the new installation of production units smaller than 1.5 MW the web based system Elsmart is
used for the application. This is also used for other installations where a certified electrician is
required, like heat pumps etc. The electrician then fills in information about the power output
and energy source into the application system. This system is in use for several other grid
companies in both Sweden and Norway.
Depending on the complexity of the installation a network analysis may be conducted prior to
the approval of the application (Responsible of Sales, 2014) to make sure that the grid can handle
the new unit (Business Area Manager Grid, 2014). EC-A-Grid has the option to refuse an
Trimble NIS is a Network Information System with integrated GIS-functions and functions for documentation
handling (Tekla, 2014a). It includes a number of connected modules (Tekla, 2014a) where Trimlbe DMS is the
Distribution Management System that can handle the switching state of the electricity distribution system among
others (Tekla, 2014b).
2
31
installation in order to reinforce the grid (Responsible of Sales, 2014). If a customer wants to
decrease the processing time of the application, EC-A-Grid can be contacted by phone or email
prior to the installation (Responsible of Sales, 2014). When the application is approved the
technical information from the application system is being transferred automatically to the NIS
and the customer information is being transferred automatically to the billing part of Lime
(Responsible of Sales, 2014). Lime is EC-A’s customer management system, used by multiple
actors, (Customer Relations, 2014b) in which the possibility to connect documents to a facility or
a customer exists (Power Engineer, 2014). Documents that are not directly linked to a customer
or facility are stored in a folder structure on a common server.
5.4.3 The handling of information that needs to be dealt with if something happens
When the power output of an electricity production unit or electricity heating unit are changed a
certified electrician is required (Responsible of Sales, 2014). Consequently the web based
application system is used for this too and the procedure for approval is the same as for new
installations. Furthermore the customers have the right to, once a year, change their subscribed
power (Customer Relations, 2014b). This notification is sent with email to EC-A-Grid and then
transferred into the customer management system manually.
The production units of EC-A notifies EC-A-Grid about their maintenance plans and so EC-AGrid can plan its own maintenance accordingly (NOC Engineer, 2014a). Similarly EC-A-Grid
notifies EC-D of larger work that will affect the total consumption or shift consumption between
the different connection points (Business Area Manager Grid, 2014). EC-D is also contacted in
case of an accident that might have an effect on them (NOC Manager, 2014). This is mainly done
over the phone. The maintenance plans of the demand units are not communicated due to their
limited impact on the system (NOC Engineer, 2014a). If a larger load would disconnect from the
grid it would be noticed by the NOC though. Before the connection of a new facility the facility
tests its own equipment according to predefined standards (Responsible of Sales, 2014). EC-AGrid supplies these tests with threshold values for pre-fault and post-fault short circuit capacity
(Business Area Manager Grid, 2014). The compliance is only investigated before the installation
and no further investigation is done during operation of the facility as long as no problem occurs
(Measuring Responsible, 2014a). EC-A-Grid is responsible for the infrastructure until the
connection point and may conduct tests on it (Responsible of Sales, 2014). EC-A-Grid owns the
equipment to perform these tests (Business Area Manager Grid, 2014).
Equipment for automatic disconnection is installed in the grid which automatically disconnects
areas in case the frequency drops (NOC Manager, 2014). EC-A-Grid also has a plan for how and
in which order the disconnection of different loads is to be conducted, if SvK would give the
order. This order would come through telephone in case of serious frequency problems. In case
of compliance issues, EC-A-Grid has the possibility to remotely disconnect 55000 of their
customers individually (Measuring Responsible, 2014a).
Furthermore EC-A-Grid has the possibility to apply for derogation from parts of EI’s revenue cap
if they consider it not to be applicable for them (Business Area Manager Grid, 2014). This
possibility is not widely used today (Customer Relations, 2014b). The possibility to inform
affected groups about changed conditions with targeted information is something that EC-A-Grid
has used on several occasions though (Responsible of Sales, 2014).
5.4.4 The handling of information on scheduled basis
Once a year the outages statistics are withdrawn from the NIS (NOC Engineer, 2014a) and are
together with information regarding the amount of grid on different voltage levels reported to
EI’s system, Neon, via a login (Customer Relations, 2014c). It is possible to withdraw a lot of
32
other statistics from the NIS and its modules since a log of everything that happens in the grid,
both normal and abnormal, is kept there (NOC Engineer, 2014a). The contract between EC-AGrid and EC-D, that states the subscribed power for the coming year, is another example of yearly
communication (Customer Relations, 2014c). This contract also states the power of each energy
source present in EC-A-Grid’s grid but not the exact size and number of units. There is a
continuously ongoing dialogue with EC-D which results in knowledge being shared (Customer
Relations, 2014b) but if EC-A-Grid uses more power than contracted there is a fee to be paid
(Customer Relations, 2014a). The communication between EC-A-Grid and EC-E on the other
hand is limited to information exchange regarding delivered energy and power.
Another one of the subsidiaries of EC-A is responsible for the reception and handling of the
measurements from both the production (Measuring Responsible, 2014b) and the consumption
in EC-A-Grid’s grid (Measuring Responsible, 2014a). All of the customers have individual meters
and most of them use automatic meter reading which results in that about 80 % of the meters can
transmit values every hour. These meters can also transmit values per every 30 minutes after a
minor software change (Measuring Responsible, 2014b). The rest of the meters can only send
daily values but include the values of the hour with the highest consumption (Measuring
Responsible, 2014a). Usually the data from the meters is transferred to the central system
between 12 midnight and 6 a.m. every night. This guarantees the opportunity to contact the
meters multiple times in case of errors. The data includes active and reactive power, current,
voltage and outages. The meters that do not support hourly measurements are estimated to be
changed within five to six years (Measuring Responsible, 2014b).
Monthly EC-A-Grid sends a prognosis of the consumption in their grid for the following month
to the different retailing companies and BRPs active in their grid (Measuring Responsible, 2014a).
This preliminary prognosis is then followed by an actual outcome per customer, no later than two
months after the month of operation. When the actual outcome is transferred to the BRPs and
the trading companies it is also transferred to the NIS and its modules so that EC-A-Grid always
has an up to date image of their grid. The meter’s possibility to transfer hourly values is only used
for the 3500 customers that specifically have asked for their consumption to be determined for
every hour individually. For these customers and customers subscribing to currents over 80
amperes the values are instead transferred daily to the different actors (Measuring Responsible,
2014b)
33
34
6 The area of greatest concern
This chapter answers the first research question and provides the basis for Chapter 7 “Possible organisational
consequences” and Chapter 8 “Actions required to deal with the information handling” that follows. In this
chapter not only the area of greatest concern is presented but also two other areas that the line of business has
expressed concerns with. So firstly the concerns regarding simulation models (section 6.1) and the new role of the
demand side response aggregator is introduced (section 6.2) and finally the area of greatest concern, the information
handling, is presented (section 6.3).
The line of business has expressed multiple different concerns with the Network Codes and only a
few of these are presented here. Overall less concern has been expressed regarding the Network
codes CACM, LFCR and FCA in comparison to RfG and EB. This could partly be explained by the
different times the drafts have been available to the public. Looking at the different parties the
DSO seems to be affected more than the others in general since way more concern is expressed
regarding these aspects of the codes. For retailers the concerns are more limited. In the following
sections the three areas of concerns that have been expressed by most people are presented. A
full list of all the concerns can be found in Appendix 1.
6.1 The quantity and size of simulation models
Simulation models in different forms come up in multiple articles in the different Network Codes
and concerns regarding this have been brought up by numerous people in the line of business.
These concerns are marked with a circle around the dot in the table in Appendix 1. In DCC Grid
Planning Manager (2014) for example point out that the DSO has to simulate and estimate the
reaction of the grid. He highlights the problems that could arise when there’s a lot of temperature
controlled production facilities or DSR in the grid. When GEODE (2014) highlights the main
issues with the Network Codes for the DSO they also emphasise the need of simulation models in
DCC. The fact that the simulation is to be done in steady and dynamic state and that the cost is to
be handled by the DSO is the most disturbing. Grid Planning Manager (2014) also points out that
RfG requires the DSO to perform new kinds of simulations that are not done today which will
apply an extra administrative burden on the DSO. Power Engineer (2014) raises the question how
these simulations are to be performed. In the Network Code CACM there are also references to
simulation models. Swedish Energy Market Inspectorate (2013a) points out in their PM regarding
the impacts of the Network Code that issues have been expressed regarding that a common grid
model may lead to large changes and results in high demands on a new IT-system.
6.2 The impacts of the demand side response aggregator
The demand side response aggregator is a role that has been introduced in the Network Codes that
people in the industry have expressed both curiosity and issues with. These aspects are marked
with a star around the dot in the table in Appendix 1. For example Power Engineer (2014) states
that the aggregator is a role that needs to be assessed. Furthermore Energy Strategist (2014)
wonder if the aggregator is a role that EC-A can take or on the other hand if it is might be
economically beneficial to let and aggregator use their hydro power plants. Balance Responsible
Electricity Trader (2014) has another approach when he sees the problems that might occur
when a retailer has customers who use another company’s aggregation services. He also states the
possibility that the aggregator and retailer should be the same for all the customers and that it
might be more beneficial to get rid of the retailing customer otherwise. Analytics and Risk
Manager (2014) on the other hand sees the position of the aggregator more as a business
opportunity, for the balancing responsible companies, than as a threat. He thinks that they will be
able to determine how the aggregators working with their customers will react in certain
situations after a period of time. Furthermore he emphasises the fact that it would be beneficial
35
for the consumption planning of a retailing company if they were the aggregator themselves.
Power Engineer (2014) is also questioning whether the aggregators should do the control of the
DSR-customers without the grid company’s involvement. Planning Engineer (2014) goes even
further and expresses it as a threat if the aggregator could control the customers in the grid
without the grid company’s clearance.
6.3 The administrative burden due to increased information handling
The information handling is a concern which enforces an especially large administrative burden
on the DSO. This and also other aspects of information handling have been expressed by
multiple people in the line of business. The size of this area and all the different aspects that are
included in it makes this by far the greatest area of concern for the line of business. This can
clearly be seen in the table in Appendix 1 where all aspects that affect information handling are
marked with a square around the dot. In this section only a brief selection of these aspects are
presented.
Regarding the connection code RfG GEODE (2014) expresses the concern regarding the high
administrative burden for the DSO due to the testing of facilities during their life time. Grid
Planning Manager (2014) has a similar concern when he highlights the administrative work that
has to be done when connecting new PGMs and controlling them. Measuring Responsible (2014)
is also worried about the amount of control and regulation required for the smaller generators
since it is the same demands apply for generators between 800 W and 1.5 MW. Furthermore
Power Engineer (2014) raises the question for both the Network Code RfG and DCC regarding
what the DSO’s responsibilities are when it comes to newly connected facilities and controlling
them. Also Swedish Energy Market Inspectorate (2013c) recount for a large DSO’s concern
regarding the fact that the DSO should ensure the compliance of its customers and take care of
derogations and information. Planning Engineer (2014) points out that the role of the DSO looks
more like that of an authority.
Also in the operation codes there are concerns regarding communication and information
handling. GEODE (2014) starts by emphasising that one of the DSO’s main issues is the
provision of active and reactive power. Grid Planning Manager (2014) breaks down the problem
by stating that the DSOs need to have real-time surveillance of production units of category B, C
or D regarding their active and reactive power and the position of the switches. This should apply
for all units not only new ones. He also highlights that all communication, including planned data
regarding maintenance etc. is to be transferred from all significant grid users to the TSO through
the DSO. Energy Strategist (2014) expresses concerns regarding the real-time information to be
acquired and transferred for all production facilities according to the Network Code OPS. He is
also concerned about the amount of maintenance and production plans to be made according to
this code. Furthermore Power Engineer (2014) raises the question regarding the maintenance
planning in OPS and what the cooperation between the different parties is supposed to look like.
Regarding the Network Code LFCR Swedish Energy Market Inspectorate (2013b), in a summary of
a stakeholder hearing, highlights a consequence for the actors in the business regarding the data
to be collected and transferred for all facilities in the frequency restoration reserve.
36
7 Possible organisational consequences
This chapter is based upon Chapter 6 “The area of greatest concern” and provides the foundation for Chapter 8
“Actions required to deal with the information handling” that follows. This chapter focuses on the possible
organisational consequences when the rules related to information handling enter into force. The chapter begins by
illustrating the information that needs to flow between different actors, according to the Network Codes, in two
different flow charts (section 7.1). Subsequently the different analytical steps that end with the generation of possible
solutions to be able to deal with the information flows are presented (section 7.2). These possible solutions are also
the possible organisational consequences.
The largest area of concern is information handling as identified in Chapter 6 and the greatest
effects of this are for the DSO. Therefore this chapter will focus on the possible organisational
consequences for the DSO when handling the imposed information flows. After the information
flows between different actors had been determined multiple solutions for the DSO’s handling of
each information flow were generated. All these generated solutions are therefore also possible
organisational consequences of the Network Codes. Which of these possible consequences that will
be factual is determined by the state of the individual company. This is further analysed in
Chapter 8.
7.1 The information flows required due to the Network Codes
As already determined the Network Codes enforce considerable amount of communication to take
place between different parties. These flows of information are presented in two different flow
charts to ensure readability, Figure 7illustrates the communication connected to production units
and Figure 8 illustrates the communication connected to the demand units. These figures
together with the description in Appendix 2 provide a complete image of the flows of
information connected to a non-transmission system connected electricity company, such as ECA-Grid.
Regarding the flow chart some data is supposed to be sent in real-time, some only in case
something happens, some only once and some information is supposed to be sent on a scheduled
basis, for example yearly. These different types of information flows are illustrated by the colour
of the arrow in the figures. Furthermore the Network Codes open up for some information that
would be flowing if the actor in one end requires it; these information flows are indicated with a
dashed arrow in the figures.
37
Info
r
Sc maio
For hedu n gath
Reqecast ling ering
ues info
ted rma
dat tion
a
ld
ra
tu
c
tru
Higher DSO
)
25
s ( 3)
M (3
PG es
m Rul
o
r f
af to
at Lis
G
m ene
pli ra
an l i
ce nfo
(1 rm
9) a
& tio
(3 n
0) (2
6)
S
Co
Compliance (5) & (12)
Structural data
(10)
Compli
ance (1
8)
Ne
w
i
Co
De Deco nsta
m
l
r
Informatio
m
p
o
n gathering lian ga iss latio
ce tio ion n
Scheduling
(5) n ( (5 (1)
Forecast info
& 3) )
rmation
(12
)
New Installation (1)
Infor
mati
on
Sched gathering
uling
Decommission (5)
Derogation (3)
General Information (9)
New Power Generating
Module (PGM) Type B
New Power Generating
Module (PGM) Type A
ro
De
n
tio
ga
Publish
NRA
)
(23
Gene
ral
New Power
Generating
Module
(PGM)
Type C
Infor
matio
n (9)
New In
stallat
ion (1)
Decomm
ission (5)
Derogation (3)
Compliance (5) & (12)
(10)
Structural data
8)
Compliance (1
DSO
Existing Power
Modules (PGM) Type B,C
or D
Compliance (5) & (12)
Compliance (18)
Derogation (3)
New Installation (1)
5)
s(
(9)
ge
n
n
o
a
ati
ch
rm
of
o
f
n
o
In
(7 )
ati
ral
ne (10) orm ) nce
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2
f
G
ta In ta ( rma
da
da rfo
al
r
al e
ctu ctur ncy p
u
u e
Str
Strrequ
F
ing
ather
tion g
a
m
r
Info
uling
Generating
Sched
Structu
ral dat
a (10
General Informa )
tion (9)
Requested data
New Power Generating
Module (PGM) Type D
(28)
Structural DS-data
1) & (22)
Derogation (2
g (35)
rin
the
ga
on
ati
Inform
Structural DS-data (29)
Availability plan for Relevant Assets (13)
Av
ail
ab
TSO
ilit
yp O
lan uta
(1 ge (
6) 15
& )&
17 (3
)
2)
ing
her
gat
n
tio
g
rma dulin
Info Sche
tion
rma
o
f
a
n
st i
dat
eca
ted
s
F or
e
u
Req
St
at
us
te
sti
ng
(6
)
Relevant Asset
Figure 7 Illustrates the information flows connected to the different types of production units. The colour of the arrow indicates type of flow; red is real-time, yellow is scheduled,
green is “in case of” and blue is data sent only one time. A dashed arrow indicates that the code opens up the possibility for the flow, but it might not exist. The number within
brackets clarifies to which objective the flow is connected. To be able to have a complete view this flow chart should be read together with Figure 8 for demand units and the
explanation of the individual arrows in Appendix 2.
38
Higher DSO
2)
Applic
ation
(4)
General Information (9)
Compliance (5) & (18)
ON/OFF
tion gathering
ma
or
Inf
M
et
er
in
g(
24
)
Frequency
Containment Reserve
(FCR) providing Unit
Demand Facilities
Gene
ral in
fo
Capac rmation (8
ity (14
)
)
Structural da
ta (11)
Derogatio
n (3)
Compliance monitoring
(34)
DSO
Compliance (5), (12) & (18)
Compliance monitoring (34)
Lower DSO
New installation (1)
Decommission (5)
Application of RPU (4)
27
)
Infor
mati
on ga
theri
n
Publish
g
6)
(2
SR
un
its
(
)
(20 0)
it on RPU (3 ring
a
& to
m
of )
or ion (19 oni
f
e
n
l i licat anc ce m 33)
ra
i
n
s(
ne App mpl plia
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o
m
G
C Co
fR
o
t
Lis
at
aD
St
ru
ct
ur
al
d
ata
(
Decom
ission
(5)
Co m
plian
ce (5
Stru
)
, (12
ctur
)&(
al da
18)
ta (1
1)
Str
uc
tu
ral
d
ering
New Installation (1)
Informa
tion gath
al
Gener
Reserve Providing
Unit (RPU)
(8)
ation
Inform
Aggregators with Demand Side Respons (DSR)
ata (28)
ral DS-d
Structu
ng (35)
on gatheri
Informati ta DS-data (29)
Structural da
encies (31)
Disconnection frequ
ant Assets (13)
Relev
for
plan
y
Availabilit
Derogation (21) &(23)
Av Ou
ail tag
ab
e
St ility (15
at
us pla ) &
te n ( 32
sti 16 )
ng ) &
(6 (1
)
7)
Demand Facilities with Demand Side Respons
(DSR)
o
ati
rm
o
f
In
TSO
ng
eri
ath
g
n
Relevant Asset
Figure 8 This figure illustrates the information flows connected to the different types of demand units. The colour of the arrow indicates type of flow; red is real-time, yellow is
scheduled, green is “in case of” and blue is data sent only one time. A dashed arrow indicates that the code opens up the possibility for the flow, but it might not exist. The number
within brackets clarifies to which objective the flow is connected. To be able to have a complete view this flow chart should be read together with Figure 7 for production units and
the explanation of the individual arrow in Appendix 2.
39
The two flow charts (Figure 7 and Figure 8) clearly illustrate the complexity of the
communication that is required by the Network Codes. In general the DSO has taken position in
the centre of the chart with multiple connections to a lot of different actors. Furthermore it is
noticeable that a majority of the actors have information flows of all different types, which
indicate that the corresponding solutions might be diverse. Additionally the PGMs of a higher
level are required to send more information than the ones of a lower, even if this might be
difficult to notice in the flow charts.
Information flows with the same name can be seen between multiple parties in the flow charts.
This means that the corresponding information flows include similar information but it does not
have to be the exact same information. An example of an information flow that is present
between numerous actors is New Installation. For a PGM type A this means that the PGM has to
fill in an installation document, provided by the DSO, which shall at least include location and
date of connection, maximum capacity and type of primary energy source. For a demand facility
with DSR the information flow is a bit different. All new facilities, connected below 1 kV need to
communicate location, maximum capacity, type of DSR, contact details and equipment
information to the DSO. These two information flows are similar in appearance but have
differences and originate from two different Network Codes.
General information is another name that is present on multiple arrows in the flow chart. For a
PGM type A this means that the PGM shall provide the DSO with real-time information regarding
status of switching devices and circuit breakers at the connection point, active and reactive power
flows and the current and voltage at the connection point. For PGM type D this information flow
also includes the status signal of FSM (on/off), scheduled Active Power output, actual value of
the Active power output, actual parameter settings for Active power frequency response and
Droop and dead band. Similar explanations to all of the information flows present in the flow
chart are available in Appendix 2.
7.2 Formulation of objectives and generation of possible solutions for
handling information
In this section are the formulated objectives, constrains, measures and possible solutions, which
are also the possible consequences, presented. The numbers within brackets in the flow charts
(Figure 7 and Figure 8) indicate which objective the flows are linked to. For example the different
new installation flows are linked to objective 1 and the general information flows from demand
facilities and aggregators with DSR are linked to objective 8. Some information flows are divided
between multiple objectives and in total there are 35 different objectives written from a DSOs
perspective. The objectives are applicable for all non-transmission system connected DSOs, just
as the flow charts.
The constrains connected to each objective are divided into two parts, the first part indicates how
many months, after the code enters into force, the legislation will be binding. The second part
specifies how EC-A-Grid handles tasks linked to the objective today. These constrains were only
considered in the evaluation of solutions when answering research question three which is
described in Chapter 8. Therefore the constrains can function as an indicator for other
companies in this stage but were not taken into account when the objectives were broken down
into measures that needs to be taken to handle the corresponding information. Most of the
measures have multiple corresponding possible solutions. All the analysis steps are presented for
objective 1 in Table 7 and objective 8 in Table 8. The analysis of the other objectives is available
in Appendix 3.
40
Table 7 This table shows the different steps of the analysis before ending up in possible solutions for the first
objective.
Objective:
1
Provide and administrate new installation forms for new PGM, DSR
and aggregators
Constrains:
 36 months
 EC-A-Grid uses a web based application system for facilities under 1.5 MW and loads
Measure:
1. Analyse and decide what information is to be included in the forms
2. Create different forms for the different types of units
3. Receive and put information from forms into a system
Solution generation:
 The resources required already exist within the company(1)
 The resources required exist with other DSOs collectively(1)
 Hire consultant to do the evaluation(1)
 May come rules from TSO of NRA(1)
 The resource required already exists within the company(2)
 Hire consultant to do the form(2)
 Use already existing system(3)
 Invest in a new system(3)
 Automatic registration(3)
 Manual registration(3)
o The resources already exist within the company(3)
o Hire a new resource(3)
Table 8 This table shows the different steps of the analysis before ending up in possible solutions for the eighth
objective.
Objective:
8
Receive general information in real-time from DSR and aggregators
Constrains:
 18 months
 EC-A-Grid have access to real-time values for the active power of some demand facilities
Measure:
1. Receive and store information automatically
Solution generation:
 Use existing data system(1)
 Develop existing system(1)
 Invest in a new system(1)
The solutions generated for different objectives are fairly similar. When the measure indicates
that a system is needed the possible solutions usually are to buy a new system, use the existing
system or develop it. Furthermore the information might be registered into the system manually
or automatically and the resources for this could exist within the company or not. If the resources
do not exist the possible solutions are to educate someone within the company or to hire
someone new, either as a permanent employee or consultant. The communication of the
information to another party can be done through an existing or new communication channel.
41
Finally some of the generated solutions focus on how to determine the details of a specific
information flow which can be done by the DSO itself or in cooperation with others. Some of the
measures also open up for the possible solution of awaiting further development in the industry.
Consequently these generated solutions are possible organisational consequences of the
corresponding objective. All of the generated solutions, presented in Appendix 3, therefore form
the possible organisational consequences of the information handling in the Network Codes for a
Swedish non-transmission system connected DSO. Which of these possible consequences that
will be real consequences are dependent on the competence and size of the staff and the systems
already in place. If a worst case scenario is assumed the consequences for the individual company
would be unbearable. To demonstrate that this scenario will not be the case for the companies
Chapter 8 will evaluate and choose which solutions that will be appropriate for EC-A-Grid and
also analyse the applicability for other non-transmission system connected companies.
42
8 Actions required to deal with the information handling
This chapter is based upon the two analysis chapters, Chapter 6 “The area of greatest concern” and Chapter 7
“Possible organisational consequences” and also Chapter 5 “An overview of Electricity Company A and its’
information handling”. It determines which of the possible organisational consequences that will be real for EC-AGrid and consequently which actions that need to be taken. Firstly an example of how the evaluation of the
different possible consequences can be conducted is presented followed by the general consequences for a nontransmission system connected electricity company. Subsequently the specific actions that need to be taken by EC-AGrid in the implementation phase divided into different action groups are presented (section 8.1). Finally the actions
belonging in the ongoing phase for EC-A-Grid are presented (section 8.2).
The solutions in this chapter were chosen together with representatives from EC-A-Grid with key
knowledge in the particular area. The solutions were evaluated individually to be appropriate for
EC-A-Grid. This process can be seen for objective 1 in Table 9 and for objective 8 in Table 10.
Table 9 This table illustrates which of the generated solutions for the first objective that are chosen, bold, and an
evaluation of why these solutions are most appropriate for EC-A-Grid.
Objective:
1
Provide and administrate new installation forms for new PGM,
DSR and aggregators
Solution generation:
 The resources required already exist within the company(1)
 The resources required exist with other DSOs collectively(1)
 Hire consultant to do the evaluation(1)
 May come rules from TSO of NRA(1)
 The resource required already exists within the company(2)
 Hire consultant to do the form(2)
 Use already existing system(3)
 Invest in a new system(3)
 Automatic registration(3)
 Manual registration(3)
o The resources already exist within the company(3)
o Hire a new resource(3)
Evaluation of the solutions:
1. Since the information requireed will be identical for all Swedish DSOs the most
beneficial would be for the DSOs to collectively have a dialogue with SvK and EI to
determine what to be included in these forms. This dialogue can preferably be dealt
with within Swedish Energy.
2. The information flow for new PGM B, C & D will not be considerable since only 7
facilities of this size is present today and the rate of establishment is not high. This
combined with the fact that the NIS handles this kind of information today it is
economical to just manually add the extra information to the system.
For all other facilities, where the amount of installations is larger, the web based
application system is already in place. the web based application system
communicates with other systems for storage can continue to be used for this.
3. Furthermore EC-A-Grid can tell the system developer of the web based application
system collectively with the other DSOs to increase the system with the extra
information required.
43
Table 10 This table illustrates which of the generated solutions for objective 8 that are chosen, bold, and an
evaluation of why this solution is the most appropriate for EC-A-Grid.
Objective:
Receive general information in real-time from DSR and
aggregators
8
Solution generation:
 Use existing data system(1)
 Develop existing system(1)
 Invest in a new system(1)
Evaluation of the solutions:
 Since real-time values are received in the DMS for the existing PGMs the DMS
should be complemented to include the same information for demand facilities
and aggregators.
As indicated earlier a multiple generated solutions, and therefore the solutions chosen for EC-AGrid too, are similar and may therefore be grouped together. The different groups, and if the
action only needs to be taken in the implementation phase or if it is ongoing, are illustrated in
Figure 9.
Implementation
Ongoing
New
Systems
Change
Existing
New
Information
channels
Human
Resources
Existing
Existing
Existing
competence
Educate
Await further
development
Dialogue
with external
Continous
registration
Continous work
Rules
determined
externally
Practice
developed
externally
Within Svensk
Energi
Figure 9 This figure illustrates the different groups of solutions chosen and if they will be conducted in the
implementation phase or if the work will be ongoing.
In general the individual actions in the implementation phase demand less resources than the
actions in the ongoing phase. This is partly because the implementation phase only last up to 36
44
months after the entry into force of the Network Codes. During the implementation phase it is also
a possibility to put together a project organisation to free extra resources for the limited time,
possibly from other parts of the organisation. In the project organisation there should be a leader
that is in charge of the implementation and drives the process forward and makes sure all the
changes are implemented in a timely manner. Even though the individual actions could be
handled by the existing organisation the total volume of new work assignments might require
extra personnel. It is not recommended to hire new personnel in the initial stage since the work
load is tightly linked with the number of RPUs, new PGMs and DSR-providing units in the
network. Consequently the work load will increase over time and for shorter periods a consultant
could be hired if needed.
8.1 Actions required in the implementation phase
The implementation phase is the time period from when the corresponding Network Code enters
into force until the point when it becomes binding law. This time period is pointed out as the
first statement under constrains in Table 7 and Table 8. The workload for these actions is
therefore limited. In the following subsections the actions required in the implementation phase
will be presented for each of the groups as indicated in Figure 9.
8.1.1 Implement new systems
To be able to handle some of the information flows the existing systems are not enough and
therefore investments in new systems are needed. Firstly a new system that can acquire
information from the DMS and send it to EC-D in real-time is needed. The information to be
acquired is the real-time data received from the different PGMs, demand facilities and
aggregators. Furthermore there is also a new system needed to send the structural data of the
distribution system to SvK in real-time. This system should acquire the structural data the NIS
and its modules and then send it. This system is fairly similar to the first one since both of these
information flows are ending up at SvK. Therefore it would be beneficial for SvK if the same
system could take care of both the flows to avoid high implementation costs. Finally a new
system might be required for receiving and sending the day-ahead values from the PGMs,
demand facilities and aggregators to EC-D. This could be costly and require a lot of extra
administrative work but should be avoided if only a login, to an existing system, is provided to
EC-A-Grid. This is further analysed in sub-section 8.1.4.
8.1.2
Perform software changes to existing system
EC-A-Grid already has a lot of different systems in place and in general some changes are required
to these systems to comply with the Network Codes. Firstly the customer management system
needs a minor change due to the fact that the DSR capacity should be included where the
subscribed power is today. Furthermore the web based application system also needs a minor
change since the possibility to supply some extra information when new installations are made is
required. The exact content of this extra information is to be defined later. The claim to the
system developer to include these possibilities, both for the customer management system and
the web based application system, can be made collectively with other users since these systems
are widely used in the line of business.
The changes to the NIS and its modules should be limited to include extra fields to be able to
handle the new information flows. EC-A-Grid needs to make sure that the NIS and its modules
can handle all of the following supplied information and make claims to the system developer to
include the extra fields needed. Firstly the NIS and its modules needs to be able to store the
information saying why a facility is not compliant and for how long it will remain so when
notified about an incident at a facility. In case a facility gets derogated from certain requirements
the possibility to include the specific behaviour of a facility in the system is also required, to
45
ensure the network analyses’ credibility. Furthermore the date of any facility’s planned test must
be stored. For all new PGMs and EC-E, the lower DSO connected to the grid of EC-A-Grid, the
DMS must be able to store real-time status of switching devices and circuit breakers at
connection point and the real-time values of the current, voltage and active and reactive power
