DUTCH FLEXIBILITY POLICY: AN ANALYSIS OF FLEXIBILITY

POLICY AND REGULATION TO ACCOMMODATE VARIABLE

RENEWABLE ENERGY

By

Koen Gorrissen

A Thesis Submitted to the

Faculty of Engineering at Cairo University

and Kassel University

in Partial Fulfilment of the

Requirements for the Degree of

MASTER OF SCIENCE

In Renewable Energy and Energy Efficiency

for the MENA Region

REMENA

University of Kassel - Kassel, Germany

University of Cairo - Giza, Egypt

November - 2017

DUTCH FLEXIBILITY POLICY: AN ANALYSIS OF FLEXIBILITY

POLICY AND REGULATION TO ACCOMMODATE VARIABLE

RENEWABLE ENERGY

By

Koen Gorrissen

A Thesis Submitted to the

Faculty of Engineering at Cairo University

and Kassel University

in Partial Fulfilment of the

Requirements for the Degree of

MASTER OF SCIENCE

In Renewable Energy and Energy Efficiency

for the MENA Region

REMENA

Under the Supervision of

Prof. Dr. K. Rohrig

……………………………….

Prof. Dr. M. S. Elsobki

……………………………….

Professor of Integrated Energy Systems

Faculty of Electrical engineering and

computer science, Kassel University

Professor Energy Planning

Faculty of Engineering, Cairo University

University of Kassel - Kassel, Germany

University of Cairo - Giza, Egypt

November - 2017

DUTCH FLEXIBILITY POLICY: AN ANALYSIS OF FLEXIBILITY

POLICY AND REGULATION TO ACCOMMODATE VARIABLE

RENEWABLE ENERGY

By

Koen Gorrissen

A Thesis Submitted to the

Faculty of Engineering at Cairo University

and Kassel University

in Partial Fulfilment of the

Requirements for the Degree of

MASTER OF SCIENCE

In Renewable Energy and Energy Efficiency

for the MENA Region

REMENA

Approved by the

Examining Committee

........................................................

Prof. Dr. sc. Techn. D. Dahlhaus, University of Kassel

........................................................

Prof. Dr. K. Rohrig, University of Kassel

........................................................

Prof. Dr. M. S. Elsobki, Faculty of Engineering, Cairo University

........................................................

Prof. Dr. S. Kaseb, Faculty of Engineering, Cairo University

University of Kassel - Kassel, Germany

University of Cairo - Giza, Egypt

November – 2017

Engineer’s Name: Koen Gorrissen

Date of Birth: 22/06/1991

Nationality: Dutch

E-mail: koengorrissen@gmail.com

Phone: +31 (0)6 44613643

Address: Opsterland 34, 3524 CH,

Utrecht, The Netherlands

Registration Date: 9/11/2017

Awarding Date: ………………….

Degree: Master of Science

Department: …………………..

Supervisors: Prof. Dr. K. Rohrig

Prof. Dr. M. S. Elsobki

Examiners:

Prof. Dr. D. Dahlhaus

Prof. Dr. S. Kaseb

Prof. Dr. M. S. Elsobki

Title of Thesis:

Dutch flexibility policy: An analysis of flexibility policy and regulation to accommodate variable

renewable energy

Key Words:

Flexibility; Policy; The Netherlands; Variable Renewable Energy integration

Summary:

An energy transition is unfolding in the Netherlands. Increasing shares of variable renewable energy demand the

consideration of power system flexibility by policy and regulation. This paper investigates current Dutch flexibility

policy and discussions surrounding the flexibility of the power system. It investigates whether new arguments and

new policy or regulatory perspectives from literature and foreign practice could enrich these discussions. To do so,

Dutch policy, foreign practices and academic literature are reviewed, and experts from various sides of the Dutch

power sector are interviewed. Findings include a good positioning for further mass integration of variable

renewables, with only some local grid congestion challenges on the short-term. Energy supply and balancing are

relatively unproblematic at least until 2030 due to overcapacity of conventional power plants. The interviews showed

strong agreement about i.a. the introduction of 15-minute pricing, the enabling of distribution system operators to

contract flexibility products and the undesirability of capacity mechanisms. Discussion, on the other hand, is apparent

about the merit of dynamic electricity prices and grid tariffs for household consumers, the most viable model for

aggregation services, the merit of locational pricing and the merit of strengthening export and import capacities.

Underlying these discussions are important differences in political values. These values are the adherence to cost-

causing principles versus the socialisation of costs, decentralisation versus centralisation, market primacy versus

government intervention and the level of policymaking. The outcomes of the discussions are at least partially

grounded in differences in interests of actors in the sector.

Dutch flexibility policy: An analysis of flexibility policy and

regulation to accommodate variable renewable energy

Koen Gorrissen | 33422749

Submitted to the Faculty of Electrical Engineering and Computer Science University of

Kassel in partial fulfilment of the requirements for M.Sc. degree in Renewable Energy and

Energy Efficiency for the MENA Region REMENA

November 2017

Prof. Dr. K. Rohrig Prof. Dr. M.S. Elsobki Prof. Dr. D. Dahlhaus Prof. Dr. S. Kaseb

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i

Abstract An energy transition is unfolding in the Netherlands. Increasing shares of variable renewable energy

demand the consideration of power system flexibility by policy and regulation. This paper investigates

current Dutch flexibility policy and discussions surrounding the flexibility of the power system. It

investigates whether new arguments and new policy or regulatory perspectives from literature and

foreign practice could enrich these discussions. To do so, Dutch policy, foreign practices and academic

literature are reviewed, and experts from various sides of the Dutch power sector are interviewed.

Findings include a good positioning for further mass integration of variable renewables, with only some

local grid congestion challenges on the short-term. Energy supply and balancing are relatively

unproblematic at least until 2030 due to overcapacity of conventional power plants. The interviews

showed strong agreement about i.a. the introduction of 15-minute pricing, the enabling of distribution

system operators to contract flexibility products and the undesirability of capacity mechanisms.

Discussion, on the other hand, is apparent about the merit of dynamic electricity prices and grid tariffs

for household consumers, the most viable model for aggregation services, the merit of locational pricing

and the merit of strengthening export and import capacities. Underlying these discussions are important

differences in political values. These values are the adherence to cost-causing principles versus the

socialisation of costs, decentralisation versus centralisation, market primacy versus government

intervention and the level of policymaking. The outcomes of the discussions are at least partially

grounded in differences in interests of actors in the sector.

ii

Acknowledgements I would like to thank all colleagues at Agora Energiewende for their valuable support, insights and

discussions, and especially Christian Redl for his supervision, guidance and advice during my three-

month internship in Berlin. My sincere thanks as well to all interviewees for their time, attention, and,

more importantly, for openly sharing their knowledge and insights which have been of crucial

importance to this research. I would like to thank my supervisors Prof. Kurt Rohrig and Prof. Elsobki for

showing me the importance of working on this subject, for the independence they provided me with,

and for their guidance. My sincere thanks to all my classmates and REMENA staff for their help and

concern. Finally, I would like to thank my friends, family and especially Arin Koreman for their support

and commenting on my work.

iii

Statement of originality

To the best of my knowledge, I do hereby declare that this thesis is my own work. It has not

been submitted in any form of another degree or diploma to any other university or other

institution of education. Information derived from the published or unpublished work of others

has been acknowledged in the text and a list of references is given.

Date: 8-11-2017

Place: Utrecht

Name: Koen Gorrissen

Signature ....................................................................................

iv

Contents

Abstract .......................................................................................i

Acknowledgements ................................................................ ii

Statement of Originality ...................................................... iii

Contents ................................................................................... iv

List of figures .......................................................................... iv

List of tables ............................................................................ iv

List of abbreviations ................................................................v

1. Introduction .................................................................... 1

2. Methods and sources .................................................. 2 2.1. Literature review .................................................. 2 2.2. Interviews ............................................................. 3

3. literature review results .............................................. 3 3.1. Global Energy transition ...................................... 4 3.2. The Dutch energy transition ................................. 6 3.3. Flexibility .............................................................. 9

3.3.1. Flexibility challenges ................................. 11 3.3.2. Flexibility options ...................................... 14

3.3.2.1. Demand-side flexibility ......................... 14 3.3.2.2. Market Design ...................................... 18 3.3.2.3. System flexibility ................................... 24 3.3.2.4. Supply-side flexibility ............................ 28

4. Interview Results ......................................................... 31 4.1. Challenges .......................................................... 31 4.2. Flexibility options ............................................... 32

4.2.1. Demand-side flexibility.............................. 32 4.2.2. Market design ........................................... 36 4.2.3. System flexibility ....................................... 42 4.2.4. Supply-side flexibility ................................ 44

4.3. Overarching discussions and underlying values . 45

5. Discussion .................................................................... 46

6. Conclusion ................................................................... 48

7. References .................................................................... 50

Annex A: Interview questions ........................................... 57

Annex B: list of interviewees .............................................. 66

List of figures figure 1: Overview of relevant actors in the

Dutch power sector and their relations. 7

figure 2: Historical data up to and including

2015 and projection of electricity

production from 2016 by energy source

in the Netherlands. ....................................... 8

figure 3: Percentages of VRES technologies

with respect to total power generation

in several jurisdictions ................................. 9

figure 4: Schematic overview of the

integration challenge, its causes and its

solutions .......................................................... 15

figure 5: Schematic overview of the different

power markets, their bidding periods,

gate closure times and contract

durations ......................................................... 19

figure 6: Results of a Fraunhofer power

generation simulation at different levels

of spatial aggregation ............................... 20

figure 7: Installed capacity per generation

type in the Netherlands ............................ 29

List of tables table 1: Grid properties of electrical Networks

in the countries under consideration .... 10

table 2: Categorization of flexibility options . 16

table 3: Categorization of storage types ...... 27

v

List of abbreviations ACM (Dutch) Authority Consumer and

Market

BMWi (German) Federal Ministry for

economic affairs and energy

(Bundesministerium für Wirtschaft

und Energie)

BRP Balancing Responsible Party

BSP Balancing Service Providers

CAES Compressed-Air Energy Storage

CCS Carbon Capture and Storage

CH4 Methane

CWE Central-West Europe

DAM Day-Ahead Market

DRES Distributed Renewable Energy

Source

DSM Demand Side Management

DSO Distribution System Operator

EES Electrical Energy Storage

ETS Emission Trading System

EU European Union EV Electric Vehicle

EZ Dutch ministry of economic affairs FiT Feed-in Tariff

FTR Financial Transmission Rights

H2 Hydrogen gas

ICT Information and Communication

Technology

IDM Intraday Market

IOU Investor-Owned Utility

ISO Independent System Operator

kWh kiloWatt-hour (energy)

MW Mega Watt (power)

MW/h MegaWatt per hour (ramp-rate)

MWh MegaWatt-hour (energy)

NWE North-West Europe

PHES Pumped-Hydro Energy Storage

PLEF Pentalateral Energy Forum

PtH Power-to-Heat

PV Photo-Voltaic

R1 Primary Reserve Market

R2 Secondary Reserve Market

R3 Tertiary Reserve Market

RE(S) Renewable Energy (Source)

RfG Requirements for Generators

ToU Time-of-use

TSO Transmission System Operator

TYNDP Ten-year Network Development Plan

VoLL Value of Lost Load

VRE(S) Variable Renewable Energy (Source)

XBID Cross-Border Intraday

1

1. Introduction The transition towards a renewable energy

system in The Netherlands is developing slowly,

but picking up speed. According to the National

Energy Survey,1 the goal of 16% renewable

energy out of the total energy consumption in

2023 will be reached with only a minor

deficiency of 0,1% (Schoots, Hekkenberg, &

Hammingh, 2016). The growth of RE usage in

the electricity sector has been much higher and

will expectedly rise from 15,0% in 2016 to 37,7%

in 2020 and to 41,1% in 2023. New capacity is

dominated by wind power and, to a lesser

extent, by solar power. These variable

renewable energy sources (VRES) are

fundamentally different from technologies that

generate electricity by burning fossil fuels. The

intermittent character causes several challenges

which together are often described as the

‘integration challenge’ or ‘flexibility challenge’

(Agora Energiewende, 2015).

The challenge is caused by the simultaneity

of supply and demand of electricity, which

requires power to be produced at the same time

as it is consumed by the end-user. Moreover,

supply and demand should be matched over

space, while they find their origin at different

locations. Because VRE supply is dependent on

external conditions such as wind and solar

irradiation, the time and place of power

production are less controllable and less

predictable. A power system that is increasingly

based on VRES, therefore, needs to deal with

reducing flexibility on the supply side and

requires the incorporation of other flexible

resources. Flexibility, herein, is understood as

the ability of the power system to match

demand and supply economically and

efficiently, both temporally and spatially.2 The

flexibility challenge, therefore, consists of

integrating flexible resources or limiting the

increasing flexibility needs. The methods to

1 This paper has made use of the national energy survey serveral times. Altough the most recent national energy

survey was published just before finalising this paper, it could not be included due to lack of time.

2 Many different definitions of flexibility exists, but they usually include the same aspects, albeit putting different

weights on certain aspects. See for example those of ACER and CEER (2017b), CE Delft and Microeconomics

(2016), Triple E (2015), and Grave, Papaefthymiou and Dragoon (2014).

address this challenge are collectively denoted

as flexibility options. Whereas the challenge is

relatively mild at low percentages of VRE

injection in the grid, it becomes much more

pervasive when the fraction of VRE technologies

rises, which is the case in many power systems

all over the world.

Research into the integration challenge has

been widely performed (e.g. CE Delft &

Microeconomix, 2016; Fraunhofer IWES, 2015;

IEA, 2014a; Martinot, 2016; SWECO, Ecofys,

Tractebel engineering, & PWC, 2015). Flexibility

needs and options for the Netherlands have

been discussed for the electricity market by, for

example, Triple E (2015), within the policy

analysis of the International Energy Agency (IEA,

2014a), within the National Energy Survey

(Schoots et al., 2016) and other research

(Frontier Economics, 2015; Hers, Rooijers,

Afman, Croezen, & Cherif, 2016; Hout, Koutstaal,

Ozdemir, & Seebregts, 2014; Van der Welle &

De Joode, 2011). The Ministry of Economic

Affairs (EZ) has also discussed policy aspects of

VRE integration (EZ, 2016a, EZ, 2016b). Yet,

considering the flexibility of energy systems is

one of the key issues for a sustainable energy

transition, the challenges of integration did not

receive enough dedicated attention yet.

Especially the non-technical issues of market

development, planning, the design of policy,

institutions and regulation, and the economic

aspects are under-exposed. While technical

assessments are available, there is room for an

overarching understanding of and discussion

about policy and regulation for maintaining a

flexible power system while integrating higher

percentages of VRES.

This research will take these aspects into

account to discuss the Dutch renewable energy

integration policy and its missing links. To do so,

it will look both to solutions under discussion

within the country and solutions brought

2

forward in selected countries with high VRE

penetration grades and academic literature.

Thus, this research attempts to answer the

following question:

How does Dutch policy currently address the

effects of the integration of variable

renewable energy on the flexibility of the

power system, what are the relevant

discussions to adapt policy, institutions, and

markets to maintain flexibility, and what are

the positions and arguments in these

discussions?

This research intends to create a deeper

understanding of the policy framework that is

currently in place while describing and feeding

the discussions with options found in literature

and the context of high VRE penetration

countries. The overview of the policy landscape

should enable further planning of an energy

system with growing dependencies on

renewable technologies. As will be explained in

the methodology section of this thesis, this

would be done by the combination of a

literature study and interviews with experts in

research, industry and governmental institutes.

The next section will discuss the methods

and sources used for both parts of the research.

Subsequently, the results are presented for the

literature review (chapter 3) and the interviews

(chapter 4) respectively. Chapter 5 discusses the

findings and implications for research and

policy. Finally, chapter 6 reflects on and

summarizes the paper.

2. Methods and sources As has been mentioned in the introduction, the

research question will be addressed through a

combination of a literature review and

stakeholder interviews. The literature review will

give an overview of relevant policy discussions

and possible measures in the Netherlands and

selected countries. The interviews are meant to

create an in-depth understanding of the

positions of Dutch stakeholders in these

discussions.

For both the literature review and the

interviews, this paper focusses on policy steps

until 2030. This time frame is chosen because an

important stretch in the Dutch energy transition

is expected to be made before that date, as will

be further clarified in the results sections itself.

However, since other emission goals are

determined until 2050, some attention is given

to the longer term as well.

Furthermore, while this research is

delineated around Dutch policy, it does include

considerations out of international perspective.

Since the Dutch power system is physically

highly interlinked with neighbouring countries

and politically dependent on the European

Union (EU) and other cooperations such as the

Pentalateral Energy Forum (PLEF), some if not

much of the policy decisions take place on other

levels than the national one.

The following sections describe the methods

and sources used for the literature review and

the interviews respectively.

2.1. Literature review

The main purpose of the literature reviews is to

create an overview of the relevant discussion for

power system flexibility in the Netherlands and

other countries. Besides having value in itself, it

will also serve as input for the interview

questions.

Firstly, the literature review will discuss, in

general terms, the challenges to accommodate

higher percentages of renewable energy to

better understand current policy frameworks

around VRE. Secondly, it will discuss the

structure of the Dutch energy system and its

ongoing transition. Thirdly, the flexibility

challenge is discussed in detail. The third section

will be split into two parts. While the first part

covers the flexibility challenges caused by the

integration of higher percentages of VRES, the

second part discusses the options available in

literature and other countries to address these

challenges.

The sources used for the literature review are

not limited to scientific work but include a range

of reports and policy papers. While scientific

research is an important source for flexibility

policy, it is necessary to include further

3

information about installed policy as well as

positions on policy from different angles.