flows.
Furthermore all RPUs must provide EC-A-Grid with information regarding which type of reserve,
their maximum capacity and maximum rate of change. If it is a frequency containment reserve,
according to the definition in the Network Code LFCR, it also needs to provide frequency
restoration data and replacement data. Consequently the NIS and its modules need to be able to
handle all of this information. There is also a considerable amount of information from existing
PGMs that the NIS and its modules need to be able to handle. This information includes capacity,
location, primary energy source, protection data, reactive power, control capability, capability of
remote access to the circuit breakers and the voltage level. Additionally the existing facilities will
supply the NIS with their frequency performance which means the frequency where they partly or
totally disconnect from the grid. Finally the DMS needs to be able to receive and store real-time
data from demand facilities and aggregators with DSR. This real-time information consists of
active and reactive power at the connection point and the confirmation of the estimated DSR
values.
8.1.3 Implement new information channels
Since the communication needed due to the Network Codes is extensive some new information
channels need to be implemented. A lot of the communication required is not continuous though
and will only occur sporadically or for a limited period of time. Furthermore the content of the
information will be quite different and it could be easy to take care of it by sending emails. Firstly
EC-A-Grid needs to implement a communication channel for sending emails regarding test
schedules of own compliance tests and the pre-qualifications and an opinion of RPUs in its
network to EC-D, the higher DSO which EC-A-Grid is connected to. An email-channel to SvK for
sending applications for derogation from own compliance also needs to be implemented. Finally
an email to all existing PGMs larger than 1.5 MW with the information they need to provide
regarding their own frequency performance must be sent.
In some cases the receiving party would benefit from having an automatic system for storing the
information. Today this is done in some cases when the receiving party use a system where the
sending party logs in and supplies the information required. Therefore a similar kind of
information system might be used for various types of data that is needed to be sent to SvK or
EI. Firstly this kind of system could be used when supplying Ei with the CBA and opinion on the
derogation applications of different facilities. Furthermore some structural data of the
distribution system should be sent to SvK. Here it would be beneficial to use a login system too
and supply the required information. A system similar to Neon that Ei uses for the same kind of
information would be beneficial. To prevent the DSOs from having to supply the same
information to multiple parties SvK could supply Ei with the information they need. The
structural data sent this way should also include the disconnection frequencies for the distribution
network’s automatic disconnection.
The structural data from demand facilities and aggregators with DSR, including forecasts, planned
power and duration of the DSR and structural data from the PGMs which is similar to what the
BRP use Cactus for today is supposed to be sent through EC-A-Grid. This information is just
going to flow through EC-A-Grid without them assessing it in any way before sending it to SvK.
Therefore it would be beneficial if the information is sent directly to SvK and that EC-A-Grid just
has the possibility to look up the information concerning them via a log in. This will limit the
46
costs for the whole system. If this solution is chosen by SvK it is vital that the information
provided includes the unit’s location.
8.1.4
Use existing information channels
EC-A-Grid communicates a considerable amount today already, as can be seen in Figure 6 and
consequently some of the information channels needed to deal with the Network Codes are already
in place. Firstly the information channel to EC-D when EC-A-Grid is doing something that affects
them can still be used. The need to inform EC-D should be included in the routines though to
make sure that it is always done. Furthermore the customers with DSR who shall inform about
capacity changes can use the same information channel as the one they would use for changing
their subscribed power. The NOC gets some faults reported over the phone and this information
channel should also be able to deal with notifications regarding incompliance from different
actors in the grid. Finally the way of notifying actors of changes to the rules is mainly done
through mail today and the changes due to the Network Codes should be handled the same way.
8.1.5 Use the existing competence within the company
In this sub-section the new work assignments that can be handled by the already existing
competence within the company are presented. These assignments are mostly similar to already
existing tasks or are tasks that are not too extensive. Firstly the competence for examining
whether or not there is a need to file a derogation application for derogation from own
compliance exists. If the derogation gets accepted one or more of the actions explained in this
section could be affected since they might not be required anymore. Secondly the competence for
the creation of forms for structural data and frequency performance of all existing PGMs and
RPUs and the reception of this information already exists within the company. The new
information that is to be included in these forms, as a result of the Network Codes, might be
determined collectively within Swedish Energy which is discussed in subsection 8.1.9. If the
information to be included in the forms already is decided the creation of the actual forms should
be fairly easy. Furthermore which documents required and which of them to make publicly
available could also be defined through Swedish Energy and thereby limit the handling within the
company.
Some of the new work assignments due to the Network Codes are not so extensive and require no
special competence. A work assignment that fit this description is the structural data received
from existing PGMs and RPUs that needs to be registered in the NIS manually. This data includes
information regarding installed capacity and other general information. The information
regarding the frequency performance of the existing PGMs also needs to be register in the NIS
manually. Since no special competence is required this could be conducted by a person who
could be hired for a shorter period of time to ease the workload for the employees, preferably a
temporary resource during the summer period. Though the number of existing PGMs and RPUs
are limited in number and therefore it might be more beneficial to use already existing employees
even for these assignments.
8.1.6 Further education for employees to be able to deal with new assignments
Some of the new work assignments require special competence that is not present within EC-AGrid today. Therefore some employees have to acquire certain extra knowledge through further
courses. This includes the knowledge about how to supervise and possibly carry out compliance
tests and simulations on new PGMs type B, C or D, demand facilities and aggregators with DSR
and EC-E has to be acquired. Furthermore the knowledge of how the compliance testing on ECA-Grid’s own network is to be conducted has to be attained. Finally the organisation has no
experience of conducting CBAs. Consequently some new competence has to be acquired through
education. This competence includes the examination if there is a need to conduct a CBA or not,
47
when a unit has applied for derogation, and the conduction of the CBA and opinion on the
derogation from all new PGMs and DSR-providing units.
8.1.7 Rules to be determined by an external party
Several information flows go directly from EC-A-Grid to SvK or will end up there after passing
through EC-D. Since SvK will receive this information from all Swedish DSOs it is fair to assume
that they would want to receive it in a standardised way. Therefore an assumption is made that
SvK will supply the DSOs with a template of the specific information required including the
format in which it is to be sent. This means that EC-A-Grid should await further instructions in
certain areas. This concerns the content of the application forms for RPUs and which
information is required when EC-A-Grid is applying for derogation from own compliance.
Furthermore SvK should determine how and what information is to be reported yearly regarding
frequencies for automatic disconnection. Finally it would be beneficial if SvK defines a standard
protocol to be used for all the real-time data that is to be sent to SvK, regarding both the
structure of the own network and the facilities in it.
The derogation applications for all new PGMs, type A, B, C and D, and DSR-providing units in
Sweden will be handled by EI. Therefore one can assume that Ei also would be interested in
supplying a template for what is to be included in the opinion and how the CBA should be
conducted by the DSO. Consequently EC-A-Grid should await a statement regarding this from Ei
since they could use the template to analyse which expertise is required. Since EC-D is supposed
to monitor the compliance of EC-A-Grid they decide which information is required from EC-AGrid and which tests EC-A-Grid should carry out. Therefore it would be beneficial for EC-A-Grid
to have a dialogue with EC-D in an early stage to clarify the content of this decision.
Finally there is a paragraph in the Network Codes (EB art58(1)) that states that SvK should
determine the exact time period for which the imbalance is to be settled within two years. This
time period cannot be longer than 30 minutes which probably implies that all units need to be
measured in the same time frame. This paragraph will not have a direct effect on EC-A-Grid’s
information handling but probably a consequential law will be legislated which will result in
consequences. If this consequential law states that the energy use of all units should be known
within a 30 minute time frame EC-A-Grid would need to conduct a minor software update in a
majority of the meters. The rest of the meters will need to be changed. Furthermore the existing
system can handle the new information but since the information flow will increase in size
significantly the system will need to be updated.
8.1.8 Practice determined by an external party
The Network Codes indicate indirectly that a lot of systems and equipment used today will be
sufficient to carry out the enforced tasks. However this might change when different external
parties change the praxis. Currently it seems like some of EC-A-Grid’s systems can be used
without alterations. This concerns the web based application systems connection to the NIS that
handles the information from installing new and changing existing small facilities such as PGMs
of type A and DSR-providing units. Furthermore the folder structure should also work without
alteration in its storage of compliance test done for the own network. The applications of
derogation received from facilities in the grid including the CBAs and opinions made for these
might be stored in the customer management system. Also the application forms sent by RPUs in
own or EC-E’s grid and the test schedules sent in by different facilities should be able to be stored
without alterations in the customer management system.
Regarding the equipment needed to monitor the compliance EC-A-Grid’s equipment should be
sufficient since it is a new concept and it is up to EC-A-Grid to define whether or not to monitor.
48
It is vital to continuously evaluate the need for monitoring to ensure that the different parties are
compliant. This might therefore change the need for equipment later. Furthermore EC-A-Grid
has a lot of equipment to test its own network so for the time being the equipment should be
sufficient to conduct compliance tests but it is not exactly clear until EC-D comes with a specific
demand for a compliance test. Regarding the equipment to receive real-time information from
new PGMs type C and D the possible establishment of these units will determine when an
investment is needed. Today EC-A-Grid does not have the right equipment to receive this
information but since power plants larger than 10 MW rarely are constructed in EC-A-Grid’s area
it is advantageous to deal with this issue when such a facility is planned.
Finally there is a paragraph in the Network codes stating that SvK can gather the information they
need from different actors. This paragraph in the code is probably a precaution if the data needed
by SvK is not mentioned in any other paragraph. Information flows due to this paragraph are
probably tightly linked with other paragraphs and can, if they appear, be dealt with in the same
way as that paragraph. Therefore it is better to wait until SvK demands information and then
solve the situation and possibly implement it in the correct routine.
8.1.9 External dialogue through Swedish Energy
In multiple cases the Network Codes state that the DSOs shall define what information is to be
included. The recommendation is that EC-A-Grid deals with these definitions in cooperation with
the other DSOs, preferably through Swedish Energy. Furthermore all the cases where the DSO and
the TSO should cooperate in the decision making should preferably be dealt with within Swedish
Energy. The decisions to be made in Swedish Energy include which data and information that has to
be sent in when installing a new PGM or DSR-providing unit. The organisation of the structural
data that is to be sent by new and existing PGMs and DSR-providing units through the chain of
DSOs to the TSO is to be agreed upon by the DSOs and TSOs together. This communication
could preferably be handled through a log in system which is treated in sub-section 8.1.3. To
make sure that this is the case the discussions should be handled by Swedish Energy. The level of
detail of the yearly notifications of the DSR capacity should preferably be the same all over
Sweden and determined within Swedish Energy. The same goes for which documents are to be
made publically available by the DSOs.
Finally Swedish Energy should put pressure on the external parties that will determine the rules and
practices dealt with in sub-section 8.1.7 and sub-section 8.1.8. This is to ensure a beneficial
outcome of the decisions where the DSO’s perspective is accounted for. The work done within
Swedish Energy could preferably be conducted in groups put together with people from different
DSOs. For EC-A-Grid this could mean that one or more employees would participate in these
groups when ensuring the right level of detail of the communication.
8.2 Actions required in the ongoing phase
The ongoing phase is the time period from when the corresponding Network Code becomes
binding law until further notice. The time when the Network Code becomes binding law is
indicated by the amount of months after the entry into force which is the first statement under
constrains in Table 7 and Table 8. The workload for these actions is therefore continuous. In the
following subsections the actions required in the ongoing phase will be presented for each of the
group as indicated by Figure 9.
8.2.1 Continuous registration into different systems
In some cases the continuous information flows need to be registered into different systems but
can still be dealt with manually. This is because these flows will only occur sporadically so the
investment into an automatic system will not be likely to pay off. Firstly this is the case for
49
registering new information and changes to it from new PGMs of type B, C or D into the NIS.
Also changes in the DSR-providing units’ capacity can be done manually into the customer
management system. When a facility has notified the NOC that it is not compliant this needs to
be registered in the NIS.
In some cases another employee should be notified in association with the registration to be able
to conduct an assessment. Since the registration is done manually the notification of the
appropriate person can also be done manually. This is the case for the registration into the NIS of
the specific behaviour of units derogated from the Network Codes and the following CBA that
needs to be done. The person who is going to do the CBA can be alerted manually. Furthermore
information from the application forms from RPUs will be registered into the NIS and the
notification of the employee doing the network analysis is performed in the same way. Finally the
registration of the test schedules for compliance tests of new PGMs of type B, C or D into the
customer management system and the test date into the NIS, followed by alerting the employee
doing compliance tests, should be done in a similar fashion. The person responsible for
performing the compliance tests should also withdraw information from the logs once a month
to determine if there are any faults that affect the compliance of the units in the grid.
8.2.2 Continuous work
The Network Codes bring multiple new work assignments that are more or less similar to tasks
already conducted within the company. One of these new work assignments are the handling of
the derogation forms and the forms for application of RPUs which should be a routine thing,
given that the forms are satisfactory created. Also the handling of the notification of changes to
the test schedule and technical data from different units is a new assignment. Additionally the
tasks of sending yearly information regarding frequencies for automatic disconnection and the
information regarding EC-A-Grid’s grid and new generation capacity to the TSO are new. An
assignment that is relatively similar to how it is done today is the notification that has to be made
to EC-D when EC-A-Grid wants to make changes that affect their compliance. Finally the task of
conducting a network analysis when doing the pre-qualification of a RPU is new.
Some new work assignments are somewhat more complex than the others. One example of this
is the monitoring and the possible conducting of compliance tests and simulations of new PGMs
of type B, C or D, DSR-providing units and EC-E which can be performed if EC-A-Grid deems it
necessary. If EC-D requires it, EC-A-Grid will need to carry out compliance tests of their own grid
too. Finally EC-A-Grid will need to conduct CBAs and make opinions on the derogations applied
by different facilities.
8.3 Actions of general nature that facilitate the transition
When combining all the actions there are some general suggestions that will further ease the
transition but that is not exactly connected to an individual action. First of all it would be
advantageous to constantly have an employee responsible for the surveillance of the Network
Codes since they still are in the development stage. This employee should also be in charge of the
implementation process and make sure relevant changes are made in a timely manner.
Accordingly should not any investments in new systems be made before they enter into force. It
might be beneficial to postpone the investments further since SvK or even EC-D might clarify
certain aspects. On the other hand it will be useful to ease the transition and ensure compliance
of the affected parties by communicating the provisions in the Network Codes once they are
finished.
The day-ahead values that are suggested to only be accessed by EC-A-Grid through a log in
system are not important for the operation of the grid today. In the future a system that can
50
acquire this information from the login system and store it in the NIS might be required in order
to perform up to date network analyses. These analyses might increase in number in order to
determine if the grid can handle the production and DSR the upcoming day. Otherwise EC-AGrid might end up in dimensioning the grid for full production and consumption which probably
not is economically rational.
The analysis in this chapter is based on the current practices at EC-A-Grid and other DSOs of the
same size should have similar equipment, information channels and systems in place. All actions
presented could not be generalized to other companies but should merely be seen as an example.
Certain actions though are directly applicable for all non-transmission system connected
electricity companies, regardless of size, such as the ones concerning continuous work or rules to
be determined externally. Also the general analysis in the beginning of the chapter, concerning
the work load in the implementation- and the ongoing-phase and the suggestion that a project
organisation should be put together with a project leader, can be seen as applicable for all nontransmission system connected companies. The importance of the right leader is also emphasised
by Nahavandi (2014).
The chapter in total provides an indication of what needs to be done for other companies of
approximately the same size and without Relevant Assets. Considerably smaller companies might
have quite different systems in place and also have increased incentive to apply for derogation
from one or more of these actions. The indication of what needs to be done is therefore less
helpful for these smaller companies. Companies that have Relevant Assets in their grids need to
further investigate the objectives linked to those information flows.
51
52
9 Discussion
This chapter is based upon all the previous chapters and provides a foundation for Chapter 10 “Conclusion”.
Firstly a discussion is held regarding the results (Chapter 6-8) position in comparison to Chapter 2” Background”
and Chapter 3” Change management theory”. This is followed by a discussion on how the chosen method has
influenced the outcome (section 9.1). Following this discussion the ISM is analysed and possible improvements
suggested (section 9.2). Finally an investigation if the answers are generalizable for other companies than specified
in the aim is presented (section 9.3).
The greatest difference between the current conditions and the scenario that the Network Codes
enforce is the position of the DSO. In the new scenario the DSO has a central position in the
middle of the communication with interactions with a majority of the other actors on the
electricity market. Furthermore the DSO gets a more administrative and controlling role with new
commitments that partly have been handled by other actors previously.
Paton & McCalman (2008) highlight the importance of staying ahead of the game in order to
survive. Nahavandi (2014) even takes it as far as to suggest that the very survival of the
organisation is dependent on how well it can adapt to change. They consequently support the
necessity of conducting this thesis even though all details are not completely outlined in the
Network Codes yet. The flow charts are in themselves a contribution to the line of business in their
way of concretising the problem when visualising a considerable amount of information. The
flow charts beneficial properties are also highlighted by Paton & McCalman (2000).
The information handling was broken down into objectives to further concretise the problem
whose importance Abrahamsson (2000) also emphasises. Abrahamsson also discusses the risk of
people not acting rationally in the process which was minimised by involving several employees
from EC-A-Grid during multiple stages. This also minimised the resistance towards the change
and maximises the knowledge about it in the work force which also is stated by Paton &
McCalman (2000).
9.1 The influence of the method
Overall the general results and analyses were not greatly influenced by company specific details
and are therefore applicable for all Swedish non-transmission system connected electricity
companies. But different results may have been achieved if another method would have been
used in certain stages. Firstly a more complete picture, from the investigation of the concerns,
would have been achieved if more companies would have taken part. Due to the limited amount
of time, companies of approximately the same size were prioritised. The great knowledge about
the Network Codes from some of the interviewees resulted in eliminating the risk of any concerns
being missed. Additionally the usage of a definition not based on the number of concerns might
have resulted in another area being greater. Other areas of concern might for example be
considerably more costly. But the definition used in this thesis forced the most complex area,
which was hard to grasp, to be chosen. Therefore this definition contributed the most to the line
of business, when determining the details of the information handling.
The ISM model was chosen even though it is most suitable for hard problems and this problem is
somewhere between hard and soft. Another model could possibly have given different results but
probably it would mostly have influenced the working procedure. The authors are generally
content with how this model functioned and agrees with Paton & McCalman (2000) that the
model provides a good result even for non-hard changes and trust the resulting actions are
appropriate for EC-A-Grid.
53
If another way of grouping the different types of actors would have been used the perspective of
another actor might have seemed more important. But since the DSO was the actor named in the
most diverse contexts and Network Codes their perspective was at least the most complex one
which ensured the investigation to be beneficial for the industry.
The usage of another company than EC-A-Grid to determine the specific actions required would
have had an influence on the result. If a smaller non-transmission system connected electricity
company would have been used the results probably would have been applicable for all of these
companies to a greater extent. EC-A-Grid’s considerable size among these companies and the
presence of all functions facilitated the possibility to acquire the right information within the
company though. This enabled the thesis to be extensive and some solutions to be generated
through the knowledge about a production company for example. Certain actions though are
directly applicable for all non-transmission system connected electricity companies, regardless of
size, such as the ones concerning continuous work or rules to be determined externally.
Another possibility of changing the method would have been to use more than one company
when specifying the actions. This would have resulted in the actions being applicable for other
Swedish non-transmission system connected electricity companies to a greater extent. The use of
one company is justified by the fact that it provided a good indication without being an
overwhelming effort. To determine the exact consequences for another company they would
have needed to do their own investigation regardless of the number of companies in our
investigation. With the method used all non-transmission system connected electricity companies
know approximately the size of the problem and have the possibility to plan their next step. Since
only the last stage, were the actions are determined, was company specific other companies with
the same conditions only would have to redo this stage to determine the actions required for
them. Consequently this thesis provides a substantial contribution to the line of business even
though the actions are specific for EC-A-Grid.
9.2 The development potential of the ISM
Using the ISM on the changes enforced by the Network Codes was a way of testing its performance
with complex changes. The first thing that struck the authors was the difficulty to understand
how to apply the ISM to the specific problems. The lack of relevant examples introduced the
feeling that the model was not applicable in this case. But when the working procedures had been
determined the model worked satisfactory. There is a potential that the model is not used
completely as intended in this thesis due to the difficulty to understand how to apply it. Overall
the structured way of working introduced in the model is suitable for this complex problem. In
order to always be able to understand previous decisions and potentially re-evaluate them when
moving through the different stages of the model it is important that all working documents are
stored in a structured way.
In this thesis no prioritising of the objectives was done, since all objectives had to be fulfilled,
even though the importance of prioritising was stated in the model. The model should state that
it is not always beneficial to prioritise due to the diversity of possible objectives. In this thesis the
key actors were partly involved in multiple stages but this is not always possible due to lack of
resources. If a qualitative evaluation method is used, like in this thesis, the actors’ involvement in
the evaluation phases is according to the authors of great importance in order to choose the best
solution. To get them to partake in this process is also a way of minimising resistance to the
change. This involvement is especially beneficial when the solutions are fairly easy to generate
and harder to evaluate.
54
So in order to improve the ISM it might be beneficial to clarify how to actually conduct the
different stages and exemplify that with more complex examples. Furthermore the possibility to
involve key actors in the evaluation stage should be emphasised. But in general the ISM is a very
suitable method for dealing with this problem, especially in the way it was interpreted in this
thesis.
9.3 The thesis generalizability
Since the Network Codes are to be valid for all members of the European Union the results and
analyses aspire to be generalizable for all electricity companies in Europe. Europe is a diversified
market though with rules that vary between different countries and therefore the companies’
preconditions are different. Furthermore the preconditions affect which paragraphs in the
Network Codes that apply which led to the necessity of this thesis to focus on non-transmission
system connected electricity companies. This section will examine how well the results and
analyses are generalizable for other companies.
Generally all European electricity companies will face the same challenges due to the Network
Codes. Consequently the usage of the ISM will be beneficial for all of these companies when
determining the need for specific actions. Therefore the change management perspective of this
thesis is generalizable to a great extent even though not all of the results are.
The concerns presented in this thesis are applicable for all European electricity companies since
concerns from the European organisations GEODE and Eurelectric were taken into account.
The fact that the concerns were not evaluated against the current conditions in Sweden further
support this statement. Some concerns that obviously were linked to the DSO being transmission
system connected were excluded and consequently some more concerns than the ones presented
in this thesis exist for transmission system connected electricity companies.
The flow charts (Figure 7 and Figure 8) are applicable for all non-transmission system connected
electricity companies in Europe since only parts linked to transmission system connected DSOs
were left out. Consequently they are not totally applicable for the transmission system connected
electricity companies. For these companies more information flows would have been present in
the flow charts and the once presented might have different content. Furthermore there is a
possibility that minor differences will exist between countries due to different interpretations of
the Network Codes by TSOs and DSOs in the corresponding countries. An example of this is the
information flows going through the DSO to the TSO that could go directly to the TSO instead.
The chosen solutions in the evaluation process were based on the current practises at the
Swedish non-transmission system connected electricity company EC-A-Grid. Consequently this
primarily offers an estimation of the workload for other Swedish companies but to some extent
also for companies in other European countries. The recommendation to work together with
other DSOs and the TSO is an example of an action that is valid all over Europe. In order for a
company to find out if the actions are applicable they will need to compare their practises with
EC-A-Grid. Accordingly the actions presented offer an indication for companies with similar
practises to EC-A-Grid. The general conclusion, that the combined work load might be too big
even though the individual assignments are not, should still stand for all European electricity
companies.
55
56
10 Conclusion
In this chapter the most important conclusions to the different research questions are presented. Additionally the
need for further research in this area is highlighted.
To reach EU’s climate and energy targets an integrated electricity market is considered to be
required (Klessmann, et al., 2011), (Boie, et al., 2014), (Becker, et al., 2013). For this reason the
European Commission decided to form a set of rules for a single market in Europe (ENTSO-E,
2013b). Concerns regarding what the Network Codes’ actual consequences are have been expressed
within the line of business (Swedish Energy, 2013a). Therefore the purpose of this thesis was to
determine and furthermore illustrate the consequences the Network Codes will have, in current
version, for a Swedish non-transmission system connected electricity company. In highlighting
the consequences that the Network Codes enforce it offers a contribution to the line of business by
making it possible for the electricity companies to plan for the future and possibly affect the
development of the Network Codes. In further extent, by illustrating the complexity more clearly
way, it also contributes to the implementation of an integrated electricity market and thereby also
contributes to the 2020-targets.
As mentioned the development of the Network Codes has caused an increasing amount of distress
within the line of business. The complexity of the rules further enhanced this which can be seen
in the numerous concerns expressed by different individuals in the electricity industry. The
concerns raised were diverse but a majority of them might be incorporated into either of the
following groups; simulation models, demand side aggregator and information handling. Out of
these groups information handling was by far the area of greatest concern with issues primarily
connected to the DSO.
The flow charts (Figure 7 and Figure 8) clearly present the increased information handling
enforced by the Network Codes when the DSO becomes a central piece in the communication. The
numerous possible organisational consequences of this are of a diverse nature. To deal with this
increased information handling, new systems might be required and existing systems could be
used with or without adaption. Other possible consequences are the hiring of new personnel, the
education of existing personnel or the use of already existing competence. Furthermore the
Network Codes open up for the possibility for the DSO to define certain details which may be
conducted individually or in cooperation with other DSOs. Which of these possible consequences
that will affect a specific DSO is highly dependent on the routines and systems already in place
within the company and the country.
The consequences were exemplified on EC-A-Grid and overall the actual actions required were
not as significant as the line of business might have feared since the information channel was
already in place for multiple cases. However EC-A-Grid still needs to take numerous actions
before all of the new information can be handled. Primarily a new system is required to handle
the real-time values transferred to EC-D and SvK and some of the existing systems need to be
developed. Furthermore the combined extra work load might require EC-A-Grid to hire more
personnel and some subjects need to be further discussed within Swedish Energy. These
consequences should be fairly similar for companies of approximately the same size since the
systems in place and organisational resources are related to the size. Accordingly the
consequences for smaller companies might be far more extensive and costly since the same rules
apply for them. Companies with Relevant Assets in their grids will also experience larger
consequences. All companies need, however, to conduct an individual analysis to determine
which specific actions are required for them.
57
This thesis has clearly shown the complexity that the Network Codes bring to an electricity
company and has clarified it from the DSO’s perspective on the information handling. This
perspective is only part of the total set of rules enforced by the Network Codes which indicate the
complexity of the regulations. Consequently further research is needed to determine the
consequences the Network Codes will have on the electricity business as a whole. This further
research applies for the other areas of concern presented in this thesis, simulation models and
demand side aggregators, as well as other areas such as the technical aspects for new production
units. Furthermore the PGM owners’ perspective on information handling should be further
investigated.
58
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64
Appendix 1 - Concerns
Table 1 This table shows the different group of concerns expressed by different stakeholders for the different Network Codes; the number of stakeholders expressing a specific
concern for each group is within brackets. The symbol around the dot indicates which area of concern the group is connected to, circle is for simulation models, star is for the new
role of the aggregator and the square is for information handling. For information regarding a specific group concerns see the following page.
CACM
FCA
EB
RfG
Grid
 Pre-qualification &  Production Control (7)
monitoring DSR (4)  Simulations (2)
 Market risk (3)
 TSOs power (1)
 DSR measuring time
(2)
 Disconnection of
DSR (2)
Production
 New role aggregator  Administration due to
compliance (6)
(1)