Some methodological considerations are

taken from Flyvbjerg’s phronetic planning

approach (Flyvbjerg, 2004, 2009). According to

his work, although rationality is often

considered to be the single most important

base of planning, it bases itself on certain

‘truths’ which are actually debatable. Instead of

taking these truths for granted, he

acknowledges that the value of certain truths is

determined by power relations and interests.

Since multiple ‘truths’ exist serving different

interest, there is no single ‘rational’ answer to

political issues. For policy making, this means

that instead of searching for a single best

answer, one could, for a range of policy options,

determine which parties would benefit and

which would be harmed by it. Concretely for this

research, it means that because these sources

are subject to the interests and capabilities of

the authoring entities, they are treated as views

of the relevant institutions rather than valued as

undisputable solutions. Because of this, the

literature review becomes an overview of the

various discussions about flexibility policy and

different positions in these discussions, rather

than an overview of a body of knowledge.

2.2. Interviews

While the literature review gives an overview of

different discussions and considerations, the

interviews are meant to get a more personal

and in-depth understanding of these positions

and a more specific application to the Dutch

(and European) context. Like the literature

review, the interview does not attempt to find

single answers or solutions, nor takes positions

in the various discussions. Since the

interviewees represent not only themselves but

are also interviewed from a position of an

institution, this part of the research will, indeed,

attempt to shed light on interests of institutions.

As mentioned in the previous section, the

questions prepared for the interviews are based

on the literature review. Since the literature

review will highlight the relevant discussions, its

findings can be used to enable a more precise

and informed discussion. The interview

questions (in Dutch) are included in annex A.

The interviewees are selected to represent a

range of various institutions dealing with the

Dutch power system, including the Ministry of

Economic Affairs (EZ), academia, other research

institutions, the transmission system operator

(TSO), a distribution system operator (DSO), and

an energy company. The interviewed experts

are all active in discussions surrounding the

flexibility challenge. A total of 17 persons are

interviewed, representing 11 different

institutions in 11 separate interview sessions. The

interviewees are listed in annex B.

The interviews are semi-structured according

to the questions in annex A and approximately

last an hour. Yet, depending on the interviewee

and the time available, more or less time is

taken to conduct these interviews. Most

interviews are conducted face-to-face with

some exceptions which are conducted by

phone. The interviews are recorded and

transcribed. Subsequently, for each interview,

relevant information is coded and organized

per theme.

The interview results are presented

thematically in the same structure as the

literature review. Where quotes are taken up in

the interview results, they are checked with the

respective interviewee and, in some cases,

edited upon his or her request to reflect his or

her position more clearly. Where necessary, the

interview results are compared with the

literature review.

3. Literature review results As discussed in the introduction, VRE

technologies such as solar and wind energy, are

fundamentally different from technologies that

generate electricity by burning fossil fuels.

These technologies differ not only

technologically but also have distinct economic

and social impacts.

Technologically, the amount of electricity

generated by VRES depends on the availability

of resources on a very short timescale and is,

therefore, fluctuating or variable (Agora

4

Energiewende, 2015). Their output is not as

easily dispatchable as compared to the output

of gas, coal, oil and oil product technologies,

and is also less controllable than other

renewable resources such as or biomass. As

these variations depend on external conditions,

more uncertainty is introduced into power

system management because of larger forecast

errors (CE Delft & Microeconomix, 2016).

Furthermore, the generating capacities of

distributed VRE technologies such as rooftop

solar power and wind turbines are typically

many times smaller than those of conventional

power plants.3 This leads to a much more

dispersed electricity generation than in a system

with only conventional thermal power plants.

VRES and conventional power generation are

economically disparate as well since the cost for

VRE technologies is largely determined by their

investment while they run at virtually no

marginal costs (Agora Energiewende, 2015).4

This contrasts sharply with fossil fuel

technologies where the costs are largely

determined by the energy resources they need,

which leads to a higher marginal fraction.

A socio-economic difference between the

VRES and conventional technology is identified

by the actors that are relevant to the

development of the technologies. As is shown

by e.g. Geels (2014), the actors that represent

the development of VRES are not the same

actors as those that represent the conventional

power production.5

Two final characteristics of VRES have

opposing effects on its local acceptance. The

strong visibility of VRES power plants has led to

3 The difference in capacities can be in the order of several hundred times the rated power. While e.g. a modern

wind power generator has the capacity of between 1 to 6 MW, a gas or coal fired power plant can produce

from several hundred MW to multiple GW.

4 The concept of marginal costs refers to the amount of costs that is related to produce one unit more of the

same good. While for fossil fuel power generation these costs are largely determined by its fuels, renewable

energy does not have substantial different costs when running at low or at high capacities.

5 As is discussed in the next paragraph, Geels (2014) claims that the difference in interest between the current

regime actors, representing conventional power generation, versus the niche actors, representing the

development of VRES, causes a hindrance in the process of low-carbon transitions.

the opposition against their development in

many areas. Yet, the absence of pollutants and

greenhouse gas emissions during generation of

electricity is a driver for these technologies.

These and other distinctions between

conventional power generation and VRES cause

several transformation issues in the energy

system. The first two sections of this chapter will

discuss the problems and solutions for the

diffusion of more variable as well as

dispatchable renewable energy technologies to

provide the thesis with both a global and a

national context of the energy transition

respectively. The third paragraph thematically

discusses the set of issues related specifically to

the integration of higher percentages of

variable renewable energy sources into the grid.

It will discuss the problems, theoretical

solutions, policy in the Netherlands and policy

in selected frontrunner countries.

3.1. Global Energy transition

This section introduces problems and solutions

in adopting larger fractions of renewable

energy sources (RES) into the power system.

Although the adoption of renewables is

intrinsically linked with the problems of grid

integration, flexibility, and balancing, this

section is limited to the problems and solutions

in creating a space for the RE technologies

themselves, independent of their integration

into the system. Yet, a complete overview of the

integration and flexibility challenges requires

knowledge of the other barriers to the

development of a renewable energy system and

is, therefore, included here.

5

The past few years, cost reductions,

improved policy frameworks, increased

possibilities for financing, political importance,

energy security concerns, and rising energy

demand have caused the diffusion of renewable

energy technology to rise rapidly (REN21, 2016).

Investments in RES are rising, so are their

installed capacity and their yearly energy

production. The total global capacity of

renewables rose in 2014 by 9% up to 1 849 GW

at the end of the year, which is 23,7% of all

global electricity production.6 The yearly global

capacity additions of renewable energy have

become greater than those of all fossil fuel

technologies (REN21, 2016).

Even though the development has been

steady, RES are still heavily dependent on policy

and, therefore, on political commitment.

Commitment to ensure growth in the usage of

renewable energy has created several

agreements, including most prominently the

agreement between 195 countries at the 21st

Conference of Parties (COP21) in Paris by United

Nations Framework Convention on Climate

Change in December 2015. However, these

commitments need to be converted into

concrete policies, investments, research and

development of technologies to meet the

specified targets. Whether policy frameworks

and practices are well-adapted and successful in

further stimulating growth in the development

of RE technologies depends on whether and

how effectively they address the relevant

problems. These problems with the adoption of

renewable energy technologies can roughly be

divided into social, economic, technological and

political aspects.

Several social aspects can be identified for

the adoption of renewable energy technologies.

Firstly, and most importantly, public acceptance

of new and often very visible technologies plays

6 It should be noted that the capacities added for renewables are not directly comparable to those for fossil

fuels, since their capacity factors are limited by the supply of the relevant natural resources such as solar

irradiation, wind speeds, and amount of precipitation.

7 For a discussion in recent cost developments of renewable energy and a comparison with the costs of fossil

fuels see IRENA (2015).

a role in many areas. The role of public

acceptance is seen to be a barrier to adoption,

particularly in the case of wind energy (see e.g.

Wüstenhagen, Wolsink, & Bürer, 2007). The high

visibility and landscape impact of wind turbines

and solar power fields often lead to community

protests and lack of acceptance. To tackle this

problem, Zoellner, Schweizer-Ries, &

Wemheuer (2008) have shown that aspects of

particular importance influencing project

acceptance are the participation of the general

public and local authorities into the decision-

making process, the transparency of the project

planning and decision-making processes, and

economic benefits as perceived by the

community.

A major barrier to mass adoption of RES is its

initial capital cost, albeit decreasingly so (Beck &

Martinot, 2004; IRENA, 2015; REN21, 2016).

While costs have been reduced strongly for

most RES, mainly for solar and wind power, it

depends strongly on the location of the project

whether investments are recoverable. Since the

production of power depends on the number of

natural resources such as solar irradiation and

wind speeds at the project location and is

variable with time, load factors and, therefore,

competitiveness of these RES vary considerably

(IRENA, 2015, p. 28).7

Furthermore, as will be discussed in the next

chapters, considerable costs exist for

maintaining system balance and RES

integration. Measures that have addressed the

redistribution of costs and remunerations in

order to promote sustainable development are

numerous, as discussed for example by Haas et

al. (2011). Notably, the role of feed-in tariffs (FiT)

has impacted investments in renewable energy

by giving long-term certainty to investors and

above market price remunerations for their

6

generated energy.8 However, some economies

such as Germany are moving to more dynamic

and market-based principles (Lang & Lang,

2015). Another important mechanism to

increase investments into renewables instead of

fossil-fuelled power is to internalize the external

costs of CO2 emissions,9 for example by CO2

taxation or cap-and-trade schemes such as the

European Union Emission Trading Scheme (EU-

ETS).