FRT (3)
 30 min reporting (2)

Frequency range (3)
 New market? (1)
 Voltage Range (1)
 Other (3)
 Grid model
(2)
Retailing
 Different
Operation (1)
 Data format
(1)
DCC
OS




 Communication
 Communication  Real time
SGU->DSO data from
of plans (5)
FRR (1)
>TSO (4)
 Compliance
monitoring SGU (3)
Compliance monitoring (6)
Reactive Power (3)
Simulation (2)
Stronger grids (1)
 Communication
SGU -> TSO (4)
 Possible reactive
power trade (2)
 Real time data (1)
OPS
 Maintenance
planning (4)
LFCR
 Demands
on FRR (1)
 New role Aggregator
(5)
 New role BSP (1)
I
CACM



Grid model: Concerns regarding different aspects of the Grid
model was expressed by Power Engineer (2014) and other
stakeholders according to the Swedish Energy Market
Inspectorate (2013a). The grid model is a common model over
the distribution grid to be provided by the DSO.
Different Operation: Concerns regarding this was expressed by
Power Engineer (2014). Different operation is the question
whether CACM will result in any new operation for the parties
on the market.
Data Format: Balancing Responsible Electricity trader (2014)
expressed concerns regarding the data format. Data format
focuses on the question regarding the data format in which the
information from retailer will be sent. It also includes the
concern regarding the problems that might occur when
implementing a new trading system.
FCA

No concerns were expressed regarding this Network Code.
II
EB




Pre-qualification & monitoring DSR: Concerns regarding
different aspects of this were expressed by, Measuring
Responsible (2014), Grid Planning Manager (2014),
Lundqvist (2014) and CEDEC, et al. (2014). Prequalification & monitoring DSR refers to the fact that new
DSR customers need to be monitored in real time and prequalified. This also covers the fact that DSOs need to know
if the grid is strong enough to handle a specific customer.
Market risk: Concerns regarding the market risk were raised
by Planning Engineer (2014), CEDEC, et al. (2014) and
Lundqvist (2014). The market risk refers to the possibility
for the DSO to pay for the market risk when a DSR cannot
deliver their service due to failures in the DSO’s grid. This
also involves the possibility for it being cheaper for the
DSO to pay for the market risk than to upgrade the grid.
DSR measuring time: Power Engineer (2014) and Lundqvist
(2014) expressed concerns regarding the measuring time.
The measuring time is the time within which the DSRcustomers need to be measured and also the question if the
meters can handle it.
Disconnection of DSR: Concerns regarding this were
expressed by Planning Engineer (2014) and Power
Engineer (2014). The disconnection of DSR covers the
issue regarding who is in charge of the actual
disconnection of the DSR-customers through an
aggregator. To let the aggregator do the disconnection
without the grid company’s knowledge could be a threat.





New role Aggregator: Energy Strategist (2014) expressed
concerns regarding this new role. This group refers to the
possibility for the production company to take the role as
an aggregator or let their production facilities be controlled
by one.
30 min reporting: Concerns regarding this were expressed by
Energy Strategist (2014) and Lundqvist (2014). 30 min
reporting refers to the measuring of electricity and
calculation of imbalance for parties on the balancing
market.
New market: Concerns regarding the new market were
expressed by Power Engineer (2014) and refers to the
possibility that the market referred to in EB involves new
opportunities in comparison with the one already in place.
New role Aggregator: Concerns regarding this role were
expressed by Lundqvist (2014), Balancing Responsible
Electricity Trader (2014), Business Development Manager
(2014), Analytics and Risk Manager (2014) and Power
Engineer (2014). This group of concerns refer to the
possibility for the electricity retailing company to take the
role of aggregator both to make profit and avoid getting
into difficulties with consumption planning etc.
New role BSP: Concerns regarding this role were expressed
by Business Development Manager (2014) and refers to
the possibility for the retailing company to take the role of
BSP.
III
RfG





Production Control: Concerns regarding this were expressed by
Lundqvist (2014), GEODE (2014), Business Developer (2014),
Power Engineer (2014), Grid Planning Manager (2014),
Measuring Responsible (2014) and a large DSO according to
the Swedish Energy Market Inspectorate (2013c) This group
of concerns refers to the compliance control of the production
facilities in the grid including derogations and control and all
kind of communication connected to this, both to and from
production facilities.
Simulations: Concerns regarding simulations were brought up
by Power Engineer (2014) and Grid Planning Manager (2014).
Simulations refer to different aspects regarding the grid
simulations to be performed by the DSO.
TSOs power: Concerns regarding this was expressed by GEODE
(2014) and refers to the issue of the TSOs unnecessary
increasing power over the DSO in matters like contracts etc.
Administration due to compliance: Concerns regarding this
administrative burden were highlighted by Power Engineer
(2014), Grid Planning Manager (2014) , GEODE (2014),
Lundqvist (2014), Eurelectric (2013) and a large DSO
according to Swedish Energy Market Inspectorate (2013c).
This group of concerns refers to the amount of administration
that the generation facilities have to withstand when dealing
with the demands in RfG.
FRT: Concerns regarding the Fault Ride Through were
emphasized by SvK according to the Swedish Energy Market
Inspectorate (2013c), Lundqvist (2014) and Eurelectric (2013).
These concerns focus on the ability of a generator to
withstand a loss of electrical tension for 150 ms and the
simulation of this matter.



Frequency range: Concerns regarding this were expressed by
Eurelectric (2013) and GEODE (2014) and a large DSO
according to the Swedish Energy Market Inspectorate (2013c).
The group frequency range is referring to the possible need to
change generators due to the new frequency range within
which the generators are not allowed to disconnect from the
grid.
Voltage Range: Issues regarding this was expressed by
Eurelectric (2013) and is a similar issue to the frequency range
but refers to the rules regarding the voltage range within which
the generator must remain connected to the grid instead.
Other: This is a group of concerns unrelated to the other ones
and were expressed by Eurelectric (2013). This group contains
concerns regarding cyber security threats, the retroactive
implantation of the RfG rules and the classification of the
significant grid users.
IV
DCC




Compliance monitoring: Issues regarding compliance monitoring
were presented by Grid Planning Manager (2014), Measuring
Responsible (2014), Lundqvist (2014), Power Engineer (2014)
Planning Engineer (2014) and a large DSO according to the
Swedish Energy Market Inspectorate (2013f). This group of
concerns refers to the high administrative burden when the
DSO need to control assure compliance of some significant
grid users. This also refers to the communication associated
with this, both to and from the DSO.
Reactive Power: Concerns regarding the reactive power was
expressed by Lundqvist (2014), GEODE (2014) and a large
DSO according to the Swedish Energy Market Inspectorate
(2013f). This group of concerns refers to the amount of
reactive power allowed to be exchanged at different
connection points and whether or not this enforces parties to
invest in capacitors.
Simulation: Concerns regarding simulations in DCC were
highlighted by GEODE (2014) (GEODE, 2014) and Grid
Planning Manager (2014) (Grid planning manager, 2014).
These concerns refer to TSO’s right to demand simulation
models from DSO in steady and dynamic state.
Stronger grids: This issue was highlighted by Planning Engineer
(2014) and it refers to the possible need to have stronger grids
to deal with all the DSR connected to the grid.
OS





Communication SGU->DSO ->TSO: Concerns regarding this
communication line was expressed by Grid Planning Manager
(2014), GEODE (2014), Power Engineer (2014), and
Lundqvist (2014). This group of concerns contain to the
DSO’s need to communicate all sorts of data from the
Significant Grid Users to the TSO. This involves active and
reactive power in real time, planned consumption and
maintenance and the question regarding how this is supposed
to be done.
Compliance monitoring SGU: Concerns involving this has been
highlighted by Lundqvist (2014), Measuring Repsonsible
(2014) and Grid Planning Manager. This group covers the fact
that the DSO should have real time surveillance of the SGUs’
active and reactive power and the position of switches. This
also involves issues regarding the control and measurement.
Communication SGU -> TSO: These group is made of concerns
expressed by EC-B according to the Swedish Energy Market
Inspectorate (2013e), GEODE (2014), Grid Planning Manager
(2014) and Energy Strategist (2014). The concerns in this
group refers to the production facilities’ need to send real time
data regarding active and reactive power to TSO, possibly
through DSO, and the possibility for the TSO to demand
different amounts of data from different users.
Possible reactive power trade: Concerns regarding this possibility
was highlighted by the Swedish Energy Market Inspectorate
(2013e) and Power Engineer (2014). This group of concerns
refer to the fact that OS could open up for the possibility to
trade with reactive power.
Real-time data: Concerns regarding real-time data was expressed
by Energy Strategist (2014) and refers to the fact that
production companies need to have information of all their
production in real time.
V
OPS
LFCR



Communication of plans: Grid Planning Manager (2014),
GEODE (2014), Power Engineer (2014), Lundqvist
(2014) and EC-C according to the Swedish Energy
Market Inspectorate (2013d) highlighted issues with this
communication which refers to the same issue as the
one in OS but in this case it is limited to planned data.
Maintenance planning: Concerns regarding these plans were
expressed by Lundqvist (2014), Energy Strategist (2014),
Power Engineer (2014) and the Swedish Energy Market
Inspectorate (2013d). This group of concerns refers to
the maintenance plans that need to be done for different
timeframes and communicated to higher authorities.

Real time data from FRR: Concerns regarding this was
highlighted by the Swedish Energy Market Inspectorate
(2013b) and refers to the real time data to be sent from
the Frequency Restoration Reserve to the TSO, probably
through DSO.
Demands on FRR: Concerns regarding this was expressed
by the Swedish Energy Market Inspectorate (2013b) and
refers to the demands that the codes put on facilities
that want to be a Frequency Restoration Reserve.
VI
Appendix 2 - Information flows
In this appendix the information flows are described. For every arrow in Figure 7 and Figure 8 a reference
to the codes and articles are presented. Firstly the flows are described that a PGM type A has to manage,
then a PGM type B and so on, followed by the demand facility with DSR and the aggregator. Lastly the
flows that the DSO has to cope with are presented. This means that a lot of the information flows are
repeated and the intention is that a DSO only has to read the section that concerns the DSO and a PGM type
A only has to read the section on PGM type A. Each section starts by presenting the Real-time data
followed by the Scheduled data and the “In case of” data and lastly the One-time data.
Table of content
1.1
New Power Generating Module (PGM) Type A ....................................................................................................................................................................VIII
1.2
New Power Generating Module (PGM) Type B .......................................................................................................................................................................IX
1.3
New Power Generating Module (PGM) Type C .......................................................................................................................................................................XI
1.4
New Power Generating Module (PGM) Type D ................................................................................................................................................................... XIII
1.5
Existing Power Generating Module (PGM) Type B, C or D ................................................................................................................................................. XV
1.6
Relevant Asset .............................................................................................................................................................................................................................XVI
1.7
Reserve Providing Unit (RPU) ................................................................................................................................................................................................ XVII
1.8
Frequency Containment Reserve providing unit................................................................................................................................................................... XVII
1.9
Demand facilities with Demand Side Response (DSR) ...................................................................................................................................................... XVIII
1.10
Aggregators with Demand Side Response (DSR) .................................................................................................................................................................. XIX
1.11
DSO............................................................................................................................................................................................................................................... XX
With Publish .............................................................................................................................................................................................................................................. XX
With New PGM Type A ........................................................................................................................................................................................................................ XXI
With New PGM Type B........................................................................................................................................................................................................................ XXII
Real-time data ......................................................................................................................................................................................................................................... XXII
Scheduled data ........................................................................................................................................................................................................................................ XXII
“In case of” data ..................................................................................................................................................................................................................................... XXII
One time data ....................................................................................................................................................................................................................................... XXIII
With New PGM Type C...................................................................................................................................................................................................................... XXIII
Real-time data ....................................................................................................................................................................................................................................... XXIII
Scheduled data ...................................................................................................................................................................................................................................... XXIII
“In case of” data ................................................................................................................................................................................................................................... XXIV
One time data ....................................................................................................................................................................................................................................... XXIV
With New PGM Type D ....................................................................................................................................................................................................................... XXV
With Existing PGM Type B, C, D .................................................................................................................................................................................................... XXVII
With Relevant Asset .......................................................................................................................................................................................................................... XXVIII
With Reserve Providing Unit (RPU) .................................................................................................................................................................................................. XXIX
One time data ....................................................................................................................................................................................................................................... XXIX
With Demand Facilities ....................................................................................................................................................................................................................... XXIX
Scheduled data ...................................................................................................................................................................................................................................... XXIX
With Demand Facilities with Demand Side Response (DSR) ........................................................................................................................................................ XXIX
With Aggregator with Demand Side Response (DSR) .................................................................................................................................................................... XXXI
With Higher DSO ............................................................................................................................................................................................................................... XXXII
With Lower DSO .............................................................................................................................................................................................................................. XXXIII
With TSO ........................................................................................................................................................................................................................................... XXXIV
With NRA ............................................................................................................................................................................................................................................ XXXV
VII
1.1
New Power Generating Module (PGM) Type A
A new PGM type A has to be able to handle the following information.
Scheduled data
Scheduling
 If there is already legal frameworks for scheduling in place between
the TSO and PGM it shall continue. It shall include scheduled
consumption, generation, and internal and external trade.
Furthermore it shall include net position, external commercial trade
schedules and internal commercial trades(OPS art52-53)
Decommission- PGM must notify the DSO prior. (RfG art25(3))
Derogation
 PGM may submit derogation from one or multiple requirements in
the code to the DSO. The DSO defines what is required to be
included in the derogation but at least it shall include identification
of plant and owner, what the derogation concerns and a justification
for derogation. If derogation has been filed PGM is seen as
compliant until answer. All non-compliant PGM shall apply for
derogation within 12 months from the day of the request. If this
has not been done despite a reminder the DSO have right to
disconnect the PGM. (RfG 53(2) & RfG 54)
“In case of” data
Compliance
 The PGM shall notify the DSO when possible impact on compliance
before initiating modification of technical capabilities, as soon as
possible after operational incident, foreseen tests scheduled
procedure to verify compliance. (RfG art34(1-5))
 The DSO may rely on equipment certificates instead of doing
compliance tests. (RfG art35(1))
Information gathering
 TSO may gather information about generation, consumption,
schedules, balance positions, planned outages and own forecasts
from PGM in order to be able to analyze injections and withdrawals
in the transmission system nodes. (OS art 16(3))
One time data
New installation
 The DSO provide Installation document to PGM at least including
location of connection, date of connection, Maximum capacity in
kW, type of primary energy source, reference to equipment
certificate. (RfG art25(1-2))
 PGM fills it out and returns the DSO. (RfG art25(1))
VIII
1.2 New Power Generating Module (PGM) Type B
A new PGM type A has to be able to handle the following information.
Real-time data
General information
 PGM shall provide the DSO in real time with status of the switching
devices and circuit breakers at the connection point, Active and
Reactive power flows, current and voltage at the connection point.
(Organisation of the data shall be agreed upon by the DSO and the
TSO). (OS art26(1-2))
Requested data
 PGM shall deliver real-time data as requested by the TSO to TSO for
contingency analysis.(OS art13(11))
Scheduled data
Structural data
 PGM shall provide the DSO with its scheduled unavailability, Active
power restriction and its forecast scheduled Active power output at
the connection point and any forecasted restriction in the Reactive
Power control capability. This can be done aggregated per legal
entity operating the PGM. (Organisation of the data shall be agreed
upon by the DSO and TSO). (OS art25(1-2))
Scheduling
 If there is already legal frameworks for scheduling in place between
the TSO and the PGM it shall continue. It shall include scheduled
consumption, generation, and internal and external trade.
Furthermore it shall include net position, external commercial trade
schedules and internal commercial trades(OPS art52-53)
Forecast information
 The PGM shall deliver forecasts information to TSO. (OS art13(11))
Compliance
 The PGM must inform the DSO about relevant changes to the data.
(OS art 16 (5d))
 The PGM shall notify the DSO when possible impact on compliance
before initiating modification of technical capabilities, as soon as
possible after operational incident, foreseen tests scheduled
procedure to verify compliance. (RfG art34(1-5))
 The PGM shall notify the DSO in advance if it is going to make
changes or have operational problems which could affect its
compliance. Also inform about any scheduled tests to verify
compliance so the DSO can approve them. The DSO shall also have
the possibility to participate in these tests. These test can also be
carried out upon request from the DSO or TSO (OS art 31)
 The DSO can request PGM to make compliance tests throughout
lifetime according to schedule or after incident, like tests from
installation. (RfG art35(2)) (RfG art37(4)). Tests regarding LFSM-O
(limited frequency sensitive model-over frequency) shall be carried
out (RfG art41(2)). Some parts of the tests can be replaced by
equipment certificate.
 If the PGM is a PPM or a SPGM a part of the compliance tests are
done differently
o PPM shall do compliance simulations with regard to LFSMO, Reactive current injection, Fault-ride-trough capability,
and Post fault power active Recovery. (RfG art48). Some
parts of the tests can be replaced by equipment certificate.
o SPGM shall do compliance simulations with regard to
LFSM-O, Fault-ride-trough capability and Post fault power
active Recovery. (RfG art 45). Some parts of the tests can
be replaced by equipment certificate.
 PGM can request from the DSO to provide the pre-fault and postfault conditions to be considered for FRT capability as an outcome
of the calculations at the connection point regarding:
o Pre fault minimum short circuit capacity, Pre-fault
operating point of the PGM expressed in Active Power
IX
output and Reactive Power output and Voltage, Post-fault
minimum short circuit capacity at each connection point.
(RfG art9(3a))
this has not been done despite a reminder the DSO have right to
disconnect the PGM. (RfG 53(2) & RfG 54)
“In case of” data
Compliance see scheduled data.
Information gathering
 TSO may gather information about generation, consumption,
schedules, balance positions, planned outages and own forecasts
from other parties in order to be able to analyze injections and
withdrawals in the transmission system nodes. (OS art 16(3))
One time data
New installation
 Power Generating Module Document
 The PGM submits the PGM Document to the DSO including at least
an Energisation Operational Notification (EON), an Interim
Operational Notification (ION) but through delivery in a single
stage and reduced details and equipment certificate is fine to
validate details. (RfG art26(1-3)& RfG art27(1-2)) (EON and ION is
described under PGM Type D)
 The DSO accepts PGM Document and sends a Final Operational
Notification (FON) to PGM (RfG art27(2)) (FON is described
under PGM Type D)
Decommission- The PGM must notify the DSO prior. (RfG art27(3))
Derogation
 The PGM may submit derogation from one or multiple
requirements in the code to the DSO. The DSO defines what is
required to be included in the derogation but at least it shall include
identification of plant and owner, what the derogation concerns and
a justification for derogation. If derogation has been filed PGM is
seen as compliant until answer All non-compliant PGM shall apply
for derogation within 12 months from the day of the request. If
X
1.3 New Power Generating Module (PGM) Type C
A new PGM type C has to be able to handle the following information.
Real-time data
General information
 The PGM shall provide the DSO in real time with status of the
switching devices and circuit breakers at the connection point,
Active and Reactive power flows, current and voltage at the
connection point. (Organisation of the data shall be agreed upon by
the DSO and the TSO) (OS art26(1-2)).
 Communication interface shall be equipped to transfer on-line from
the PGM to the DSO including at least status signal of FSM (on/off),
scheduled Active Power output, actual value of the Active power
output, actual parameter settings for Active power frequency
response and Droop and dead band. (RfG art10(2f))
Requested data
 PGM shall deliver real-time data as requested by the TSO to TSO for
contingency analysis.( OS art13(11))
Scheduled data
Structural data
 The PGM shall provide the DSO with its scheduled unavailability,
Active power restriction and its forecast scheduled Active power
output at the connection point and any forecasted restriction in the
Reactive Power control capability. This can be done aggregated per
legal entity operating the PGM. (Organisation of the data shall be
agreed upon by the DSO and the TSO). (OS art25(1-2))
Scheduling
 If there is already legal frameworks for scheduling in place between
the TSO and PGM it shall continue. It shall include scheduled
consumption, generation, and internal and external trade.
Furthermore it shall include net position, external commercial trade
schedules and internal commercial trades(OPS art52-53)
Forecast information
 The PGM shall deliver forecasts information to TSO. (OS art13(11))
Compliance
 The PGM must inform the DSO about relevant changes to the data.
(OS art 16 (5d))
 The PGM shall notify the DSO when possible impact on compliance
before initiating modification of technical capabilities, as soon as
possible after operational incident, foreseen tests scheduled
procedure to verify compliance. (RfG art34(1-5))
 The PGM shall notify the DSO in advance if it is going to make
changes or have operational problems which could affect its
compliance. Also inform about any scheduled tests to verify
compliance so the DSO can approve them. The DSO shall also have
the possibility to participate in these tests. These test can also be
carried out upon request from the DSO or the TSO (OS art(31))
 The PGM can request from the DSO to provide the pre-fault and
post-fault conditions to be considered for FRT capability as an
outcome of the calculations at the connection point regarding:
o Pre fault minimum short circuit capacity, Pre-fault
operating point of the PGM expressed in Active Power
output and Reactive Power output and Voltage, Post-fault
minimum short circuit capacity at each connection point.
(RfG art9(3a))
 The DSO and the TSO can require simulation model from PGM
which shall reflect behavior in PGM steady- and dynamic state and
sometimes electromagnetic transient simulation. It shall be used to
at least verify compliance tests. The DSO shall deliver to the PGM
an estimate of min and max short circuit capacity at the connection
point and define min and max limits on rates of change of Active
power output. The DSO and the TSO have the right to require the
PGM recordings in order to compare the connection point. (RfG
art10(6c))
XI

The DSO can request PGM to make compliance tests throughout
lifetime according to schedule or after incident, like tests from
installation (RfG art35(2)) & RfG art37(4)).If the PGM is a PPM or
a SPGM a part of the compliance tests are done differently
o PPM: Tests regarding LFSM-O (limited frequency
sensitive model-over frequency), demonstrate operation at
load level no higher than the setpoint, LFSM-U (limited
frequency sensitive model – under), FSM, Frequency
restoration control, Reactive power capability, Reactive
power control, Power factor control shall be carried out.
Some parts of the tests can be replaced by equipment
certificate shall be carried out (RfG art41(2)). Some parts
of the tests can be replaced by equipment certificate.
o PPM shall do compliance simulations with regard to LFSMO, LFSM-U, FSM, Fault-ride-trough capability, Island
operation, Capability of providing synthetic inertia,
Reactive power capability, Power Oscillations Damping
control and Post fault power active Recovery. (RfG
art(49)). Some parts of the tests can be replaced by
equipment certificate.
o SPGM: Tests regarding LFSM-O (limited frequency
sensitive model-over frequency), LFSM-U (limited
frequency sensitive model – under), FSM, Frequency
restoration control, Black start capability, House load and
Reactive power capability shall be carried out. Some parts
of the tests can be replaced by equipment certificate. (RfG
art(39))
o SPGM shall do compliance simulations with regard to
LFSM-O), LFSM-U, FSM, Fault-ride-trough capability,
Island operation, Reactive power capability and Post fault
power active Recovery. (RfG art(46)). Some parts of the
tests can be replaced by equipment certificate.
“In case of” data
Compliance see scheduled data.
Information gathering
 TSO may gather information about generation, consumption,
schedules, balance positions, planned outages and own forecasts
from other parties in order to be able to analyse injections and
withdrawals in the transmission system nodes. (OS art 16(3))
One time data
New installation
 Power Generating Module Document
 The PGM submits the PGM Document to the DSO including at least
EON, ION but through delivery in a single stage and reduced
details and equipment certificate is fine to validate details. (RfG
art26(1-3) & RfG art27(1-2)) (EON and ION is described under
PGM Type D)
 The DSO accepts the PGM Document and sends FON to SPGM
(RfG art27(2)) (FON is described under PGM Type D)
Decommission- The < must notify the DSO prior. (RfG art27(3))
Derogation
 The PGM may submit derogation from one or multiple
requirements in the code to the DSO. The DSO defines what is
required to be included in the derogation but at least it shall include
identification of plant and owner, what the derogation concerns and
a justification for derogation. If derogation has been filed PGM is
seen as compliant until answer. All non-compliant PGM shall apply
for derogation within 12 months from the day of the request. If
this has not been done despite a reminder the DSO have right to
disconnect the PGM. (RfG 53(2) & RfG 54)
XII
1.4 New Power Generating Module (PGM) Type D
A new PGM type D has to be able to handle the following information.
Real-time data
General information
 The PGM shall provide the DSO in real time with status of the
switching devices and circuit breakers at the connection point,
Active and Reactive power flows, current and voltage at the
connection point. (Organisation of the data shall be agreed upon by
the DSO and the TSO) (OS art26(1-2)). Communication interface
shall be equipped to transfer on-line from the PGM to the DSO
including at least status signal of FSM (on/off), scheduled Active
Power output, actual value of the Active power output, actual
parameter settings for Active power frequency response and Droop
and dead band. (RfG art10(2f))
Requested data
 PGM shall deliver real-time data as requested by the TSO to TSO for
contingency analysis.( OS art13(11))
Scheduled data
Structural data
 The PGM shall provide with its scheduled unavailability, Active
power restriction and its forecast scheduled Active power output at
the connection point and any forecasted restriction in the Reactive
Power control capability. This can be done aggregated per legal
entity operating the PGM. (Organisation of the data shall be agreed
upon by the DSO and the TSO). (OS art25(1-2))
Scheduling
 If there is already legal frameworks for scheduling in place between
the TSO and the PGM it shall continue. It shall include scheduled
consumption, generation, and internal and external trade.
Furthermore it shall include net position, external commercial trade
schedules and internal commercial trades(OPS art52-53)
Forecast information
 The PGM shall deliver forecasts information to the TSO. (OS
art13(11))
Compliance
 The PGM must inform the DSO about relevant changes to the data.
(OS art 16 (5d))
 The PGM shall notify the DSO when possible impact on
compliance before initiating modification of technical capabilities, as
soon as possible after operational incident, foreseen tests scheduled
procedure to verify compliance. (RfG art34(1-5))
 PGM shall do compliance simulations with regard to LFSM-O,
LFSM-U, FSM, Fault-ride-trough capability, Island operation,
Capability of providing synthetic inertia, Reactive power capability,
Power Oscillations Damping control and Post fault power active
Recovery. (RfG art45). Some parts of the tests can be replaced by
equipment certificate.
 The DSO and the TSO can require simulation model from the PGM
which shall reflect behavior in the PGM steady- and dynamic state
and sometimes electromagnetic transient simulation. It shall be used
to at least verify compliance tests. The DSO shall deliver to the
PGM an estimate of min and max short circuit capacity at the
connection point and define min and max limits on rates of change
of Active power output. The DSO and the TSO have the right to
require the PGM recordings in order to compare the connection
point. (RfG art10(6c))
 The PGM shall notify the DSO in advance if it is going to make
changes or have operational problems which could affect its
compliance. Also inform about any scheduled tests to verify
compliance so the DSO can approve them. The DSO shall also have
the possibility to participate in these tests. These test can also be
carried out upon request from the DSO or the TSO (OS art31)
XIII