An important economic and political barrier

is the vested interest of the incumbent power

industry in the fossil fuel market, which is

threatened by the rise of distributed renewable

energy sources (DRES) (Creutzig &

Goldschmidt, 2008; Geels, 2014). Geels (2014)

claims that ‘incumbent regime actors’ have

considerable power to “hinder the progress of

low-carbon transitions” (p. 16). According to

Geels, politics should not only focus on the

investments and further development of

innovations such as RES but should actively

participate in the destabilization of the current

regime. Political barriers for RES deployment are

often founded in resistance to the perceived

and real investment costs of an energy

transition but are also related to the close

relations between political actors and the

current powerful utility industry (Creutzig &

Goldschmidt, 2008). Effendi and Courvisanos

(2012) also argue for Australia that while political

actors claim that technology is the main barrier

for further development RES, these arguments

are in fact “camouflage in their attempts to

maintain economic and political power” (p. 251).

Although technological barriers are real, they

mostly concern the grid integration challenges,

as will be discussed in the next chapters.

8 Feed-in-Tarriffs are governmentlly regulated fees for electricity fed into the grid.

9 The concept of External costs refers to the costs “that affects people other than those involved in the economic

activity that produced it and that is not reflected in prices” (“Externality,” 2016). The internalization refers to

mechanisms that reflect these costs in the market prices of such goods. In the case of CO2, this means that the

costs related to the negative effects of CO2 emission induced climate change are taken into account for

determining the costs of energy. If the costs for producing a unit of energy becomes more expensive for a

power produced by means of e.g. CO2 taxation, this leads to economic decisions, with a preference for low-

carbon technologies such as wind or solar power.

Another set of barriers is identified within the

framework of innovation systems, according to

which “the speed, direction, and success of

innovation processes are strongly influenced by

the environment in which innovations are

developed” (Negro, Alkemade, & Hekkert, 2012,

p. 3837). Negro, Alkemade, and Hekkert (2012)

show that “systemic problems” in the renewable

energy transition can be categorized into

market structure problems, infrastructural

problems, institutional problems, interaction

problems and capability problems. The main

identified issues in the energy transition were

inconsistent policy, incompatibility of RES with

existing market structures, lack of legitimacy of

supporting institutions, strong influence by

opposing institutions, a lack of knowledge

development, knowledge networks, skills and

organizational maturity, too weak interactions

between actors, and too strong interactions and

dependence between incumbents, leaving little

space for new entrants (Negro et al., 2012).

3.2. The Dutch energy transition

The Dutch electricity market has been

liberalized in 1998. Since then, the number of

players in the sector has become larger and

responsibilities are separated between different

actors. The relevant groups and their relations

are summarized in figure 1.

Policy making is done in the first place by the

Ministry of Economic Affairs (EZ). However, “to

a large extent, the conditions are set by the

European framework” (EZ, 2016a). At the same

time, international agreements, such as the

climate agreement, can impact policy decisions.

The ministry of infrastructure and environment

(I&M) has some responsibilities but is not

involved in energy policy to the same extent as

EZ. The regulation of the electricity sector is

7

performed by the Authority Consumer and

Market (Authoriteit Consument en Markt

[ACM], n.d.). ACM regulates and supervises the

prices, services, conditions, responsibilities, and

gives permissions to grid operators, electricity

producers, market platforms, and energy

retailers. Power production and power retail are

wholly performed by market players. Although

these functions are often combined into one

company, retailers can also buy power from

electricity markets or other companies. On the

other hand, the Transmission System Operator

(TSO) TenneT and the Distribution System

Operators (DSOs) are government-owned

companies and their operations are strongly

regulated. The whole country has one TSO and

several DSO’s divide the distribution grid.

Another type of player is the so-called

balancing responsible party (BRP). Their role is

to ensure the balance in the system by ensuring

that the planning for electricity demand and

supply are equal. Each producer and retailer

either need to employ or become a BRP, which

is certified by and delivers their planning to the

TSO (TenneT, n.d.-a). Small consumers are

connected to the grid by DSO’s, but just uphold

a direct relation with the energy companies,

which not only sell the energy to the consumers

but also arrange the fees for grid connection for

the DSO’s. A recent development is that some

consumers started to produce energy either by

themselves or in the form of a local renewable

Transmission system

operator (TenneT)

Energy retailers

Ministry of

Economic affairs

Regulation, notably ACM

Power production,

import and export

Research,

NGO’s,

pressure

groups

Power consumer, prosumers and energy cooperations

Ministry of environment

and infrastructure

Power Markets

Distribution system

operators

figure 1: Overview of relevant actors in the Dutch power sector and their relations. Note that power production, energy retail

and the fulfillment of program responsibility (BRP’s) is often performed by the same companies which are commonly called

‘energy companies’. Adapted from (IEA, 2014a, pp. 74–75).

BRP

Policy making

Regulation

Power flow

Economic relations

Information,

pressure, steering

European, regional and worldwide policy

agreements

8

energy organisation, referred to in figure 1 as

prosumers and energy cooperations

respectively. Besides these actors, which are all

directly involved in the sector, figure 1 shows

that research, NGO’s and other organizations

can induce changes or influence this system,

which is particularly relevant in the light of the

current energy transition.

The Dutch power system is strongly reliant

on its gas-fired power plants, which are

currently the main supplier of electricity with

about 42% of the total electricity production

(see figure 2). The electricity produced by RE is

dominated by wind energy, especially by land-

based turbines. According to the estimates in

the National Energy Survey, by 2023 wind power

will become the most important electricity

source. The off-shore fraction of wind power will

be the most important technology by 2030, with

a share of 25% of the power production. The

role of solar energy is relatively small but will

increase to about 9% of the electricity produced

by 2030. The total amount of electricity

production is expected to increase by 38% from

380 PJ in 2016 to 525 PJ in 2030 (Schoots et al.,

2016).

As regulated in its renewable energy targets,

The Netherlands has dedicated itself to use 14%

of its gross final consumption from renewables

in 2020 and 16% in 2023 (Sociaal Economische

raad [SER], 2013). Yet, despite its accelerating

adoption of renewable energy, it is lagging at

5,8% in 2015 and is expected to keep behind on

its target, reaching only 12,5% in 2020. However,

the second goal in 2023 of 16% is expected to

be reached with a minor deficiency of 0,1%

(European Commission, 2015b; Schoots et al.,

2016). The growth of renewable energy usage in

the electricity sector has been much higher and

will expectedly rise from 15,0% in 2016 to 37,7%

in 2020 and 41,1% in 2023, as shown in figure 2.

The most important policy measure that has

enabled the government to influence the

achievement of the renewable energy targets is

the so-called SDE+ market premium scheme.

Instead of a fixed tariff for each unit of energy

delivered as with FiT schemes, the SDE+

program offers only the difference between the

market prices of power and the cost price of the

figure 2: Historical data up to and including 2015 and projection of electricity production from 2016 by energy source in the

Netherlands. Own representation of data from the National Energy Survey (Schoots et al., 2016).

0%

25%

50%

75%

0

100

200

300

400

500

2000 2005 2010 2015 2020 2025 2030

Ren

ewab

le g

ener

atio

n/

tota

l gen

erat

ion

Elec

tric

ity

pro

du

ctio

n (

PJ)

solar PV Wind offshore Wind onshore

Biomass other renewable Coal

Gas other non-renewable percentage renewable

9

technology.10 The premium is paid for by a

surcharge on the energy tax for household

consumers. Other measures in the energy

agreement are tax breaks for local energy

cooperations and the stimulation of R&D (SER,

2013). The climate agenda (Ministery of

Infrastructure and Environment [IM], 2013) and

energieagenda (EZ, 2016a) reaffirm the role of

the SDE+ scheme while stating that the EU-ETS

should gradually take over the main role as a

stimulus for sustainable development once it

becomes more effective.11

One of the most important barriers to the

growth of RE adoption in the Netherlands has

been the relative instability of policy (IEA, 2014a;

Negro et al., 2012). However, the most recent

policy agenda indicates a continuation of the

SDE+ scheme as primary instrument even after

2023 when the 2013 renewable energy targets

of the energy agreement expire (EZ 2016a).

10 As an example, in a fixed FiT scheme, a wind turbine operator would receive a regulated fixed amount per unit

of energy fed into the grid, e.g. 7 €-ct per kWh. In a market premium scheme, the same wind turbine generator

would receive only the difference between cost price, e.g. 7 €-ct per kWh, and the average market price, e.g.

4 €-ct per kwh. The operator receives a variable market price, and a fixed-feed in premium of 3 €-ct per kWh.

11 While the European Union Emission Trading Scheme (EU-ETS) should already have impacted sustainable

development, low carbon prices due to a surplus of emission allowances have limited this effect (European

Commission, 2016). Yearly allowances should decrease untill 2030, thus increasing scarcity, which leads to

higher carbon prices.

Other barriers, as mentioned by the IEA, are the

lead time until the plants are connected to the

grid, environmental protection and public

acceptance (IEA, 2014a).

3.3. Flexibility

The previous sections introduced a set of

barriers for the steady diffusion of renewable

energy technology. This section will discuss and

compare policies and regulation in The

Netherlands, in the selected high VRES

penetration countries, and research that

addresses problems of flexibility and grid

integration of VRES specifically.

Countries engaged in an energy transition

are quickly moving towards larger fractions of

variable renewables in their system. figure 3

shows some of the countries with the highest

percentages of variable renewable energy

generation, as well as the Netherlands and its

figure 3: Percentages of VRES technologies with respect to total power generation in several jurisdictions (large stacked colums). The

amount of total renewable generation as percentage of total electricity production is given as points. The smaller colums represent

the 2 yearly development of VRE generation from 2006 to 2014. The graphs are based on 2006 to 2014 data by the IEA (2016), except

for electricity generation in California and Texas. The graphs of these USA jurisdictions are based on 2008 to 2014 data by the

California Energy Commission (2016) and 2016 data of ERCOT (2017) respectively. Note that the total renewable energy electricity

generation of Norway is not shown, because it lies outside the graph at 98% renewable energy.

0%

10%

20%

30%

40%

50%

60%

Denmark Portugal Spain Ireland Texas Germany California UK Belgium Netherlands Norway

Solar Thermal Wind

Solar PVTotal Renewable

10

neighbouring (interconnected) countries.

Renewable energy production has risen in each

of these countries since 2006. The growth is

dominated by the VRE technologies of wind and

solar power. VRE generation in this period grew

on average by 3,6 %-point per year in Denmark

while only by 0,4 %-point per year in the

Netherlands. The jurisdictions taken into

consideration for the analysis of flexibility policy

are Denmark, Spain, Ireland, Texas, Germany

and California. The selection is based upon their

status in the energy transition, experience with

VRES and diversity of grid situations. Although

Portugal also belongs to one of the most

advanced countries with regards to its VRES

integration share, the similar grid and

environmental situation to Spain reduces the

added value of analysis. While Norway is one of

the countries with the largest percentages of RE

penetration (98%, see figure 3), it relies almost

exclusively on hydro-electricity and is therefore

of limited interest for flexibility policy in high

VRES countries. The other countries that are

shown in figure 3, however, are subject to a

variety of situations.

The diversity of grid situations of these

countries is shown in table 1. Relevant

properties according to IEA-RETD (2015a) are (1)

the VRE portfolio, (2) the geographical

distribution of VRE, (3) the interconnection with

other jurisdictions and networks, and (4) the

flexibility of the system (see table 1). The amount

of VRE in their portfolios vary from 13,7% to

42,5%. All of them have shown an increase in

VRE generation over the period from 2006 to

2014, on average by 1,9 %-point per year (see

table 1: grid properties of electrical Networks in the countries under consideration.

Property Netherlands Denmark Spain Ireland Texas

(ERCOT)

Germany California

(CAISO)

Variable

Renewable

energy in

portfolio*

7,7%

(low) 42,5%

(high wind)

23,6%

(high wind

and solar)

19,5%

(high wind)

15,0%

(mid

wind)

14,9%

(mid wind

and solar)

13,7%

(mid wind

and solar)

Geographica

l distribution

of VRE**

Mostly

distributed1

Mostly

distributed

Well

distribute

d

Mostly

distributed

Mostly

in one

Area

High

concentrat

ion in few

areas

Mostly

distributed

Interconnec-

tion with

other

Jurisdiction-

**

Strong2 Strong Weak Synchronously

Independent

Synchro-

nously

indepen

dent

Strong Strong

Flexibility of

the system**

High

flexibility

High

flexibility

High

flexibility

High flexibility Mid-

flexibility

Mid-

flexibility

High

flexibility

* Own calculation. For data source see note under figure 3.

** Based on a report by IEA-RETD (2015a), except The Netherlands. See justifications below. 1 Currently, power plants are distributed quite evenly, but because of development of off-shore

wind power, the concentration is moving towards the shores (TenneT, 2016). 2 Interconnection capacities with neigbouring counties are ‘substantial’ at about 33% of its peak

load (Frontier Economics, 2015): 3 Dispatch: currenty large amount of dispatchable gas fired power plants (Frontier Economics,

2015). Storage: scarcely available and is not expected to be used untill 2035 (Frontier

Economics, 2015). Demand side response: not expected to be used to a large scale untill 2030

(Frontier Economics, 2015)

11

figure 3). To cope with the changing power

supply situation, a large set of varying solutions

has been proposed, planned and adopted in

these countries.

In the Netherlands, the VRES penetration is

in the low range with 7,7% of the electricity

produced by solar photovoltaic (PV) and wind

power combined in 2014 (IEA, 2016).12 Secondly,

the geographical distribution of power

production is quite homogeneous but expected

to be more concentrated at the shores in the

future, demanding stronger connections with

the rest of the country (TenneT, 2016). Thirdly,

the country has strong grid connections with

the neighbouring countries, including plans for

strengthening further interconnection capacity

(Frontier Economics, 2015).13 Finally, according

to IEA-RETD (2015), flexibility is governed by the

dispatch, storage, and demand-side response

abilities. Whereas storage and demand-side

response are rarely developed, dispatchable

gas-fired power plants can provide more

flexibility than currently necessary (Frontier

Economics, 2015). As will be discussed in further

chapters, however, other flexibility options will

need to take over this role when moving

towards higher percentages of VRES and with

dispatchable plants decreasing in importance.

3.3.1. Flexibility challenges

As has been mentioned in the introduction of

this chapter the variability of VRES leads to a

number of issues that need to be addressed in

the short and long-term in order to maintain the

reliability of the electricity grid while minimizing

the cost of integrating high shares of VRES

(Martinot, 2016). The most relevant variations

are those in residual load, which refers to the

energy demand while subtracting the available

12 The IEA-RETD (2015a) considers the German share of VRES as “high wind penetration”, while wind energy just

covers 9% and solar energy 6% of the total electricity production (IEA, 2016). A mid VRES penetration region

according to IEA-RETD (2015) is California, where the wind share is 6% and and solar (PV and thermal) share is

8% (California Energy Commission, 2016).

13 Meant here is the physical grid interconnection capacity. However, market integration with other countries is

an ongoing process as well and equally important for the efficient usage of the interconnection capacity and

therefore for the smoothing effect of VRE generation when aggregated over larger geographical regions. For

the smoothing effect, see the market design section 3.3.2.2.

14 This latter situation will happen more often when the share of renewables rises.

variable power. Residual load, therefore, shows

the amount of power that needs to be covered

by flexible resources. What is necessary from

these resources is determined by the

characteristics of the residual load fluctuations.

In case of positive residual load, it needs to be

covered either by a flexible power supply or by

reducing the load through demand-side

resources. In case of negative residual load,

either supply resources need to be curtailed, or

demand needs to be increased.14 The

characteristics of such variations can be

described by three different dimensions (Van de

Vegte, 2015). Firstly, the timescale in which the

variations occur is of importance. Variations in

seconds require different measures than

variations that occur seasonally. Secondly, the

difference in power needed (in e.g. MW) during

a fluctuation determines the required capacity

to respond to it. Thirdly, the amount of energy

(MWh) that needs to be covered during

fluctuations determines the reserve energy that

should be ready for usage in case of expected

or unexpected fluctuations of the residual load.

These variations manifest themselves in

distinct challenges, as has been categorized by

Hers et al. (2016b). These challenges are energy

supply, balancing and network congestion.

Firstly, energy supply refers to the response

to long-term variations. At different times,

seasonally occurring variations will both create

scarcity and abundance in electricity supply.

This occurs both in the cases of wind and solar

power. Therefore, when VRES occupy larger

percentages of the available power capacity, the

system increasingly needs to deal with

shortages and surpluses. In case of shortages,

the system either needs to have enough flexible

12

capacity available or decrease demand to cover

the gap caused by low VRES production. In case

of energy abundance, VRES will need to be

curtailed, or demand needs to be increased.

Balancing refers to the response to variations

occurring on shorter timescales. While the

fluctuations might not be great in terms of

energy, power supply in a VRES-heavy system

might increase or decrease steeply from one

moment to the other and might do so

unexpectedly. To respond to such variations

sufficient power and energy needs to be

available but, at the same time, it should be able

to follow the rate of change of the residual load.

Therefore, not only should sufficient capacity

and energy be readily available, but ramp rates

(in e.g. MW/h) should be high enough as well to

cope with fast and unpredicted variations.