The PGM can request from the DSO to provide the pre-fault and
post-fault conditions to be considered for FRT capability as an
outcome of the calculations at the connection point regarding:
o Pre fault minimum short circuit capacity, Pre-fault
operating point of the PGM expressed in Active Power
output and Reactive Power output and Voltage, Post-fault
minimum short circuit capacity at each connection point.
(RfG art9(3a))
The PGM applies to the DSO for a LON when temporarily doing a
significant modification, loss of capacity, equipment failure that
leads to incompliance. (RfG art32(1-2))
The DSO issues a LON with timescale and responsibility for
expected solution and validity period. (RfG art32(3))
The DSO can request PPM to make compliance tests and
simulations throughout lifetime according to schedule or after
incident, like tests from installation. (RfG art35(2) & RfG
art37(4)).If the PGM is a PPM or a SPGM a part of the compliance
tests are done differently.
o PPM: Tests regarding LFSM-O (limited frequency sensitive
model-over frequency), demonstrate operation at load
level no higher than the setpoint, LFSM-U (limited
frequency sensitive model – under), FSM, Frequency
restoration control, Reactive power capability, Reactive
power control, Power factor control shall be carried out.
Some parts of the tests can be replaced by equipment
certificate. (RfG art43) shall be carried out (RfG art41(2)).
Some parts of the tests can be replaced by equipment
certificate.
o The PPM shall do compliance simulations with regard to
LFSM-O, LFSM-U, FSM, Fault-ride-trough capability, Island
operation, Capability of providing synthetic inertia,
Reactive power capability, Power Oscillations Damping
control and Post fault power active Recovery. (RfG art50).

Some parts of the tests can be replaced by equipment
certificate.
o SPGM: Tests regarding LFSM-O (limited frequency
sensitive model-over frequency), LFSM-U (limited
frequency sensitive model – under), FSM, Frequency
restoration control, Black start capability, House load and
Reactive power capability shall be carried out. Some parts
of the tests can be replaced by equipment certificate. (RfG
art40)
o The SPGM shall do compliance simulations with regard to
LFSM-O, LFSM-U, FSM, Fault-ride-trough capability, Island
operation, Reactive power capability, Post fault power
active Recovery and Power oscillations damping control.
(RfG art(47)). Some parts of the tests can be replaced by
equipment certificate
The PGM can apply for derogation to the DSO. (RfG art32(5))
“In case of” data
Compliance see scheduled data.
Information gathering
 TSO may gather information about generation, consumption,
schedules, balance positions, planned outages and own forecasts
from other parties in order to be able to analyze injections and
withdrawals in the transmission system nodes. (OS art 16(3))
One time data
New installation
 The DSO issues an EON to PGM (RfG art29(2))
 The DSO issues an ION to PGM and can request data: Statement of
compliance, technical data of PGM, Equipment certificates,
simulation models, expected steady - and dynamic state
performance intended compliance tests. Equipment certificate is
fine to validate details. (RfG art30(2-3) & RfG art26(1-3))
XIV

DSO issues FON to PGM after removal of all incompatibilities
found in ION (RfG art 31(2-3))
Derogation
 The PGM may submit derogation from one or multiple
requirements in the code to the DSO. The DSO defines what is
required to be included in the derogation but at least it shall include
identification of plant and owner, what the derogation concerns and
a justification for derogation. If derogation has been filed PGM is
seen as compliant until answer All non-compliant PGMs shall apply
for derogation within 12 months from the day of the request. If
this has not been done despite a reminder the DSO have right to
disconnect the PGM. (RfG 53(2) & RfG 54)
1.5 Existing Power Generating Module (PGM)
Type B, C or D
An existing PGM type B, C and D has to be able to handle the following
information.
Real time-data
General information
 The PGM shall provide the DSO in real time with status of the
switching devices and circuit breakers at the connection point,
Active and Reactive power flows, current and voltage at the
connection point. (Organisation of the data shall be agreed upon by
the DSO and the TSO). (OS art26(1-2))
Scheduled data
Structural data
 The PGM shall provide the DSO with its scheduled unavailability,
Active power restriction and its forecast scheduled Active power
output at the connection point and any forecasted restriction in the
Reactive Power control capability. This can be done aggregated per
legal entity operating the PGM. (Organisation of the data shall be
agreed upon by the DSO and the TSO). (OS art25(1-2))
Scheduling
 If there is already legal frameworks for scheduling in place between
the TSO and the existing PGM it shall continue. It shall include
scheduled consumption, generation, and internal and external trade.
Furthermore it shall include net position, external commercial trade
schedules and internal commercial trades(OPS art52-53)
“In case of” data
Information of changes
 The existing PGM must inform the DSO about relevant changes to
the data. (OS art16(5d)) The PGM shall notify the DSO in advance
XV
if it is going to make changes or have operational problems which
could affect its possibilities to comply with the code. (OS art 31)
Information gathering
 The TSO may gather information about generation, consumption,
schedules, balance positions, planned outages and own forecasts
from other parties in order to be able to analyze injections and
withdrawals in the transmission system nodes. (OS art 16(3))
One time data
Frequency performance
 If PGM derogated from the frequency requirements, PGM shall
inform the DSO and the TSO about their frequency performance
within 12 months and include time ranges the facility can withstand
without disconnection. (OS art 9(4))
Structural data
 Existing PGM shall provide DSO with structural data including
installed capacity, primary energy source, protection data, and
reactive power control capability, capability of remote access to the
circuit breaker, voltage level and location of each PGM. (OS art24)
1.6 Relevant Asset
A Relevant Asset has to be able to handle the following information.
Scheduled data
Availability Plan
 Before 1 August the outage planning agent, if not a DSO, sends an
availability plan for the coming calendar year to the TSO and the
DSO. Until the 1 December it’s possible to send change requests to
the TSO. (OPS art34) The availability plan shall contain of when the
relevant asset is available, unavailable or testing for any given hour
in the period. If the parties have agreed on higher level of time
detail the time period may be less than one hour. (OPS art32)
o The TSO then checks for incompatibilities with the
different plans and informs affected and request
alternative availability plans if that is needed. If the
incompatibilities remain the TSO makes an alternative
plan. (OPS art35)
 If the outage planning agent is a DSO they shall send the availability
plan, containing if the relevant asset is available, unavailable or
testing for any given hour in the period, before 1 August to the
TSO. The time may be less than one hour if agreed so. Until the 1
December it’s possible to send change requests to the TSO.
Furthermore the plan shall try to minimize the impact on the
market. If the DSO cannot do it the TSO and all affected outage
planning agents try to do it together.(OPS art36)
Status testing
 All facilities with the availability status of testing should one month
before a test supply both the TSO and the DSO with a detailed plan
of the test. (OPS art42)
XVI
“In case of” data
Outage
 If an outage is forced the TSO and the DSO shall be informed
about the reason, duration and impact on other relevant assets
under its responsibility of the fault. (OPS art43)
1.7 Reserve Providing Unit (RPU)
A RPU has to be able to handle the following information.
Scheduled data
Information gathering
 The TSO may gather information about generation, consumption,
schedules, balance positions, planned outages and own forecasts
from other parties in order to be able to analyze injections and
withdrawals in the transmission system nodes. (OS art 16(3))
One time data
Application
 The RPU unit or group sends prequalification application to the
DSO at least including Voltage level and connection point, Type of
reserve, Maximum capacity and Maximum rate of change. (LFCR
art 68)
 The DSO processes the application within two months further.
(LFCR art 68)
1.8 Frequency Containment Reserve providing unit
A Frequency Containment Reserve has to be able to handle the following
information.
Real-time data
ON/OFF
 The Frequency Containment Reserve providing unit shall make
available to the TSO information regarding the status of the
Frequency Containment Reserve, if it is on or off, and time stamped
data of active power to verify that the Frequency Containment
Reserve unit is on. (LFCR art 44 (8))
“In case of” data
Information gathering
 The TSO may gather information about generation, consumption,
schedules, balance positions, planned outages and own forecasts
from other parties in order to be able to analyze injections and
withdrawals in the transmission system nodes. (OS art 16(3))
One time data
Structural data
 If the RPU is a new or existing PGM of size B or larger or provide
demand side response it shall provide the DSO with structural data
including Frequency containment reserve data according to
definition in LFCR, frequency restoration reserve data and
replacement reserve data. (OS art24)
XVII
1.9 Demand facilities with Demand Side Response
(DSR)
A Demand facility with DSR has to be able to handle the following information.
Real-time data
General information
 A demand facility with DSR shall provide to the DSO real time
active- and reactive power at connection point and confirmation
that the estimated actual values of demand response are applied.
(OS art 29(1))
Compliance monitoring
 The DSO may monitor compliance. (DCC art 38-39)
Scheduled data
Capacity
 A demand facility with DSR shall yearly notify the DSO about
changes in capacity (detail is to be determined by DSO). (DCC art
22 (1o))
Structural data
 A demand facility with DSR shall provide the DSO with structural
minimum and maximum Active Power available for DSR; and the
maximum and minimum duration of any potential usage of this
power for DSR and a forecast of unrestricted Active Power
available for and any planned DSR. (OS art 29(1))
“In case of” data
Compliance
 A demand facility with DSR shall notify the DSO immediately if
modifications of the DSR are done. (DCC art 22 (1o))
 A demand facility with DSR shall notify the DSO in advance
directly or indirectly if wanting to increase, modernize or replace
equipment that may affect the compliance with the requirements.
(DCC art 19)
 A demand facility with DSR shall as soon as possible notify the
DSO at any incidents or failures that can affect the compliance
monitoring or testing. (DCC art 37)
 A demand facility with DSR must inform the DSO about relevant
changes to the data. (OS art 16 (5d))
 A demand facility with DSR shall notify the DSO in advance if it is
going to make changes or have operational problems which could
affect its compliance. Also inform about any scheduled tests to
verify compliance so that the DSO can approve them. The DSO
shall also have the possibility to participate in these tests. These test
can also be carried out upon request from DSO or TSO (OS art 31)
 The DSO may test or simulate the compliance of demand facility.
(DCC art 38-39)
 Compliance test should be made for every new connection, when
equipment is modernized or when suspicion of incompliance exists.
Can be delegated to third party(DCC art 38-39)
 A demand facility with DSR shall do the tests with relevant personal
and monitoring equipment. (DCC art 38-39)
 A demand facility with DSR shall communicate scheduled tests to
the DSO so that the DSO can participate. (DCC art 38-39)
Information gathering
 The TSO may gather information about generation, consumption,
schedules, balance positions, planned outages and own forecasts
from other parties in order to be able to analyze injections and
withdrawals in the transmission system nodes. (OS art 16(3))
One time data
Derogation
 The Demand facility with DSR may submit derogation from one or
multiple requirements in the code to the DSO. The DSO defines
what is required to be included in the derogation but at least it shall
XVIII
include identification of plant and owner, what the derogation
concerns and a justification for derogation. If derogation has been
filed the facility is seen as compliant until answer. All non-compliant
Demand facilities with DSR shall apply for derogation within 12
months from the day of the request. If this has not been done
despite a reminder the DSO have right to disconnect the facility.
(DCC art 51-54)
New installation
 A new demand facility with DSR connected below 1 kV need to
communicate information directly or indirectly to the DSO,
including location, maximum capacity, type of DSR, contact details
and equipment information which will be filled in a template
provided by the DSO. (DCC art 28)
Decommission- Demand Facility with DSR must notify the DSO prior.
(DCC art 28)
1.10 Aggregators with Demand Side Response
(DSR)
An Aggregator with DSR has to be able to handle the following information.
Real-time data
General information
 The aggregator shall provide to the DSO real time active- and
reactive power at connection point and confirmation that the
estimated actual values of demand response are applied. (OS art
29(2))
Scheduled data
Structural data
 The aggregator shall provide structural minimum and maximum
Active Power available for DSR; and the maximum and minimum
duration of any potential usage of this power for DSR and a
forecast of unrestricted Active Power available for and any planned
DSR at least day ahead to the DSO. (OS art 29(2))
“In case of” data
Compliance
 The aggregator shall notify the DSO in advance directly or indirectly
if wanting to increase, modernize or replace equipment that may
affect the compliance with the requirements. (DCC art 19)
 The aggregator shall as soon as possible notify the DSO at any
incidents or failures that can affect the compliance monitoring or
testing. (DCC art 37)
 The aggregator must inform the DSO about relevant changes to the
data. (OS art 16 (5d))
XIX

The aggregator shall notify the DSO in advance if it is going to
make changes or have operational problems which could affect its
compliance. Also inform about any scheduled tests to verify
compliance so that the DSO can approve them. The DSO shall also
have the possibility to participate in these tests. These test can also
be carried out upon request from the DSO or the TSO (OS art31)
Information gathering
 The TSO may gather information about generation, consumption,
schedules, balance positions, planned outages and own forecasts
from other parties in order to be able to analyze injections and
withdrawals in the transmission system nodes. (OS art 16(3))
One time data
New installation
 New Aggregator with DSR connected below 1 kV need to
communicate information directly or indirectly to the DSO,
including location, maximum capacity, type of DSR, contact details
and equipment information which will be filled in a template
provided by the DSO. (DCC art28)
Decommission- The aggregator must notify the DSO prior to
decommission. (DCC art 28)
1.11 DSO
A DSO has to be able to handle the following information flows. This section is
divided into sub-sections and in each sub-section the information flows from or
to the stated actor is presented.
With Publish
A DSO has to make the following information publicly available.
One time data
List of rules
 The DSO shall make public documents and certificates to be
provided by the PGMs, details of technical data, models for steady
state and dynamic system studies, timely provision of system data
required to perform the studies, conditions and procedures
including the scope for registration equipment certificates. And the
allocation of responsibilities for the DSO and the PGM (RfG art
35(3-4))(DCC art 38(3)).
 The DSO has to make the information regarding the requirements
to be fulfilled and the documents to be provided by the significant
grid users to comply with the code, publically available. The DSO
also has the right to evaluate if the user is compliant with these
requirements. (OS art 32)
XX
With New PGM Type A
A DSO has to be able to handle the following information change with a PGM
type A.
non-compliant PGM shall apply for derogation within 12 months
from the day of the request. If this has not been done despite a
reminder the DSO have right to disconnect the facility. (RfG 53(2)
& RfG 54)
“In case of” data
Compliance
 The DSO shall be notified by the PGM when there is a possible
impact on its compliance before initiating modification of technical
capabilities, as soon as possible after operational incident, foreseen
tests scheduled procedure to verify compliance. (RfG art34(1-5))
 The DSO may rely on equipment certificates instead of doing
compliance tests. (RfG art35(1))
One time data
New installation
 The DSO shall provide an Installation document to the PGM at
least including location of connection, date of connection,
Maximum capacity in kW, type of primary energy source, reference
to equipment certificate. (RfG art25(1-2))
 The PGM fills it out and returns to the DSO. (RfG art25(1))
Decommission- The PGM must notify the DSO prior. (RfG art25(3))
Derogation
 The PGM may submit derogation from one or multiple
requirements in the code to the DSO. The DSO defines what is
required to be included in the derogation but at least it shall include
identification of plant and owner, what the derogation concerns and
a justification for derogation. The DSO then performs a cost
benefit analysis and gives an opinion and sends that to the NRA
within six months. If the DSO has asked for a derogation regarding
the cost benefit analysis within one month and got it approved the
deadline to the NRA is three months instead. If derogation has been
filed the facility or network is seen as compliant until answer. All
XXI
With New PGM Type B

A DSO has to be able to handle the following information change with a PGM
type B.
Real-time data
General information
 The PGM shall provide the DSO in real time with status of the
switching devices and circuit breakers at the connection point,
Active and Reactive power flows, current and voltage at the
connection point. (Organisation of the data shall be agreed upon by
DSO and TSO). (OS art26(1-2))

Scheduled data
Structural data
 The PGM shall provide the DSO with its scheduled unavailability,
Active power restriction and its forecast scheduled Active power
output at the connection point and any forecasted restriction in the
Reactive Power control capability. This can be done aggregated per
legal entity operating the PGM. (Organisation of the data shall be
agreed upon by DSO and TSO). (OS art25(1-2))
Compliance
 The DSO shall be notified by the PGM when there is possible
impact on its compliance before initiating modification of technical
capabilities, as soon as possible after operational incident, foreseen
tests scheduled procedure to verify compliance. (RfG art34(1-5))
 The DSO shall be notified by the PGM in advance if the PGM is
going to make changes or have operational problems which could
affect its compliance. The DSO shall also be informed about any
scheduled tests to verify compliance so that the DSO can approve
them. The DSO shall also have the possibility to participate in these
tests. These test can also be carried out upon request from the DSO
or the TSO (OS art 31)


The DSO can request the PGM to make compliance tests
throughout lifetime according to schedule or after incident, like tests
from installation. (RfG art35(2)) (RfG art37(4)). Tests regarding
LFSM-O (limited frequency sensitive model-over frequency) shall
be carried out (RfG art41(2)). Some parts of the tests can be
replaced by equipment certificate.
If the PGM is a PPM or a SPGM a part of the compliance tests are
done differently
o The PPM shall do compliance simulations with regard to
LFSM-O, Reactive current injection, Fault-ride-trough
capability, and Post fault power active Recovery. (RfG
art48). Some parts of the tests can be replaced by
equipment certificate.
o SPGM shall do compliance simulations with regard to
LFSM-O, Fault-ride-trough capability and Post fault
power active Recovery. (RfG art 45). Some parts of the
tests can be replaced by equipment certificate.
The PGM can request the DSO to provide the pre-fault and postfault conditions to be considered for FRT capability as an outcome
of the calculations at the connection point regarding:
o Pre fault minimum short circuit capacity, Pre-fault
operating point of the PGM expressed in Active Power
output and Reactive Power output and Voltage, Post-fault
minimum short circuit capacity at each connection point.
(RfG art9(3a))
The PGM must inform the DSO about relevant changes to the
data. (OS art 16 (5d))
“In case of” data
Compliance see scheduled data.
XXII
One time data
New installation
 Power Generating Module Document
 The PGM submits the PGM Document to the DSO including at
least EON, ION but through delivery in a single stage and reduced
details and equipment certificate is fine to validate details. (RfG
art26(1-3)& RfG art27(1-2))
 The DSO accepts the PGM Document and sends FON to PGM
(RfG art27(2))
Decommission

The PGM must notify the DSO prior to decommission. (RfG
art27(3))
Derogation
 The PGM may submit derogation from one or multiple
requirements in the code to the DSO. The DSO defines what is
required to be included in the derogation but at least it shall include
identification of plant and owner, what the derogation concerns and
a justification for derogation. The DSO then performs a cost
benefit analysis and gives an opinion and sends that to the NRA
within six months. If the DSO has asked for a derogation regarding
the cost benefit analysis within one month and got it approved the
deadline to the NRA is three months instead. If derogation has been
filed the facility or network is seen as compliant until answer. All
existing facilities when this code enters into force shall apply for
derogation within twelve months. If this has not been done despite
a reminder the DSO have right to disconnect the facility. (RfG 53(2)
& RfG 54)
With New PGM Type C
A DSO has to be able to handle the following information change with a PGM
type C.
Real-time data
General information
 The PGM shall provide the DSO in real time with status of the
switching devices and circuit breakers at the connection point,
Active and Reactive power flows, current and voltage at the
connection point. (Organisation of the data shall be agreed upon by
the DSO and the TSO) (OS art26(1-2)). Communication interface
shall be equipped to transfer on-line from the PGM to the DSO
including at least status signal of FSM (on/off), scheduled Active
Power output, actual value of the Active power output, actual
parameter settings for Active power frequency response and Droop
and dead band. (RfG art10(2f))
Scheduled data
Structural data
 The PGM shall provide the DSO with its scheduled unavailability,
Active power restriction and its forecast scheduled Active power
output at the connection point and any forecasted restriction in the
Reactive Power control capability. This can be done aggregated per
legal entity operating the PGM. (Organisation of the data shall be
agreed upon by the DSO and the TSO). (OS art25(1-2))
Compliance
 The PGM must inform the DSO about relevant changes to the
data. (OS art 16 (5d))
 The DSO shall be notified by the PGM when there is possible
impact on its compliance before initiating modification of technical
capabilities, as soon as possible after operational incident, foreseen
tests scheduled procedure to verify compliance. (RfG art34(1-5))
XXIII



The DSO shall be notified by the PGM in advance if the PGM is
going to make changes or have operational problems which could
affect its compliance. Also inform about any scheduled tests to
verify compliance so the DSO can approve them. The DSO shall
also have the possibility to participate in these tests. These test can
also be carried out upon request from the DSO or the TSO (OS
art(31))
The PGM can request from the DSO to provide the pre-fault and
post-fault conditions to be considered for FRT capability as an
outcome of the calculations at the connection point regarding:
o Pre fault minimum short circuit capacity, Pre-fault
operating point of the PGM expressed in Active Power
output and Reactive Power output and Voltage, Post-fault
minimum short circuit capacity at each connection point.
(RfG art9(3a))
The DSO can request the PPM to make compliance tests
throughout lifetime according to schedule or after incident, like tests
from installation (RfG art35(2)) & RfG art37(4)). If the PGM is a
PPM or a SPGM a part of the compliance tests are done differently
o PPM: Tests regarding LFSM-O (limited frequency
sensitive model-over frequency), demonstrate operation at
load level no higher than the setpoint, LFSM-U (limited
frequency sensitive model – under), FSM, Frequency
restoration control, Reactive power capability, Reactive
power control, Power factor control shall be carried out.
Some parts of the tests can be replaced by equipment
certificate shall be carried out (RfG art41(2)). Some parts
of the tests can be replaced by equipment certificate.
o The PPM shall do compliance simulations with regard to
LFSM-O, LFSM-U, FSM, Fault-ride-trough capability,
Island operation, Capability of providing synthetic inertia,
Reactive power capability, Power Oscillations Damping
control and Post fault power active Recovery. (RfG
o
o
art(49)). Some parts of the tests can be replaced by
equipment certificate.
SPGM: Tests regarding LFSM-O (limited frequency
sensitive model-over frequency), LFSM-U (limited
frequency sensitive model – under), FSM, Frequency
restoration control, Black start capability, House load and
Reactive power capability shall be carried out. Some parts
of the tests can be replaced by equipment certificate. (RfG
art(39))
The SPGM shall do compliance simulations with regard to
LFSM-O), LFSM-U, FSM, Fault-ride-trough capability,
Island operation, Reactive power capability and Post fault
power active Recovery. (RfG art(46)). Some parts of the
tests can be replaced by equipment certificate.
“In case of” data
Compliance see scheduled data.
One time data
New installation
 Power Generating Module Document
 The PGM submits a PGM Document to the DSO including at least
EON, ION but through delivery in a single stage and reduced
details and equipment certificate is fine to validate details. (RfG
art26(1-3) & RfG art27(1-2))
 The DSO accepts the PGM Document and sends FON to the
SPGM (RfG art27(2))
Decommission
 The SPGM must notify the DSO prior to decommission. (RfG
art27(3))
Derogation
 The PGM may submit derogation from one or multiple
requirements in the code to the DSO. The DSO defines what is
required to be included in the derogation but at least it shall include
XXIV
identification of plant and owner, what the derogation concerns and
a justification for derogation. The DSO then performs a cost
benefit analysis and gives an opinion and sends that to the NRA
within six months. If the DSO has asked for a derogation regarding
the cost benefit analysis within one month and got it approved the
deadline to the NRA is three months instead. If derogation has been
filed the facility or network is seen as compliant until answer. All
non-compliant PGM shall apply for derogation within 12 months
from the day of the request. If this has not been done despite a
reminder the DSO have right to disconnect the facility. (RfG 53(2)
& RfG 54)
With New PGM Type D
A DSO has to be able to handle the following information change with a PGM
type D.
Real-time data
General information
 The PGM shall provide the DSO in real time with status of the
switching devices and circuit breakers at the connection point,
Active and Reactive power flows, current and voltage at the
connection point. (Organisation of the data shall be agreed upon by
the DSO and the TSO) (OS art26(1-2)). Communication interface
shall be equipped to transfer on-line from the PGM to the DSO
including at least status signal of FSM (on/off), scheduled Active
Power output, actual value of the Active power output, actual
parameter settings for Active power frequency response and Droop
and dead band. (RfG art10(2f))
Scheduled data
Structural data
 The PGM shall provide the DSO with its scheduled unavailability,
Active power restriction and its forecast scheduled Active power
output at the connection point and any forecasted restriction in the
Reactive Power control capability. This can be done aggregated per
legal entity operating the PGM. (Organisation of the data shall be
agreed upon by the DSO and the TSO). (OS art25(1-2))
Compliance
 The PGM must inform the DSO about relevant changes to the
data. (OS art 16 (5d))
 The DSO shall be notified by the PGM when there is possible
impact on its compliance before initiating modification of technical
capabilities, as soon as possible after operational incident, foreseen
tests scheduled procedure to verify compliance. (RfG art34(1-5))
XXV




The PGM shall do compliance simulations with regard to LFSM-O,
LFSM-U, FSM, Fault-ride-trough capability, Island operation,
Capability of providing synthetic inertia, Reactive power capability,
Power Oscillations Damping control and Post fault power active
Recovery. (RfG art45). Some parts of the tests can be replaced by
equipment certificate.
The DSO shall be notified by the PGM in advance if the PGM is
going to make changes or have operational problems which could
affect its compliance. Also inform about any scheduled tests to
verify compliance so that the DSO can approve them. The DSO
shall also have the possibility to participate in these tests. These test
can also be carried out upon request from the DSO or the TSO (OS
art31)
The PGM can request from the DSO to provide the pre-fault and
post-fault conditions to be considered for FRT capability as an
outcome of the calculations at the connection point regarding:
o Pre fault minimum short circuit capacity, Pre-fault
operating point of the PGM expressed in Active Power
output and Reactive Power output and Voltage, Post-fault
minimum short circuit capacity at each connection point.
(RfG art9(3a))
The DSO can request the PPM to make compliance tests and
simulations throughout lifetime according to schedule or after
incident, like tests from installation. (RfG art35(2) & RfG art37(4)).
If the PGM is a PPM or a SPGM a part of the compliance tests are
done differently
o PPM: DSO can request PPM to make compliance tests
and simulations throughout lifetime according to schedule
or after incident, like tests from installation. (RfG art35(2)
& RfG art37(4)). Tests regarding LFSM-O (limited
frequency sensitive model-over frequency), demonstrate
operation at load level no higher than the setpoint, LFSMU (limited frequency sensitive model – under), FSM,
Frequency restoration control, Reactive power capability,



Reactive power control, Power factor control shall be
carried out. Some parts of the tests can be replaced by
equipment certificate. (RfG art43) shall be carried out
(RfG art41(2)). Some parts of the tests can be replaced by
equipment certificate.
o The PPM shall do compliance simulations with regard to
LFSM-O, LFSM-U, FSM, Fault-ride-trough capability,
Island operation, Capability of providing synthetic inertia,
Reactive power capability, Power Oscillations Damping
control and Post fault power active Recovery. (RfG art50).
Some parts of the tests can be replaced by equipment
certificate.
o SPGM: Tests regarding LFSM-O (limited frequency
sensitive model-over frequency), LFSM-U (limited
frequency sensitive model – under), FSM, Frequency
restoration control, Black start capability, House load and
Reactive power capability shall be carried out. Some parts
of the tests can be replaced by equipment certificate. (RfG
art40)
o The SPGM shall do compliance simulations with regard to
LFSM-O, LFSM-U, FSM, Fault-ride-trough capability,
Island operation, Reactive power capability, Post fault
power active Recovery and Power oscillations damping
control. (RfG art(47)). Some parts of the tests can be
replaced by equipment certificate
The PGM applies to the DSO for a LON when temporarily doing a
significant modification, loss of capacity, equipment failure that
leads to incompliance. (RfG art32(1-2))
The DSO issues a LON with timescale and responsibility for
expected solution and validity period. (RfG art32(3))
The PGM can apply for derogation to the DSO. (RfG art32(5))
“In case of” data
Compliance see scheduled data.
XXVI
One time data
New installation
 The DSO issues an EON to the PGM (RfG art29(2))
 The DSO issues an ION to the PGM and can request data:
Statement of compliance, technical data of the PGM, Equipment
certificates, simulation models, expected steady - and dynamic state
performance intended compliance tests. Equipment certificate is
fine to validate details. (RfG art30(2-3) & RfG art26(1-3))
 The DSO issues FON to the PGM after removal of all
incompatibilities found in ION (RfG art 31(2-3))
Derogation
 The PGM may submit derogation from one or multiple
requirements in the code to the DSO. The DSO defines what is
required to be included in the derogation but at least it shall include
identification of plant and owner, what the derogation concerns and
a justification for derogation. The DSO then performs a cost
benefit analysis and gives an opinion and sends that to the NRA
within six months. If the DSO has asked for a derogation regarding
the cost benefit analysis within one month and got it approved the
deadline to the NRA is three months instead. If derogation has been
filed the facility or network is seen as compliant until answer. All
non-compliant PGM shall apply for derogation within 12 months
from the day of the request. If this has not been done despite a
reminder the DSO have right to disconnect the facility. (RfG 53(2)
& RfG 54)
With Existing PGM Type B, C, D
A DSO has to be able to handle the following information change with an
existing PGM type B, C and D.
Real time-data
General information
 The PGM shall provide the DSO in real time with status of the
switching devices and circuit breakers at the connection point,
Active and Reactive power flows, current and voltage at the
connection point. (Organisation of the data shall be agreed upon by
the DSO and the TSO). (OS art26(1-2))
“In case of” data
Information of changes
 The DSO must be informed by the existing PGM about relevant
changes to the data. (OS art16(5d)) The existing PGM shall notify
the DSO in advance if it is going to make changes or have
operational problems which could affect its possibilities to comply
with the code. (OS art 31)
Scheduled data
Structural data
 The existing PGM shall provide the DSO with its scheduled
unavailability, Active power restriction and its forecast scheduled
Active power output at the connection point and any forecasted
restriction in the Reactive Power control capability. This can be
done aggregated per legal entity operating the existing PGM.
(Organisation of the data shall be agreed upon by DSO and TSO).
(OS art25(1-2))
XXVII
One time data
Frequency performance
 If the existing PGM is derogated from the frequency requirements,
the existing PGM shall inform the DSO and the TSO about their
frequency performance within 12 months and include time ranges
the facility can withstand without disconnection. (OS art 9(4))
Structural data
 The Existing PGM shall provide the DSO with structural data
including installed capacity, primary energy source, protection data,
reactive power control capability, capability of remote access to the
circuit breaker, voltage level and location of each PGM. (OS art24)
With Relevant Asset
A DSO has to be able to handle the following information change with a
Relevant Asset.
Scheduled data
Availability Plan
 Before 1 August the outage planning agent, if not a DSO, sends an
availability plan for the coming calendar year to the TSO and the
DSO. Until the 1 December it’s possible to send change requests to
the TSO. (OPS art34) The availability plan shall contain if the
relevant asset is available, unavailable or testing for any given hour
in the period. If the parties have agreed on higher level of time
detail the time period may be less than one hour. (OPS art32)
o The TSO then checks for incompatibilities with the
different plans and informs affected and request
alternative availability plans if that is needed. If the
incompatibilities remain the TSO makes an alternative
plan. (OPS art35)
Status testing
 All facilities with the status of testing should one month before a
test supply both the TSO and the DSO with a detailed plan of the
test. (OPS art42)
“In case of” data
Outage
 If an outage is forced the TSO and the DSO shall be informed
about the reason, duration and impact on other relevant assets
under its responsibility of the fault. (OPS art43)
XXVIII
With Reserve Providing Unit (RPU)
A DSO has to be able to handle the following information change with a RPU.
With Demand Facilities with Demand Side Response
(DSR)
One time data
A DSO has to be able to handle the following information change with a
Demand facility with DSR.
Application
 The DSO shall process the prequalification application from the
RPU unit or group within two months. The application sent by the
RPU unit includes at least Voltage level and connection point, Type
of reserve, Maximum capacity and Maximum rate of change. (LFCR
art 68)
Scheduled data
Structural data
 The RPU shall provide the DSO with structural data including
Frequency containment reserve data according to definition in
LFCR, frequency restoration reserve data and replacement reserve
data. (OS art24)
With Demand Facilities
Scheduled data
Metering
 The period for which the imbalance for all Balance Responsible
Parties is settled is to be determined by the TSO, within two years,
but it shall not exceed 30 minutes. (EB art58(1))
Real-time data
Compliance
 The DSO may monitor compliance. (DCC art 38-39)
General information
 A Demand facility with DSR shall provide to the DSO real time
active- and reactive power at connection point and confirmation
that the estimated actual values of demand response are applied.
(OS art 29(1))
Scheduled data
Capacity
 A demand facility with DSR shall yearly notify the DSO about
changes in capacity (detail is to be determined by DSO). (DCC art
22 (1o))
Structural data
 A demand facility with DSR unit shall provide the DSO with
structural minimum and maximum Active Power available for DSR;
and the maximum and minimum duration of any potential usage of
this power for DSR and a forecast of unrestricted Active Power
available for and any planned DSR. (OS art 29(1))
“In case of” data
Compliance
 The DSO shall be notified by the demand facility with DSR
immediately if modification of DSR is done. (DCC art 22 (1o))
XXIX








The DSO shall be notified by the demand facility with DSR in
advance directly or indirectly if wanting to increase, modernize or
replace equipment that may affect the compliance with the
requirements. (DCC art 19)
The demand facility with DSR shall as soon as possible notify the
DSO at any incidents or failures that can affect the compliance
monitoring or testing. (DCC art 37)
The demand facility with DSR must inform the DSO about relevant
changes to the data. (OS art 16 (5d))
The demand facility with DSR shall notify the DSO in advance if it
is going to make changes or have operational problems which could
affect its compliance. Also inform about any scheduled tests to
verify compliance so that the DSO can approve them. The DSO
shall also have the possibility to participate in these tests. These test
can also be carried out upon request from the DSO or the TSO (OS
art 31)
The DSO may test or simulate the compliance of the demand
facility. (DCC art 38-39)
Compliance test should be made for every new connection, when
equipment is modernized or when suspicion of incompliance exists.
This can be delegated to a third party(DCC art 38-39)
The demand facility with DSR should do the tests and with relevant
personal and monitoring equipment. (DCC art 38-39)
The demand facility with DSR shall communicate scheduled tests to
the DSO so that the DSO can participate. (DCC art 38-39)
performs a cost benefit analysis and gives an opinion and sends that
to the NRA within six months. If the DSO has asked for a
derogation regarding the cost benefit analysis within one month and
got it approved the deadline to the NRA is three months instead. If
derogation has been filed the facility or network is seen as
compliant until answer. All non-compliant PGM shall apply for
derogation within 12 months from the day of the request. If this
has not been done despite a reminder the DSO have right to
disconnect the facility. (DCC art 51-54)
New installation
 A new Demand facility with DSR connected below 1 kV need to
communicate information directly or indirectly to the DSO,
including location, maximum capacity, type of DSR, contact details
and equipment information which will be filled in a template
provided by the DSO. (DCC art 28)
Decommission
 The demand facility with DSR must notify the DSO prior to
decommission. (DCC art 28)
One time data
Derogation
 The demand facility with DSR may submit derogation from one or
multiple requirements in the code to the DSO. The DSO defines
what is required to be included in the derogation but at least it shall
include identification of plant and owner, what the derogation
concerns and a justification for derogation. The DSO then
XXX
With Aggregator with Demand Side Response (DSR)
A DSO has to be able to handle the following information change with an
Aggregator with DSR.
Real-time data
General information
 The aggregator shall provide the DSO with real time active- and
reactive power at connection point and confirmation that the
estimated actual values of demand response are applied. (OS art
29(2))
Scheduled data
Structural data
 The aggregator shall provide the DSO with structural minimum and
maximum Active Power available for DSR; and the maximum and
minimum duration of any potential usage of this power for DSR
and a forecast of unrestricted Active Power available for and any
planned DSR at least day ahead. (OS art 29(2))
compliance so that the DSO can approve them. The DSO shall also
have the possibility to participate in these tests. These test can also
be carried out upon request from the DSO or the TSO (OS art31)
One time data
New installation
 A new aggregator with DSR connected below 1 kV need to
communicate information directly or indirectly to the DSO,
including location, maximum capacity, type of DSR, contact details
and equipment information which will be filled in a template
provided by the DSO. (DCC art28)
Decommission
o The aggregator must notify the DSO prior to
decommission. (DCC art 28)
“In case of” data
Compliance
 The DSO shall be notified in advance by the aggregator directly or
indirectly if wanting to increase, modernize or replace equipment
that may affect the compliance with the requirements. (DCC art 19)
 The DSO shall as soon as possible be informed by the aggregator at
any incidents or failures that can affect the compliance monitoring
or testing. (DCC art 37)
 The aggregator must inform the DSO about relevant changes to the
data. (OS art 16 (5d))
 The aggregator shall notify the DSO in advance if it is going to
make changes or have operational problems which could affect its
compliance. Also inform about any scheduled tests to verify
XXXI
With Higher DSO
A DSO has to be able to handle the following information change with higher
DSO.
Real-time data
Compliance monitoring
 The higher DSO may monitor the DSOs compliance. (DCC art3839)
General information
 The DSO shall submit data to the higher DSO that they have
received from demand unit or aggregator including real time activeand reactive power at connection point and confirmation that the
estimated actual values of demand response are applied. (OS
art29(1-2))
 The DSO shall provide the higher DSO with data in real time from
the PGM with status of the switching devices and circuit breakers at
the connection point, Active and Reactive power flows, current and
voltage at the connection point. Organisation of the data shall be
agreed upon by the DSO and the TSO. (OS art26(1-2))
Scheduled data
Structural data from DSR units
 The DSO shall submit data to the higher DSO that they have
received from demand unit or aggregator including structural
minimum and maximum Active Power available for the DSR; and
the maximum and minimum duration of any potential usage of this
power for the DSR and a forecast of unrestricted Active Power
available for and any planned DSR. (OS art29(1-2))
Structural data from PGMs
 The DSO shall provide the higher DSO with data from the PGMs
concerning the PGMs scheduled unavailability, Active power
restriction and its forecast scheduled Active power output at the
connection point and any forecasted restriction in the Reactive
Power control capability. This can be done aggregated per legal
entity operating the PGM. Organisation of the data shall be agreed
upon by the DSO and the TSO. (OS art25(1-2))
“In case of” data
Compliance
 A significant DSO shall notify the higher DSO in advance directly
or indirectly if wanting to increase, modernize or replace equipment
that may affect the compliance with the requirements. (DCC art19)
 The DSO must inform the higher DSO about relevant changes in
the data (OS art16(5c))
 The higher DSO may test or simulate the compliance of the DSO.
(DCC art38-39)
 A compliance test should be done for every new connection, when
equipment is modernized or when suspicion of incompliance exists.
This can be delegated to a third party (DCC art38-39)
 The DSO should do the tests and with relevant personal and
monitoring equipment. (DCC art38-39)
 The DSO shall communicate scheduled tests to the higher DSO so
that the higher DSO can participate. (DCC art38-39)
One time data
Application of RPU
 The RPU unit or group or lower DSO sends a prequalification
application to the DSO at least including Voltage level and
connection point, Type of reserve, Maximum capacity and
Maximum rate of change. (LFCR art68)
 The DSO processes the application within two months and sends it
to the higher DSO. (LFCR art68)
XXXII
With Lower DSO

A DSO has to be able to handle the following information change with lower
DSO.