The final dimension of the flexibility

challenge considers its spatial aspect. While

VRES are variable over time, they also cause

changes in power flows through the grid

system. At some points, peak loads on the grid

will increase, requiring either grid strengthening

or options to take the load off the grid. A clear

case of congestion due to the increase in VRE is

the high wind power feed-in in the north-west

of Germany during hours of strong wind, while

demand is mostly found in the south. The

resource dependent, rather than load

dependent placement of resources creates

stronger segregation of load and consumption

centres and therefore, dependence on a

strengthened grid system to connect them.

While it is technologically possible to

respond to each of these challenges, both

consequences of the problems as well as its

solutions come at certain costs. A body of

research is performed on such ‘integration

costs’. Integration costs are defined by Hirth,

Ueckherdt and Edenhofer (2015) as the gap

between the market value of energy from a

certain VRE technology and the average market

price of energy while assuming a perfect

market. According to them, integration costs of

VRES technologies tend to increase once their

penetration increases. This economic

perspective is consistent with the assessments

mentioned earlier: increasing penetration

grades increase the challenge for energy

supply, balancing as well as congestion. In the

words of Hirth, et al. (2015):

We propose a decomposition of

integration costs along three inherent

properties of VRE: uncertainty causing

balancing costs, locational inflexibility

causing grid-related costs, and temporal

variability causing profile costs. (p. 935)

Thus, besides a technical and social issue, the

flexibility challenge can be understood as an

economic development. Market design and

regulation are, therefore, important aspects in

responding to it. Moreover, because policy and

regulation can introduce measures to increase

the value of VRE, it can decrease integration

costs. As an example, while the value of wind at

a certain moment might be low due to low

demand, a measure to improve the market

might be able to increase demand at that time

and therefore, increase the value of the

electricity.

A related discussion about the economic

aspects of VRE integration centres around the

so-called merit-order and compression effects

(see e.g. IEA (2014b, pp. 29–31) and Hirth (2013)).

Because of the low variable costs of renewables,

their bid prices in the market are usually much

lower than that of conventional power

technologies. Since the market dispatches the

lowest bids first, higher-merit technologies such

as gas-fired power plants are pushed further

out of the market. With the increase of VRES

penetration, market prices decrease at times of

high wind and solar feed-in. This is referred to

as the merit-order effect. The compression

effect refers to the decreasing capacity factors

of power plants that have higher variable costs

(IEA, 2014b). At the same time, VRES also erode

their own market, as returns on investments

decrease with decreasing market prices.

Although their variable costs are usually low,

their investment costs are high, because of

which high margins are needed to get a positive

return on investment. A Regulatory Assistance

Project (RAP) report, on the other hand,

indicates that:

13

contrary to a common misconception,

marginal clearing prices in a properly

functioning, fully competitive market

reflect the value of the marginal kWh of

electricity – this may or may not equal the

marginal cost to produce that kWh, and

in many scheduling periods it clearly does

not nor should it. (Keay-bright, 2013, fig.

20, emphasis my own)

The author indicates that although prices might

decrease, this is not a permanent effect of VRES

integration, as scarcity will increase them again.

A CEPS report confirms that depressed prices in

Germany were only partially caused by the

merit-order effect. The reason for the merit-

order effect, moreover, is understood not to be

caused by the market, but rather as an effect of

dedicated policy instruments to stimulate RES

(Genoese & Egenhofer, 2015). Therefore, not the

properties of VRES determine low average

prices on the market, but rather its top-down

stimulation taking place outside of the market.

As mentioned in the RAP report, the price of

electricity indicates its marginal value, rather

than its marginal costs. However, as much of the

renewable energy production is correlated

(taking place at the same time), surplus still

reduces the prices for electricity, particularly

affecting VRES. As with the ‘integration cost’

interpretation of the economic effect of VRES,

understanding of the merit-order effect can also

show how introducing flexibility into the power

system can reduce their decreasing value. E.g.

Hirth (2013) shows that the integration of

flexibility options could increase the value of

VRES since it reintroduces additional value to

energy at a certain point in time or place.

The flexibility needs and challenges of the

Netherlands have, most notably, been

considered by Frontier Economics (2015), as

commissioned by EZ, and by CE Delft (Hers et

al., 2016). Both studies, however, show that

15 Peak load refers here to load values occuring less than 1500 hours per year. While the peak load in 2023 is

between 16 and 18,5 GW, the residual peak load occurs between 13 GW and 18,5 GW. Therefore, a greater

amount of load is needed to cover the top 1500 hours of a year. The middle load refers to capacity that is

dispatched 1500 to 7000 hours per year. The baseload refers to capacity that is dispatched more than 7000

(out of 8760) hours per year.

flexibility is currently not very challenging within

the foreseeable future, considering a large

capacity of flexible power plants (as will be

discussed under supply-side flexibility in

chapter 3.3.2.4). Yet, the CE Delft report does

show an increase in flexibility needs until 2023.

The demand for peak capacity might increase

by 30% with respect to 2013 (to 5 GW). The

demand for balancing capacity increases by

40% (to 1,2 GW). Grid congestion in capacity

shortages might arise of about 0,5 GW in the

low voltage grid, 1,2 GW on the medium voltage

grids, and 1,3 GW on the high voltage grids.

(Hers et al., 2016).

Changes due to the integration of VRES can

be understood by the analysis of the difference

between duration curves for load and residual

load. One can see from the duration curves for

2023 by Hers et al. (2016, fig. 9), that peak load

increases from 2,5 to 5,5 GW. At the same time,

the middle load remains equal and the reliance

on baseload decreases from 11 to 8 GW.15 This

confirms the compression effects as discussed

earlier: capacity factors decrease due to

stronger variation. The same duration curves

show that the occurrence of certain loads is

significantly reduced due to the introduction of

VRES. It shows, for example, that the situation

with of 8 GW or more load occurs 20% less

often. This means that the capacity factor of

power plants dispatched at this load is, on

average, reduced by 20%. For power plants

dispatched around 14 GW, the compression

effect is much greater with a 75% reduction of

their capacity factors.

Still, according to Frontier Economics (2015),

the flexible production capacity will be sufficient

until at least 2035 to ensure resource adequacy

(energy supply) as well as balancing. Sufficient

interconnection capacities with neighbouring

countries, flexible gas-fired power plants, and

low internal congestion cause the Dutch market

14

to be well positioned for mass integration of

VRES (Frontier Economics, 2015).

3.3.2. Flexibility options

The set of solutions related to the integration

challenges are often labelled as ‘flexibility

options’, referring the ability of certain policies

and practices to deal with variations in power

production caused by VRES or to decrease the

fluctuations of VRES itself (Fraunhofer IWES,

2015; Hogan, Weston, & Gottstein, 2015; IEA,

2014a; Papaefthymiou & Dragoon, 2016;

SWECO et al., 2015). According to

Papaefthymiou and Dragoon (2016), these

challenges can be addressed by 9 different

directions that address the flexibility challenge.

In this paper, these directions were merged into

four categories, as shown in table 2, also based

on IEA (2011). The flexibility options address

energy supply adequacy, as well as the

balancing and grid congestion challenges.

The following paragraphs will discuss the

problems and solutions offered by The

Netherlands, other countries, research, and

stakeholders within the range of each of these

Flexibility options. The flexibility challenges as

described in the last section and the flexibility

options have been summarized in figure 4.

3.3.2.1. Demand-side flexibility

Firstly, Demand Side Management (DSM) refers

to the ability of loads to respond to the

availability of electricity generated in the power

system. This includes not only the activation of

the flexibility of existing loads but also the

creation of additional flexible loads and

electrification of non-electricity powered

sectors (Papaefthymiou, Hasche, & Nabe, 2012;

SWECO et al., 2015).

Albadi and El-Saadany (2008) classify

demand-response programmes into two broad

categories: incentive-based programs and

price-based programs. Whereas incentive-

16 Some of these practices are inherently linked with storage, since the flexibility in the timing of the usage of

these devices and processes is often determined by their ability to store the final energy for later use. Even

though in table 2 storage is included in system flexibility, the first category includes the options here that

Papaefthymiou and Dragoon (2016) describe as end-use storages, since they always take place at the demand

side (see table 3).

based programs engage electricity consumers

to offer their demand flexibly by offering

specific incentives for the bidding into balancing

markets, or for direct control over the load,

price-based programs intend to offer flexible

prices to consumers such that they are self-

motivated to shift their load to off-peak times

or shave their peak energy usage.