Real-time data

Compliance monitoring
 The DSO may monitor compliance. (DCC art38-39)
General information
 The lower DSO shall provide the DSO with data in real time from
the PGM with status of the switching devices and circuit breakers at
the connection point, Active and Reactive power flows, current and
voltage at the connection point. Organisation of the data shall be
agreed upon by the DSO and the TSO. (OS art26(1-2))
Scheduled data
Structural data
 The lower DSO shall provide the DSO with data from the PGMs
concerning the PGMs’ scheduled unavailability, Active power
restriction and its forecast scheduled Active power output at the
connection point and any forecasted restriction in the Reactive
Power control capability. This can be done aggregated per legal
entity operating the PGMs. Organisation of the data shall be agreed
upon by the DSO and the TSO. (OS art25(1-2))

The DSO may test or simulate the compliance of the lower DSO.
(DCC art 38-39)
Compliance test should be done for every new connection, when
equipment is modernized or when suspicion of incompliance exists.
This can be delegated to a third party (DCC art38-39).
The lower DSO should do the tests and with relevant personal and
monitoring equipment. (DCC art38-39)
The lower DSO shall communicate the scheduled tests to the DSO
so that the DSO can participate. (DCC art38-39)
One time data
New Installation
 RPU-unit or group
o The RPU unit or group sends prequalification application
to the lower DSO at least including Voltage level and
connection point, Type of reserve, Maximum capacity and
Maximum rate of change. (LFCR art68)
o The lower DSO processes the application within two
months and sends to the DSO. (LFCR art68)
“In case of” data
Compliance
 A significant lower DSO shall notify the DSO in advance directly or
indirectly if wanting to increase, modernize or replace equipment
that may affect the compliance with the requirements. (DCC art19)
 The lower DSO must inform the DSO about relevant changes in
the data (OS art 16(5c))
XXXIII
With TSO
A DSO has to be able to handle the following information change TSO.
Real-time data
Structural DS-data
 If the TSO determines the distribution network to be significant,
the DSO shall provide real time data regarding the substation
topology and active and reactive power in line bay, transformer bay
and injection in power generating facility bay and best available data
for aggregated generation and consumption in its network. (OS
art20)
Scheduled data
Disconnection frequencies
 The DSO shall yearly notify the TSO in writing at what frequency in
which connection point they have scheduled the start of the
demand disconnection and also to what extent that will happen.
(DCC art20(1e))
Structural DS-data
 If the TSO determines the distribution network to be significant,
the DSO need to provide for each substation; the voltage, lines
connected, transformers, significant grid users, reactor and
capacitors to the TSO. The DSO shall also inform the TSO about
frequency behavior of all new type Facilities that are not subject to
RfG, aggregated generated capacity and best estimate regarding
power by primary energy source. (OS art19)
Availability plan for Relevant Assets
 If the DSO has a relevant asset in its network: Before 1 November
the DSO get a preliminary availability plan for the coming year of all
relevant assets in its distribution network and before 1 December
the TSO will supply the DSO with an updated version. (OPS Art 37
& 39)
“In case of” data
Information gathering
 The TSO may gather information about generation, consumption,
schedules, balance positions, planned outages and own forecasts
from other parties in order to be able to analyze injections and
withdrawals in the transmission system nodes. (OS art 16(3))
One time data
Derogation
 The DSO may submit derogation from one or multiple
requirements in the code to the TSO. The TSO defines what is
required to be included in the derogation but at least it shall include
identification of plant and owner, what the derogation concerns and
a justification for derogation. The TSO then performs a cost benefit
analysis and gives an opinion and sends that to the NRA within six
months. If the TSO has asked for a derogation regarding the cost
benefit analysis within one month and got it approved the deadline
to the NRA is three months instead. If derogation has been filed the
network is seen as compliant until answer. (DCC art51-54 & RfG
art53-54)
XXXIV
With NRA
A DSO has to be able to handle the following information change with NRA.
One time data
Derogation
 The cost benefit analysis performed by the DSO and the opinion is
sent to the NRA within six months. If the DSO has asked for a
derogation regarding the cost benefit analysis within one month and
got it approved the deadline to the NRA is three months instead. If
derogation has been filed the facility or network is seen as
compliant until answer. (DCC art51-54 & RfG art53-54)
XXXV
Appendix 3 – Objectives, measures and solution generation
In this appendix the whole analysis is presented. The analysis is divided by the objectives and a full analysis
of every objective is conducted before presenting the next one. Every objective have a number matching
the number within brackets on the flows in the flow chart Figure 7 and Figure 8. This indicates which
information flows the objective deals with. For each objective the corresponding constrains are presented,
both in time and what EC-A does today. The first constrain always expresses after how many months of the
publication of the Network Code the corresponding paragraph will be binding law. Following the constrains
the different measures, that needs to be taken to deal with the objective, are presented. The next paragraph
presents possible solutions to every measure. The number within brackets indicates which measure it is
connected with. After that the different solutions are evaluated and a solution for every measure is chosen.
This might also be a combination of multiple solutions in the generation part. The solutions chosen are
marked in bold and the justification for this is presented in the evaluation paragraph.
XXXVI
Objective:
1
Provide and administrate new installation forms
for new PGM, DSR and aggregators
Constrains:
 36 months
 EC-A-Grid uses a web based application system for facilities
under 1.5 MW and loads
Measure:
1. Analyse and decide what information is to be included in the
forms
2. Create different forms for the different types of units
3. Receive and put information from forms into a system
Solution generation:
 The resources needed already exist within the company(1)
 The resources needed exist with other DSOs
collectively(1)
 Hire consultant to do the evaluation(1)
 May come rules from TSO of NRA(1)
 The resource needed already exists within the company(2)
 Hire consultant to do the form(2)
 Use already existing system(3)
 Invest in a new system(3)
 Automatic registration(3)
 Manual registration(3)
o The resources already exist within the
company(3)
o Hire a new resource(3)
Evaluation of the solutions:
1. Since the information required will be identical for all
Swedish DSOs the most beneficial would be for the DSOs to
collectively have a dialogue with SvK and EI to determine
what to be included in these forms. This dialogue can
preferably be dealt with within Swedish Energy.
2. The information flow for new PGM B, C & D will not be
considerable since only 7 facilities of this size is present today
and the rate of establishment is not high. This combined with
the fact that the NIS handles this kind of information today it
is economical to just manually add the extra information to
the system.
For all other facilities, where the amount of installations is
larger, the web based application system is already in place.
the web based application system communicates with other
systems for storage can continue to be used for this.
3. Furthermore EC-A-Grid can tell the system developer of the
web based application system collectively with the other
DSOs to increase the system with the extra information
required.
XXXVII
Objective:
2
Provide and administrate forms for existing
PGM and RPU
Constrains:
 18 months. “Within agreed time”
 EC-A-Grid does not have all the information required about
these facilities
Measure:
1. Analyse and decide if more information is to be included in
the forms than already given in the code
2. Create different forms for the different types
3. Receive and put information from forms into a system
Solution generation:
 The resources needed already exist within the
company(1)
 Hire consultant to do the evaluation(1)
 The resources needed already exist within the
company(2)
 Hire consultant to do the form(2)
 Use already existing system(3)
 Invest in a new system(3)
 Automatic registration(3)
 Manual registration(3)
o The resources already exist within the
company(3)
o Hire a new resource(3)
Evaluation of the solutions:
1. Since this information is not required today and it is fair to
assume that the information stated in the code is enough.
Extra information may be added later if needed. This results
in that the resources for the analysis exist within the
company.
2. There are no certified electrician involved in the process so
the web based application system cannot be used by default.
This combined with the limited number of facilities, 7, makes
it economical to use a computer based form that is
transferred to the owner via email. This form should be easy
to construct and therefore use resources that exist within the
company.
3. The NIS can be used to store the information since it is fairly
easy to add extra fields if needed.
Implementation period is fairly long and the number of
existing plants is not so high EC-A-Grid can manually register
this information in the NIS with the resources that already
exist within the company. Since the skills needed for this
work is limited it is possible to hire uneducated personal for a
limited time to be doing this.
XXXVIII
Objective:
3
Provide and administrate derogation forms for
new PGMs and Demand facilities with DSR
Constrains:
 36 months
 EC-A-Grid does not receive any derogation today so no
function for this exists
Measure:
1. Analyse and decide if more information is to be included in
the forms than already given in the code
2. Create different forms for the different types of units
3. Receive and put information from forms into a system
4. Alert person who is doing the derogation from CBA analysis
Solution generation:
 The resources needed already exist within the company(1)
 Hire consultant to do the evaluation(1)
 Do it together with other DSOs(1)
 The resources needed already exist within the
company(2)
 Hire consultant to do the form(2)
 Use already existing system(3)
 Invest in a new system(3)
 Automatic registration(3)
 Manual registration(3)
o The resources already exist within the
company(3)
o Hire a new resource(3)
 Alert person manually(4)
 Alert person by having the data system doing it
automatically(4)
Evaluation of the solutions:
1. Since EI should handle all of these applications from all over
Sweden one can assume that they would be interested in
supplying a template CBA. Therefore the form should be
built up using this. EC-A-Grid can work together with the
other DSOs, preferably through Swedish Energy, to get the
right information into the template.
2. If the content of the form is known the resources for making
it are limited and therefor available within the company.
Especially since the EC-A supply different actors with forms
today.
3. The received derogation is preferably stored within the
customer management system, connected to the appropriate
facility, to ensure that employees know where to find it. If
derogation is granted by EI, the new information should be
stored within the NIS to ensure that specific behaviour of this
facility is considered in calculations.
Since it is a derogation it is likely that the information is
different between different facilities and therefore the
registration into the NIS will be done manually. This should
not take too much time and therefore the resources should
exist within the company.
4. Since the registration is done manually it is possible to also
alert the person manually.
XXXIX
Objective:
4
Provide and administrate forms for new RPU
Constrains:
 18 months
 EC-A-Grid does not receive this kind of applications today
Measure:
1. Analyse and decide what information is to be included in the
forms
2. Create a form
3. Receive and store information from forms in system
4. Alert the person who is doing the network analysis
Solution generation:
 The resource needed already exists within the company(1)
 Hire consultant to do the evaluation(1)
 May come rules from TSO or NRA(1)
 The resource needed already exists within the
company(2)
 Hire consultant to do the form(2)
 Use already existing system(3)
 Invest in a new system(3)
 Automatic registration(3)
 Manual registration(3)
o The resource already exists within the
company(3)
o Hire a new resource(3)
 Alert person manually(4)
 Alert person by having the data system doing it
automatically(4)
Evaluation of the solutions:
1. Since this application will be sent to EC-D it is fair to assume
that SvK, in the end of the application chain, will want this
application in a standardized way. Therefore < should
provide a template or an already made form.
2. If SvK has provided a template the work load of doing the
form is not so big and should be handle with already available
resources. If SvK provides the form the resources required is
even more limited.
3. The application could be stored in the customer management
system. Since this possibility there is no need to invest in a
new system.
Since the number of these kinds of applications should be
limited the information could be registered manually with no
need to invest in an automatic system.
4. Since the storage is done manually it is easy to also alert the
person doing the assessment of the application manually.
XL
Objective:
5
Receive and store notification regarding
changes to technical aspects, decommission of
units and test schedules
Constrains:
 18 months for technical data. 36 months for test schedules
 EC-A-Grid receives application of changes to some extent
today
Measure:
1. Receive notification
2. Store new information and test schedule
3. Alert the compliance testing responsible
Solution generation:
 Receive automatically by computer system(1)
 Receive manually by email(1)
 Receive manually by mail(1)
 Use already existing system(2)
 Invest in a new system(2)
 Automatic registration(2)
 Manual registration(2)
o The resource already exists within the
company(2)
o Hire a new resource(2)
 Alert person manually(3)
 Alert person by having the data system doing it
automatically(3)
Evaluation of the solutions:
1. Changes in technical specification or decommissions of
facilities should be handled by the the web based application
system since a certified electrician is required. For new PGM
B, C, D and EC-E the number of changes should be limited so
it should be able to be handled manually by email. The same
goes for the test schedules of the compliance tests.
2. The information from the web based application system will
be stored automatically in the NIS. The other information will
have to be registered to the NIS manually. The test schedules
should be stored in the customer management system but a
notification of the date of test could be integrated into the
NIS. Since the limited amount of manual information to be
handled it is fair to assume that it can be done with existing
resources.
3. Since the information is registered manually the alerting of
the person doing the compliance tests could be done
manually too.
XLI
Objective:
6
Receive and store test plans from relevant assets
Constrains:
 18 months
 EC-A-Grid does not receive any test plans from units today
Measure:
1. Receive the test plan
2. Store the test plan
3. Alert compliance testing responsible
Solution generation:
 Receive automatically by computer system(1)
 Receive manually by email(1)
 Receive manually by mail(1)
 Use already existing system(2)
 Invest in a new system(2)
 Automatic registration(2)
 Manual registration(2)
o The resource already exists within the company(2)
o Hire a new resource(2)
 Alert person manually(3)
 Alert person by having the data system doing it
automatically(3)
Evaluation of the solutions:
 A relevant asset is only an asset with a significant effect on
cross border trade. This is thereby larger units close to
borders and it is fair to assume that EC-A-Grid will not have
any relevant assets in its grid.
Objective:
7
Receive information regarding frequency
performance of existing PGMs
Constrains:
 12 months
 EC-A-Grid does not have this information about the facilities
today
Measure:
1. Receive the information
2. Store the information
Solution generation:
 Receive automatically by computer system(1)
 Receive manually by email(1)
 Receive manually by mail(1)
 Use already existing system(2)
 Invest in a new system(2)
 Automatic registration(2)
 Manual registration(2)
o The resource already exists within the
company(2)
o Hire a new resource(2)
Evaluation of the solutions:
1. Since the amount of information from each of the 7 units is
low it is not beneficial to develop an automatic system for
this. Preferably an email with the information needed can go
out to the affected parties
2. This information can be stored in the NIS, perhaps some
minor alterations to the system is needed to have the
appropriate fields for this.
The registration can furthermore be done manually since the
amount of work is limited and not ongoing. The resources
for this should exist within the company and the skills needed
for this work are limited which makes it possible to hire
uneducated personal for a limited time to be doing this.
XLII
Objective:
8
Receive general information in real-time from
DSR and aggregators
Constrains:
 18 months
 EC-A-Grid have access to real-time values for the active
power of some demand facilities
Measure:
1. Receive and store information automatically
Solution generation:
 Use existing data system(1)
 Develop existing system(1)
 Invest in a new system(1)
Evaluation of the solutions:
 Since real-time values are received in the DMS for the existing
PGMs the DMS should be complemented to include the same
information for demand facilities and aggregators.
Objective:
9
Receive general information in real-time from
new and existing PGM B, C, D and lower DSO
Constrains:
 18 months for general information (power, current and
tension) and 36 months for more detailed information from
new PGMs
 EC-A-Grid has a system that receives active power flow from
own production sites
Measure:
1. Receive and store information automatically
Solution generation:
 Create a new system that can handle all the data(1)
 Create a new system that can handle the general
information(1)
 Use existing system for general information(1)
 Use existing system for all of the data(1)
Evaluation of the solutions:
1. The only problem is the detailed data from new PGMs type C
and D since only minor software changes are needed for the
DMS to be able to handle the general information. Therefore
the data from new PGMs C and D can be handled when those
facilities are planned since the amount of facilities will be
limited and the preparation time long.
XLIII
Objective:
10
Receive structural data from new and existing
PGMs directly or through lower DSO including
information on how they will act
Constrains:
 18 months
 How often the information should be sent is not define.
 EC-A-Grid doesn’t access this information today it is sent
directly from BRPs to SvK
Measure:
1. Define information to be included with TSO
2. Receive and store data
3. Alert sending responsible.
Solution generation:
 With TSO individually(1)
 With DSO collectively(1)
 Use already existing automatic system(2)
 Invest in new automatic system(2)
 Receive information and store in already existing system
manually(2)
 Receive information and store in new system manually(2)
 No alerting(3)
 Automatically via system in place(3)
 Manually(3)
o By email
o Telephone
Evaluation of the solutions:
1.
Since this information is sent day-ahead to SvK it may be
assumed that a similar timeframe is used in this information
flow
To minimize the work load for SvK and all DSOs it is
beneficial to do the definition of the information to be
included together with the other DSOs, preferably through
Swedish Energy. In this information society it is old fashioned
to send information through actors if they are not supposed
to asses it before sending it. Therefore this information
should be sent directly to the SvK with the possibility for the
EC-A-Grid to look up the information concerning them. The
reporting is supposed to be done per facility and if
information regarding the geographical location of it is
included it will probably remove the need for the information
flow to go via EC-A-Grid.
2. If the information will be sent directly to SvK there is no new
data system needed for the EC-A-Grid. Preferably the Cactus
system can be used and EC-A-Grid is just provided with the
log in to this system to access the information concerning
them. The costs for EC-A-Grid should be limited.
3. If the information is sent automatically no alerting is needed.
If not a central system is used this will involve implementing
a totally new system with all that comes with it.
XLIV
Objective:
11
Receive regarding forecasts of active power and
planned DSR and available power and duration
from demand facilities and aggregators with
DSR
Constrains:
 18 months
 For aggregators the information is day ahead or within a day
 EC-A-Grid does not have a system in place for this today
Measure:
1. Define information to be included together with TSO
2. Receive and store data
3. Alert sending responsible
Solution generation:
 With TSO individually(1)
 With DSO collectively(1)
 Use already existing automatic system(2)
 Invest in a new automatic system(2)
 Receive information and store in already existing system
manually(2)
 Receive information and store in new system manually(2)
 No alerting(3)
 Automatically via system in place(3)
 Manually(3)
o By email
o Telephone
Evaluation of the solutions:
1. This information is assumed to be similar to the one from
producers to SvK concerning their production and physical
trade (objective 10) but for the balancing market instead. This
means that a similar solution can be used.
To minimize the work load for SvK and all DSOs it is
beneficial to do the definition of the information to be
included together with other DSOs, preferably through
Swedish Energy. In this information society it is old fashioned
to send information through actors if they are not supposed
to asses it before sending it. Therefore this information
should be sent directly to the SvK with the possibility for the
EC-A-Grid to look up the information concerning them. In
this case it is vital that the information from the aggregators
include in which Distribution network the DSR providing
unit is located.
2. If the information will be sent directly to SvK there is no new
data system needed for the EC-A-Grid. Preferably a system
similar to Cactus, for day-ahead physical trade, could be
needed. On the other hand the EC-A-Grid needs to be
provided with the log in to this system but the costs should
be limited.
3. If the information is sent automatically no alerting is
required.
XLV
Objective:
12
Receive notifications as soon as possible from
new PGM type A, B, C and D, DSR and
Aggregators when not compliant due to an
incident
Constrains:
 36 months
 EC-A-Grid does not receive this kind of alarms today
Measure:
1. Receive the notification
2. Store the information
3. Alert compliance responsible
Solution generation:
 Via telephone(1)
 Automatically(1)
 Use already existing system(2)
 Develop already existing system(2)
 Invest in a new system(2)
 Register information into system automatically(2)
 Register information into system manually(2)
 Automatically(3)
 Manually(3)
 Compliance responsible looks up himself(3)
Evaluation of the solutions:
1. In total this should be a limited number of units and this
shouldn’t occur that often. But since the notification can
come in any time during the day it should be assessed by the
NOC since it is manned all the time, they also have
knowledge about fault reporting. The limited amount of
notifications to be expected makes it possible to handle them
via telephone.
2. Since this kind of information is not stored in the DMS today
some minor updates in the system probably is needed. But
these changes should be limited to adding extra fields.
Since the information is received manually via telephone the
information also has to be stored manually.
3. If the notification is crucial for the operation of the grid the
NOC will already have received the information from their
measuring units. Therefore this kind of information is mostly
useful for checking the compliance of different units.
Consequently no automatic alerting system is required. It is
probably enough that the person responsible for the
compliance of the different units checks the log for this kind
of faults once a month to determine if any further actions
needs to be taken.
XLVI
Objective:
Objective:
13
14
Receive availability plan from TSO for the
relevant assets in DSOs network.
Constrains:
 18 months
 Yearly, preliminary 1st of November and final 1st December
 EC-A-Grid does not receive an availability plan from TSO
today
Measure:
1. Receive the information
2. Store the information
Solution generation:
 Receive automatically with computer system(1)
 Receive manually by email(1)
 Receive manually by mail(1)
 Use already existing system(2)
 Invest in a new system(2)
 Automatic registration(2)
 Manual registration(2)
o The resource already exists within the company
o Hire a new resource
Evaluation of the solutions:
 A relevant asset is only an asset with a significant effect on
cross border trade. This is thereby larger units close to
borders and it is fair to assume that EC-A-Grid will not have
any relevant assets in its grid.
Receive information yearly about changes in
DSR capacity
Constrains:
 36 months.
 EC-A-Grid receive and administrate changes in subscribed
power from customers today
Measure:
1. Determine the details of the information
2. Receive and store information
Solution generation:
 The resource needed already exists within the
company(1)
 Hire a new recourse(1)
 Educate someone within the company(1)
 Automatically in already existing system(2)
 Automatically in new system(2)
 Receive information and store manually in already
existing system(2)
 Receive information and store manually in new system(2)
Evaluation of the solutions:
1. The level of detail needed for this information should be the
same all over Sweden and therefore it would be beneficial to
determine this together with the other DSOs, within Swedish
Energy for example. This would limit the competence needed
for EC-A-Grid. This combined with the fact that similar
information, regarding subscribed power, is handled today it
can be assumed that the resources exists within the company.
2. Since the changes in subscribed power are handled manually
this new information could be handled in the same way. That
means receiving emails from customers when they want to
change. If no email is received it is safe to assume that no
changes have been done. This information is then stored in
the customer management system.. A new field will be
required and since this customer management system is
widely used, the same request will come from multiple
parties.
XLVII
Objective:
Objective:
15
16
Receive information regarding duration of
forced outage from relevant asset
Receive availability plan from relevant asset
Constrains:
 18 months
 EC-A-Grid does not receive this kind of information today
from any party
Constrains:
 18 months
 Yearly, the 1st of August
 EC-A-Grid gets an outage plan from the PGMs today
Measure:
1. Receive the information
2. Store the information
Measure:
1. Receive the information
2. Store the information
Solution generation:
 Receive automatically by computer system(1)
 Receive manually by email(1)
 Receive manually by mail(1)
 Use already existing system(2)
 Invest in a new system(2)
 Automatic registration(2)
 Manual registration(2)
o The resource already exists within the company(2)
o Hire a new resource (2)
Solution generation:
 Receive automatically by computer system(1)
 Receive manually by email(1)
 Receive manually by mail(1)
 Use already existing system(2)
 Develop already existing system(2)
 Invest in a new system(2)
 Automatic registration(2)
 Manual registration(2)
o The resource already exists within the company(2)
o Hire a new resource(2)
Evaluation of the solutions:
 A relevant asset is only an asset with a significant effect on
cross border trade. This is thereby larger units close to
borders and it is fair to assume that EC-A-Grid will not have
any relevant assets in its grid.
Evaluation of the solutions:
 A relevant asset is only an asset with a significant effect on
cross border trade. This is thereby larger units close to
borders and it is fair to assume that EC-A-Grid will not have
any relevant assets in its grid.
XLVIII
Objective:
Objective:
17
18
If DSO has a Relevant Asset: Prepare and send
an availability plan to higher DSO and TSO
Constrains:
 18 months.
 Yearly, by the 1st of August send a plan for the coming year.
Until 1st of December changes in the plan can be made
Measure:
1. Prepare an availability plan
2. Send the availability plan
3. Keep track if changes are required
4. Apply for changes to the plan
Solution generation:
 Do the plan manually(1)
o The resource needed already exists within the
company
o Hire consultant to do the plan
o Educate person within the company
 A program makes the plan(1)
o Program already exists
o Develop already existing program
o Invest in new program
 Send the plan to TSO and higher DSO as requested(2)
 Compare and coordinate the plan with the ones received
from relevant assets in the network. Make plan in same
manner as above(3)
 Send changes if needed as requested from TSO and higher
DSO(4)
Evaluation of the solutions:
 A relevant asset is only an asset with a significant effect on
cross border trade. This is thereby larger units close to
borders and it is fair to assume that EC-A-Grid will not have
any relevant assets in its grid.
Supervise and possibly carry out compliance
tests and simulations on new PGM B, C, D,
Demand facilities and aggregators with DSR
and lower grid
Constrains:
 18 months for the right to carry out tests, 36 months for how
the tests are to be performed
 EC-A-Grid does not perform any tests of other facilities today
Measure:
1. Acquire the competence for supervising the tests
Solution generation:
 Acquire no competence(1)
 Evaluate when there could start being a risk for the company
and acquire competence then(1)
 Educate one person already in the business(1)
 Resources to carry out the tests already in the company(1)
 Hire a new person(1)
 Hire consultant to supervise the tests(1)
Evaluation of the solutions:
 Tests are not done today so someone needs to be educated
and have the responsibility for this. Depending on the
amount of tests to be carried out the work load is hard to
determine. Start by educating someone but it is possible that
a person needs to be hired to do this if the work load gets
too heavy. Hire a consultant is not a good idea since
someone needs to be responsible for this on a continuous
basis. To do nothing is not something that is in line with ECA being a serious company with a vision to build the most
resource effective region. Then it is not beneficial to avoid
applying the network codes as they are intended.
XLIX
Objective:
Objective:
19
20
Plan, execute and send information about
compliance test of own network
Constrains:
 36 months
 EC-A-Grid does not perform this kind of tests today
Measure:
1. Make sure to have the right resource
2. Have the right equipment
3. Store the information
4. Send test schedule to higher DSO
Solution generation:
 Educate one person already in the business(1)
 Hire a new person(1)
 Hire consultant to doing the tests(1)
 Use already existing equipment(2)
 Invest in new equipment(2)
 Rent the equipment(2)
 Use already existing system(3)
 Invest in a new system(3)
 Through channels already in place(4)
 Acquire new information channels(4)
Evaluation of the solutions:
1. Have a dialogue with EC-D to know what they expect from
the tests when they ask for them. If the knowledge about the
tests does not exist in the company educate someone to do
the test which should not involve too much work. Make that
person responsible for doing these tests. Preferably the same
person as responsible for the other test. The responsibility is
continuous so a consultant might not be beneficial. The
workload should not be so heavy that a new person is needed
2. Already existing equipment can probably be used since
EC-A-Grid today have equipment for various types of test.
3. The tests could be stored in the folder structure on the
common server.
4. Then the test can be transferred to EC-D through email since
the tests probably are far apart.
Assess pre-qualifications from RPUs in own or
lower network and send to higher DSO
Constrains:
 18 months
 2 months’ time to process, before sending to higher DSO
 EC-A-Grid does network analysis on new production units,
but nothing special for reserve power
Measure:
1. Do a network analysis to see if the RPU can deliver when it
should (within 2 months from application)
2. Store the information in
3. Send information to higher DSO
Solution generation:
 Use already available resources to conduct analysis(1)
 Hire new person to do it(1)
 Educate someone within the company(1)
 Use already existing system(2)
 Invest in a new system(2)
 Use already existing channel(3)
 Install a new information channel(3)
Evaluation of the solutions:
1. Since network analysis’s already are conducted for various
reasons the competence for this should be within the
company.
2. The NIS can handle the storage of the new information
storage since only a smaller change should be needed when
adding an extra field.
3. Since the information flow is not continuous it should be
enough with having a manual handling of the application by
accessing it from the customer management system and
sending it with an email. This means using the
communication channels already in place.
L
Objective:
Objective:
21
22
Examine if a CBA should be performed or not
for the submitted derogation
Constrains:
 36 months
 1 month to perform it and send derogation to NRA
 EC-A-Grid does not apply for derogation or does CBAs today
Measure:
1. Make sure to have the resources to perform the analysis
Solution generation:
 The resource needed already exists within the company(1)
 Educate one person already in the business(1)
 Hire a new person(1)
 Hire consultant to do the CBA(1)
Evaluation of the solutions:
1. Preferably the person that is doing the CBAs would do this
evaluation. Therefore it would be needed to just extend the
education a bit for this person to also be able to determine if
a CBA is needed.
Examine whether or not you need a derogation
from own compliance and send derogation to
TSO
Constrains:
 36 months
 After that it is 12 months from the date the requirement is
forced
 EC-A-Grid have the possibility to apply for derogation from
the income framework today
Measure:
1. Make sure to have the resources to perform the analysis
2. Send information to TSO
Solution generation:
 The resource needed already exists within the
company(1)
 Educate one person already in the business(1)
 Hire a new person(1)
 Hire consultant to do the evaluation(1)
 Use already existing channel(2)
 Install a new information channel(2)
Evaluation of the solutions:
1. Since SvK will handle all derogations from all DSOs in
Sweden it is fair to assume that they want them to be done in
a standardized way. Therefore they should supply the DSOs
with a template for doing this. But either way the resources
for doing the analysis should exist since the resource for
analysing if EC-A should apply for derogation from the
income frame work is needed within the company today.
2. Since there is no communication channel for this it will
consequently be new. This will not enforce any larger costs
on EC-A though and can because of the limited amount of
DSOs be assumed to be handled through email for example.
LI
Objective:
23
Conduct CBA and make an opinion of
derogations from PGM A, B, C, D and DSR and
send the CBA and the DSOs opinion to NRA
Constrains:
 36 months
 6 months to have an opinion if CBA is required. 3 months if
no CBA is required
 EC-A-Grid does not perform CBAs today
Measure:
1. Make sure to have the resources to perform a CBA
2. Store the information
3. Send information to NRA
Solution generation:
 Examine what kind of expertise is needed(1)
 The resource needed already exists within the company(1)
 Educate one person already in the business(1)
 Hire a new person(1)
 Hire consultant to do the CBA(1)
 Use already existing system (2)
 Invest in a new system(2)
 Use already existing channel(3)
 Install a new information channel(3)
Evaluation of the solutions:
1. Since EI should handle all of these applications from all over
Sweden one can assume that they would be interested in
supplying a template for this. Then EC-A-Grid can use the
template to analyse which expertise is needed.
The Amount of derogations should not be so high since type
A should be the large amount and they usually buy a package
deal. Especially when the new reform comes in place and
people with a smaller interest in these issues invest. It also a
possibility that more than one facility applies for the same
kind of derogation and thereby shortens the handling period
per derogation. Therefore it would only be needed to educate
a person since it shouldn’t take too much time but the
competence doesn’t exist in the company today.
2. The information could be stored in the customer
management system since the amount of CBAs should be
limited.
3. Since the information today to EI is handled by logging in to
their system and filling in a template one could assume that
this information would be handled in the same way.
Therefore a new information channel is needed, a log in to a
new system, but the effort and cost for EC-A-Grid would be
limited.
LII
Objective:
Objective:
24
25
Be able to measure customers with at least 30
minutes accuracy
Constrains:
 24 months then the exact accuracy will be defined
 EC-A-Grid measure a lot of clients by the hour today
Measure:
1. Make sure to measure with 30 minutes accuracy
2. Retrieve and store data from the meters
Solution generation:
 Update existing meters(1)
 Use already existing meters(1)
 Invest in new meters(1)
 Update already existing system(2)
 Use already existing system(2)
 Invest in a new system(2)
Evaluation of the solutions:
1. The exact demands will be defined within 24 months and
therefore it’s best to wait until then before doing changes to
the equipment. The evaluation below is based on the fact that
a metering with 30 minutes accuracy for all customers will be
defined by SvK.
2. A majority of the meters only need a minor software update
to handle measurements in a shorter timeframe. The rest
have to be changed to be able to manage this.
3. The existing system can handle the new information but
since the information flow will increase in size significantly
the system will need to be updated.
Send data regarding the schedules received
from the PGMs in the network.
Constrains:
 18 months.
 The interval is not defined but it is the same as received
 EC-A-Grid does not access this information today it goes
directly from BRP to SvK
Measure:
1. Agree with TSO on the organisation of data
2. Acquire information from system and send to TSO
Solution generation:
 The resource needed already exists within the
company(1)
 Hire a new recourse(1)
 Educate someone within the company(1)
 Let TSO decide on its own(1)
 Automatically through a new system(2)
 Manually through a new system(2)
 Manually through existing communication channels(2)
Evaluation of the solutions:
1. Since this information is sent day-ahead to SvK it may be assumed
that a similar timeframe is used for this information flow
To minimize the work load for SvK and all DSOs it is beneficial to
do the definition of the information to be included together with
the other DSOs, preferably through Swedish Energy. In this
information society it is old fashioned to send information
through actors if they are not supposed to asses it before sending
it. Therefore this information should be sent directly to the SvK
with the possibility for the EC-A-Grid to look up the information
concerning them.
2. If the information will be sent directly to SvK there is no new data
system needed for the EC-A-Grid. Preferably the Cactus system
can be used and EC-A-Grid is just provided with the log in to this
system to access the information concerning them. The costs for
EC-A-Grid should be limited. If not a central system is used this
will involve implementing a totally new system with all that comes
with it.
LIII
Objective:
Objective:
26
27
Send received real-time information from DSR,
aggregators and PGMs to Higher DSO
Send received information from DSR and
aggregators to higher DSO.
Constrains:
 18 months
 EC-A-Grid does not send any information to EC-D in
real-time
Constrains:
 18 months
 EC-A-Grid does not communicate this kind of information to
Measure:
1. Send the information automatically
Measure:
1. Acquire structural data from system
2. Send information to higher DSO
Solution generation:
 Use same system as for receiving(1)
 Develop existing system(1)
 Invest in another system(1)
Evaluation of the solutions:
1. This information is supposed to be aggregated all the way up
to SvK and therefore it is fair to assume that the protocol to
be used will be decided by them. Therefore the possibility
that the protocol is not directly compatible with the DMS
without adjustment is quite large. The most likely solution
might be a new system which handles this communication
automatically which has the possibility to acquire the
information from the DMS.
EC-D
Solution generation:
 Manually from system(1)
 Automatically from system(1)
 Through channels already in place(2)
 Install new communication channel(2)
Evaluation of the solutions:
1. In this information society it is old fashioned to send
information through actors if they are not supposed to asses
it before sending it. Therefore this information should be
sent directly to the SvK with the possibility for the EC-A-Grid
to look up the information concerning them. In this case it is
vital that the information from the aggregators include in
which Distribution network DSR providing unit is located.
2. For this a new communications channel is needed but the
cost should be low for EC-A-Grid since they only need to be
provided with a log in to be able to access the information.
LIV
Objective:
Objective:
28
29
If significant DSO: Send information regarding
the structure of the network to TSO in real-time
Constrains:
 18 months
 EC-A-Grid does not send any information to SvK in
real-time but the information is available in the DMS
Measure:
1. Send the information automatically
Solution generation:
 Use existing data system(1)
 Develop existing system(1)
 Invest in a new system(1)
Evaluation of the solutions:
1. It is fair to assume that EC-A-Grid’s grid will be significant in
a fairly close future since one DSR providing unit in the grid
is enough to achieve this.
Since the information is available but there are no
communication channels the existing system needs to be
complemented with another one to handle this. SvK needs to
decide one standard protocol to be used for this information
flow.
If significant DSO: Send information regarding
its network and the capacity of new generators
to TSO
Constrains:
 18 months
 EC-A-Grid sends information regarding cables on different
voltage levels and number of customers yearly to EI
Measure:
1. Acquire appropriate information
2. Send the information
Solution generation:
 Manually from system(1)
 Manually from equipment(1)
 The resources already exists in the company(1)
 Hire a new person(1)
 Through channels already in place(2)
 Install new communication channel(2)
Evaluation of the solutions:
1. This information exists in different systems. The information
required is similar to the one send yearly EI. Therefore one
can assume that this information also will be sent yearly.
Furthermore it might be beneficial to develop a way of
getting all the information automatically from the systems but
this is a measure to be dealt with later on.
This results in that the work load will be fairly similar to
before and therefore the resources within the company
should be able to handle it.
2. Since this information is not sent to SvK today a new
information channel is needed. To avoid having to send the
same information to EI and SvK it would be preferable if this
information could be dealt with together. Therefore a log in
is provided where EC-A-Grid fills in the information in SvKs
system, similar to Neon, and then the relevant information is
transferred to EI.
LV
Objective:
Objective:
30
31
If significant DSO: Notify higher DSO when
wanting to do changes that can affect
compliance.
Send information yearly regarding frequencies
for demand disconnection.
Constrains:
 18 months for notifications after the change and 36 months
for notifications in advance
 EC-A-Grid communicates with EC-D about changes that
affect them, this is done in a semi structured way
Constrains:
 36 months
 Yearly communication
 EC-A-Grid does not communicate the information regarding
their automatic disconnection at certain frequencies to
anyone
Measure:
1. Investigate which type of changes affects compliance
2. Introduce “notify higher DSO” in existing routines
3. Send information to the higher DSO.
Measure:
1. Acquire data
2. Send the information.
Solution generation:
 The resource needed already exists within the
company(1)
 Hire a new recourse to do the assessment(1)
 Educate someone within the company to do the
assessment(1)
 The resource needed already exists within the
company(2)
 Hire a new recourse to do the assessment(2)
 Educate someone within the company to do the
assessment(2)
 Through channels already in place(3)
 Install new communication channel(3)
Evaluation of the solutions:
1. Since EC-A-Grid does a lot of network analysis before
changes are done today it is reasonable to assume that the
investigation can be handled by existing personal.
2. To include this information into the routines so that EC-D
always is informed should not be such a big work load.
Therefore it should be handled by the existing resources
within the company.
3. It should be possible to use the channels already in place to
transfer the information since this currently is working
without problems.
Solution generation:
 Acquire data from system(1)
 Acquire data from equipment(1)
 Send information in writing as requested by TSO(2)
 Send information by email(2)
Evaluation of the solutions:
1. Since the information regarding these frequencies exists it is
no need to consult the equipment for these frequencies.
Since this information is to be send yearly and probably the
frequencies are not changed that often the work load for this
part should be small the following years. Consequently the
resources should exist within the company.
2. Since the SvK is receiving the information it is fair to assume
that they will request the information in a specific format.
Perhaps in the same system as the structural data to be sent
to SvK.
LVI
Objective:
Objective:
32
33
If DSO has a relevant asset: Send information
regarding duration of forced outage to TSO and
higher DSO and also information on how this
affects the availability of other relevant asset
owned by DSO
Constrains:
 18 months
 EC-A-Grid can see the availability status on their assets in
real-time
Measure:
1. Alert the assessment responsible when there is a forced
outage
2. Assess duration of forced outage and impact on other
relevant assets
3. Send information to TSO and higher DSO
Solution generation:
 Alert person manually(1)
 The data system alerts automatically(1)
 The resource needed already exists within the company(2)
 Hire a new recourse to do the assessment(2)
 Educate someone within the company to do the
assessment(2)
 Send information as requested by TSO and higher DSO(3)
Evaluation of the solutions:
 A relevant asset is only an asset with a significant effect on
cross border trade. This is thereby larger units close to
borders and it is fair to assume that EC-A-Grid will not have
any relevant assets in its grid.
Make all information, documents and tests
required from different parties publicly available
Constrains:
 18/36 months depending on which information
 EC-A-Grid have similar information available on their site
Measure:
1. Investigate and prepare the documents required
2. Publish information online
3. Notify affected parties about publication
Solution generation:
 The resource needed already exists within the company(1)
 Hire a new recourse(1)
 Educate someone within the company(1)
 Hire a consultant(1)
 Wait for directions from TSO(1)
 Cooperate with other DSOs(1)
 Resources within the company publish it online(2)
 Hire a consultant to publish it online(2)
 Notify affected parties about publication via mail(3)
 Notify affected parties about publication via email(3)
Evaluation of the solutions:
1. The difficult part here is to investigate and prepare which
documents are required for different actors. The complexity
of this matter and the fact that the same documents should
be needed all over Sweden results in that this preferably
should be conducted in cooperation with other DSOs and
SvK. This communication could be done within Swedish
Energy.
2. Since this kind of information is published on the homepage
already there are no difficulties in publishing more
information there. Consequently the resources within the
company are enough.
3. There is a routine for notifying affected parties through mail
when changes apply and this routine could also apply for this
matter.
LVII
Objective:
Objective:
34
35
It is possible for DSO to monitor the compliance
of DSR and lower DSO
Constrains:
 36 months
 EC-A-Grid can see all high tension customers in real-time and
ask for real-time values for 80% of the other meters
Measure:
1. Decide where/if/how monitoring is needed
2. Install monitoring equipment
3. Monitor information from equipment
Solution generation:
 Resource needed already exists within the company(1)
 Hire a new recourse to do the assessment(1)
 Educate someone within the company for the assessment(1)
 Equipment already in place is sufficient(2)
 Invest in new equipment(2)
 Install new equipment(2)
 Use already existing system(3)
 Invest in a new system(3)
 Resource needed already exists within the company (3)
 Hire a new recourse(3)
 Educate someone within the company(3)
Send information to TSO if they ask for it and
possibly make information regarding state of
system available for TSO
Constrains:
 18 months
 EC-A-Grid sends the actual and planned consumption
monthly to BRPs
Measure:
1. Ensure that all information exists and is easily accessible
Solution generation:
 Wait until TSO demands information(1)
 Pro-actively ensure that the information is accessible(1)
Evaluation of the solutions:
1. This paragraph in the code is probably a precaution if the
data needed by SvK is not mentioned in any other paragraph.
Information flows due to this paragraph is probably tightly
linked to other paragraphs and can if they appear be dealt
with in the same way as that paragraph. Therefore it is better
to wait until SvK demands information and then solve the
situation and possibly implement it in the correct routine.
Evaluation of the solutions:
1. Since this is a new concept and it is up to EC-A-Grid to
decide whether or not to monitor. This decision should be
evaluated continuously but the resources should exist within
the company.
2. For the current time the equipment already in place is
sufficient to handle the monitoring to the extent needed.
Probably it is useful to make sure that the meters in the DSR
providing units report their measurements daily. If the
decision changes later on new equipment probably will be
needed
3. For the current time the resources for the monitoring should
exist within the company.
LVIII
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