The conversion of power into heat (power-

to-heat) and cooling, the use of electricity for

desalination, electric vehicle integration, several

industrial processes (power-to-products) and

power-to-gas are of particular importance for

creating demand-side flexibility. The ability to

cope with variations can be determined by the

inertia of the technology, its energy storage

possibilities, and the ease of a time-shift of the

process (IEA, 2014b).16

Thermal storage in buildings and industrial

heating and cooling allow a shift in the usage of

electricity to improve the match of consumption

with the VRES electricity production. The shift in

time could both reduce peaks and valleys of

residual load, which otherwise would need to be

covered by other flexibility options

(Papaefthymiou et al., 2012). Since water can

also be stored relatively easily at relatively low

cost, the flexibility of electricity driven

applications such as water pumps and Reverse

Osmosis desalination plants enables them to

participate in the markets for ancillary grid

services (Kim, Chen, & Garcia, 2016). Shifts in

usage patterns are possible for all devices that

have some flexibility in their time of use, such

as industrial processes that can obtain a variable

production in combination with a buffer for

their produced goods. Such power-to-x type of

technologies can be used to absorb energy at

times of surplus. It is problematic, however, that

if such a technology has large investment costs,

they are not likely to be viable. They depend on

a small number of hours with very low electricity

15

prices, in which it is hard to regain their

investments. When investment costs are low,

however, power-to-x technologies might profit

from low electricity prices while delivering

flexibility to the system, both in terms of

balancing and providing absorption capacity for

surplus situations.

Large-scale electric vehicle (EV) deployment

would offer important contributions for system

purposes as well. Since their integration

requires no significant system investments and

offers large storage potentials, EV batteries

could contribute to flexibility by making use of

charging strategies and load aggregation.

Although bulk energy storage, as discussed

below, will be required and feasible only in the

long term, vehicle integration as a system

integrator for VRES might become interesting at

a much earlier stage (Agora Energiewende,

2014; California Independent System Operator

[CAISO], 2014a; IEA, 2014b; Martinot, 2016).

Another topic discussed in policy literature is

that of aggregation. Aggregation services are a

possible player in the power market and could

act in between suppliers and consumers of

electricity. These services would be able to

combine the energy consumption of a group of

customers and change their usage patterns,

such as to respond to power market prices. A

contract, for example, could be that under

certain conditions an aggregator takes over the

control over a device, reducing or increasing its

electricity consumption. It could pay the

customer an agreed-upon amount for making

the demand resource available while generating

income from reselling the energy on the

electricity markets, balancing markets or to

relieve grid congestions. Aggregation can come

in many forms: consumers could be discounted

on their grid tariffs for control by the grid

operator over a flexible device, aggregation

could optimize a consumer’s energy usage

based on the electricity prices and resell the

change in energy use to the market,

aggregation could come in the form of a

supplier engaging in contracts with its

customers to minimize the actual energy costs.

Within the EU context, there is a strong debate

about the role of this relatively new type of

figure 4: Schematic overview of the integration challenge, its causes and its solutions, based partially on studies by IEA (2011, fig.

4), Papaefthymiou and Dragoon (2016), and Hers et al. (2016).

16

player. In the ‘clean energy for all Europeans’,

also called ‘winter package’, the EU commission

proposed that every member country should

“define frameworks for independent

aggregators (…) along principles that enable

their full participation in the market” (European

Commission, 2017). While aggregation services

are already possible in many jurisdictions, they

do not have independence because companies

still need to cooperate and engage in contracts

with them. Since aggregation is not necessarily

in their best interest, CE Delft and

Microeconomix (2016), claim that a position

independent of energy companies is desirable

to facilitate the development of aggregators.

The question is, however, which model should

be incorporated to do so. A number of different

formats have been proposed by USEF to define

17 Because the possible formats for the independent aggregator is a subject in itself, it cannot completely be

discussed here. For more information, please refer to USEF (2015, 2017), and De Heer and Van der Laan (2017).

the aggregators’ balancing responsibility and

their relation to suppliers (USEF, 2017).17

Some possibilities for demand-side

management are identified and acted upon in

the Netherlands. Firstly, Dutch policy aims to

achieve flexibility for household consumers by

moving towards a quarter-hourly dynamic

pricing of power. To do so, ICT-systems are

planned to be modernized while the mass-

rollout of smart meters is expected to be at

more than 80% of all connections by 2019.

These developments are planned such as to

allow and stimulate dynamic consumer tariffs

on a large scale from 2019 (EZ, 2016c).

Concerning the aggregation discussion, EZ

currently considers its possibilities for

aggregating entities to operate more freely.

According to CE Delft and Microeconomix

(2016), currently, no regulatory arrangements

table 2: categorization of flexibility options, as adapted from Papaefthymiou and Dragoon (2016).

Categories in Dragoon and

Papaefthymiou (2015) #

Categories in this

research Description

1. Demand side management

1 Demand side flexibility

Activation of the flexibility of demand to respond

to the availability of energy resources, with or

without the help of an aggregating entity. This

includes efficiently increasing the used energy in

case demand exceeds supply and vice-versa, and

end-use storage options such as battery home

systems or electric vehicles.

2. Surplus Energy

7. Power markets 2 Market design

Adapting of the design of the power markets to

optimize incentives for flexibility and enable

participation of VRES in markets.

3. Distribution networks – smart

grids

3 Sytem flexibility

Measures that impact flexibility of the power

system in between supply and demand. This

includes transmission and distributions grids and

energy storage.

4. Flexible transmission systems –

supergrids

5. Energy storage

6. Non-synchronous generation

8. VRES control

4 Supply side flexibility

Using the potential which the supply side holds to

respond to an imbalance in demand and supply.

This includes stimulating the flexibility of individual

generators, but also their mix, their control, and

prediction of VRES availability 9. Resource diversity

17

are made to facilitate the independent

aggregation of demand-side resources. Yet, the

contractual relations necessary between the

supplier or BRP on the one hand and the

aggregator on the other are usually not

considered problematic in the Netherlands. The

availability of many parties and the related

presence of competition prevent energy

companies from blocking their entrance (Hers

et al., 2016). Finally, the barriers that exist for the

system-friendly integration of electric mobility,

thus enabling its demand-side potential, is also

being revised through a set of new laws18

(Movares, 2016).

In Denmark, since 2005, electricity usage

during high wind injection is stimulated in the

district heating system. If CHP capacity is

available in the district heating system, tax

reductions are given for electricity used by

boilers. In this tax system, district heating

companies are inclined either to shift their CHP

output from electricity to heat or use electric

boilers at high wind injection. Furthermore,

since 2013, tax for electricity usage for comfort

heating has been reduced to stimulate

investment in heat pumps and household

electricity boilers. Although through these

policies, Denmark grew considerably in its

flexible CHP capacity, electric boiler capacity is

still limited. Nevertheless, the integration of the

heating and power sector is responsible for a

large part of the Danish system flexibility

(Danish Ministry for Climate Energy and

Building, 2013; Ea, 2015). The Danish

government, similarly to the Netherlands,

formulated plans for a smart meter roll-out, and

are planning towards allowing flexible pricing in

a smart-grid strategy (Danish Ministry for

Climate Energy and Building, 2013).

The German policy for demand-side

management focusses on its market structure:

“Demand side management is a commercial

18 However, The instute ElaadNL, which gathers experience in the area of smart charging, opposed the law that

was passed recently. According to them, the law ‘VET’ hampers the development of the smart integration of

electro-mobility, since it does not allow grid operators to experiment in this area (Onoph Caron, 2017). Grid

operators are restricted in their operations because of their limited role, and regulated position within the

energy market. As will be mentioned later, the position of grid operators is subject to a wider discussion.

decision. In the electricity market 2.0,

companies take their decisions on a commercial

basis” (Bundesministerium für Wirtschaft und

Energie [BMWi], 2015b). The strategy is to allow

maximum flexibility of power prices and, thus,

let the market incentivize demand-side

management where necessary. The market-

based strategy, however, is yet only of interest

for companies that are ‘capacity profiled’. For

household consumers, the introduction of

smart meters is part of the Ministry of Economic

Affairs and Energy’s (BMWi’s) planning already

since the 2009 EU Directive that required

member states to do so. The smart meter roll-

out yet needs to take place and is restricted to

consumers with high energy demand (Lang,

Heun, & Assion, 2016).

In Spain, the mass rollout of smart meters

and variable pricing for small consumers,

however, has been implemented to a much

further extent and is planned to be finished by

2018. A ‘Voluntary price for small consumers’ is

already in place since 2014 (Comisión Nacional

de los Mercados y la Competencia [CNMC],

2015). Until now, however, economic signals for

domestic consumers have been too weak for

this group to join in demand response

(Fernández, Payán, Santos, & García, 2017).

California is also changing its electricity tariffs

to better reflect market prices and, therefore,

availability. California already has a Time-of-Use

(ToU) scheme for non-residential load, with

different tariffs for peak hours and off-peak

hours. According to the regulator California

Public Utilities Commission (CPUC), however,

these do not properly reflect the price

fluctuations in the electricity market since they

are not designed for integrating VRES. CPUC

has initiated pilots with ToU schemes of utility

companies, which are expected to lead either to

better aligned ToU with actual market prices or

dynamic rates over smaller timescales.

18

3.3.2.2. Market Design

Market design and cost allocation includes all

policy and regulatory actions considering the

energy market and economic incentives to

enable flexibility from the supply side, demand

side as well as the system. This section considers

eight subjects of market design: market access,

market completeness, market pricing, VRES

participation, market coupling and integration,

representation of grid conditions, and a

discussion of capacity mechanisms. The first

three concepts are discussed together, as these

subjects are highly interlinked.

Firstly, the concept of market access denotes

the possibilities and barriers that exist for

demand-side resources and VRES to participate

in wholesale markets. For demand side

resources it is important that they have access

to bid into the day-ahead market (DAM),

Intraday market (IDM) and reserve markets, but

it is critical that aggregators are allowed to do

so independently of energy companies:

“aggregation services should be allowed

without the explicit consent of the supplier, so

long as compensation for the impact on the

supplier’s balancing area is assured” (CE Delft &

Microeconomix, 2016, p. 47). Furthermore,

prequalification requirements by TSO’s can be

restrictive and based on the original centralised

power system. Product specifications for bids

into the market can further limit the ability of

demand-side resources and distributed VRES to

enter markets. Both minimum energy volumes

and product durations of reserve power can be

too large for many types of demand-side

resources and VRES. The same accounts for the

obligation that exists in some regions that

reserve power needs to be offered

symmetrically. This means that if an actor

decides to bid into the downward reserve

market, it must bid the same amount into the

upwards reserve market and vice-versa. Since

this is not possible for all balancing services

providers (BSP), some are unnecessarily

excluded (CE Delft & Microeconomix, 2016).

Secondly, market completeness is achieved

when there is a continuous set of markets

ranging from very early bids to real-time

markets. Oversimplified markets can cause

inefficiencies. The most important reasons for

markets to be incomplete are either the

impossibility of market players to hedge their

risks or transaction costs caused by trading

constraints (Willems & Morbee, 2008). An

important aspect of completing the market is

the alignment of trading periods and the

alignment of delivery periods. Decreasing the

gate closure time and decreasing the temporal

granularity of the traded products improves the

ability of all market players to bid into the

market efficiently, including VRES and

aggregators. Decreasing the gate closure time,

the time difference between the closure of the

market and the delivery of the product

significantly reduces the forecast errors of wind

power producers (Holttinen et al., 2016).

Reducing the gate closure time, therefore,

increases the ability to bid their produced

energy into the right market. The temporal

granularity defines the length of the product

offered by the producer. Since wind and solar

power generation can have strong variations

over short time scales, shorter duration of

energy and balancing power products lead to

improved integration into the power markets

(Brijs, De Jonghe, Hobbs, & Belmans, 2017;

Henriot & Glachant, 2013; Neuhoff et al., 2015).

Another discussion within the subject of market

completeness is whether markets should be

continuous or in the form of discrete auctions.

There are two reasons that this is relevant to the

flexibility discussion. Firstly, the addition or shift

to auctions might lead to a more liquid and,

therefore, stronger intraday markets (IDM).

Since a stronger IDM improves the ability of

VRES and demand resources to predict their

production, it increases their ability to offer their

flexibility (Neuhoff, Ritter, Salah-Abou-El-Enien,

& Vassilopoulos, 2016). The second reason

relates more to the locational challenge

because auctions allow flow-based allocation of

grid capacity. While such a system is only in

place for cross-border day-ahead markets

(DAM), auctions could enable this for the IDM

as well (Neuhoff et al., 2016). The discussion of

this latter implication of IDM auctions will be

continued when discussing market coupling, as

19

it currently would affect cross-border capacity

allocation only.

Market pricing refers to the way prices are

determined. For wholesale markets such as the

IDM and DAM, prices can be determined on a

continuous or auction basis. While in

continuous markets prices are determined by

the individual bids, auctions are determined

based on all bids bound together, known as a

bid stack. Likewise, prices for balancing energy

in the balancing markets might either be based

on pay-as-bid principles or pay-as-cleared

principles. According to CE Delft and

Microeconomics (2016), pay-as-bid induces

inefficiencies, and therefore increases system

balancing costs, while a pay-as-cleared model

leads to an optimal marginal pricing based

market.

Within these three subjects of short-term

market design, the Dutch market is quite well

adapted to the changing situation due to the

integration of VRES. Firstly, low minimum, high

maximum and negative prices on the spot

markets for electricity allow strong incentives to

deal with shortages and overgeneration.19

19 Still, CE Delft and Microeconomix (2016) claim that even this price cap is unnecessary and undesirable. Only

configurations where no price caps exist at all, which is the case for the Dutch primary reserve market only, are

deemed well adapted for flexibilization of the energy system.

Secondly, the Dutch system of balancing

responsibility applies both to normal as well as

to VRES suppliers. The pricing scheme for

imbalance payment, which is paid to the TSO in

the case of deviation from the program,

incentivizes producers to either sell the power,

curtail where necessary and improve their ability

to predict their power production. Thirdly, the

short gate closure time of five minutes on the

IDM enables parties to have reasonably precise

forecasts of VRES produced during the delivery

period (figure 5). Fourthly, even after the gate

closure, all parties can participate in balancing

through the system of passive contributions. If a

balancing responsible party deviates from its

scheduled programme but this contributes to

alleviating the system imbalance, it will be

rewarded the balancing price instead of paying

for its own imbalance.

Yet, CE Delft and Microeconomix (2016)

show that improvements are possible in a

number of market design aspects to create or

exploit flexibility. Firstly, there are no regulatory

arrangements for independent aggregation

services, as for France and Switzerland in all

their markets. Secondly, unit-based

figure 5: Schematic overview of the different power markets, their bidding periods, gate closure times and contract durations. The

colour coding represents how well different aspects are adapted to the integration of variable renewables in the system. Based on

data compiled by CE Delft and Microeconomix (2016). It should be noted that the IDM is moving to 15-minute contracts.

20

prequalification for the primary reserve market

excludes small-scale renewable energy and

demand-side from participation by pooling

them (Smart Energy Demand Coalition [SEDC],

2014). Thirdly, as shown in figure 5, reserve

capacities in the balancing market (BM) are

contracted for long periods and far in advance.

The primary reserve capacity (R1) is contracted

weekly. The secondary (R2) and tertiary reserve

capacity (R3) markets are both contracted 50%

quarter-yearly, and 50% yearly (CE Delft &

Microeconomix, 2016). Furthermore, Van der

Welle (2016) shows that the dissimilarity of the

gate closure times of the energy markets (DAM

& IDM) on one hand and the reserve capacity

(R1-3) markets on the other prevent market

actors to make well-informed trade-offs

between bidding into the one or the other.

Fourthly, the time blocks for energy bids, both

in the DAM and IDM, are too long (60 minutes)

for full market integration of VRES and demand-

side resources. As a solution, an ECN report

suggests moving to a 15-minute time resolution,

corresponding to the balancing energy

settlement period (Van der Welle, 2016).

According to the EPEX market platform,

however, this step will already be made soon for

20 This point is confirmed by Van der Welle (2016).

the IDM (EPEX Spot, 2017). Fifthly, primary

reserve capacity currently needs to be offered

symmetrically, implying that a bid must offer

equal upward and downward regulation at the

same time, which is often not possible for

demand-side resources.20

Another important market design aspect for

flexibility is whether VRES are required to

participate in the market. A notable cause for a

priority position outside the market is found in

VRES stimulation policy. Although fixed feed-in

tariffs provide strong incentives to investors,

which is necessary for the growth of the sector,

it can hamper flexibility. A continuous feed-in of

electricity, no matter what the market situation

is, reduces or nullifies the ability of system

friendly integration of VRES. ACER and CEER

(2017), both cooperations of EU energy market

regulators, posed that priority dispatch should

be removed, (also for existing RES), net-

metering schemes should be avoided as well as

any other non-market approach to redispatch

and RES curtailment.

In the Netherlands, the market participation

of renewables has already been partially

provided by the design of the SDE+ incentive

figure 6: Results of a Fraunhofer power generation simulation at different levels of spatial aggregation. The pixel level represents

an area of 2,8 by 2,8 km. PLEF stands for the Pentalateral Energy Forum and consists of Austria, Belgium, France, Germany,

Luxembourg, the Netherlands and Switzerland. Figure courtesy of Fraunhofer IWES (Fraunhofer IWES, 2015).

21

scheme. The SDE+ is a market premium

scheme, which exposes electricity producers to

market conditions and thus to variable prices.

Such an incentive scheme decreases flexibility

needs when compared to fixed feed-in tariffs

(Couture, Cory, Kreycik, & Williams, 2010). The

income flow from the market premium is

determined yearly, based on the average

market price of electricity. The income flow from

the market itself is dependent on real-time

market conditions. This means that the total

revenue for VRE producers varies with the

market. These producers, therefore, have an

incentive to adapt their production to demand

and vice versa, thus promoting self-balancing

(Huntington, Rodilla, Herrero, & Batlle, 2017).

Moreover, since 2016 the market premium is no

longer granted during prolonged negative

market prices, to prevent overproduction

during overgeneration (Netherlands Enterprise

Agency [RVO], 2017). For small-scale household

production, a net-metering or offsetting

scheme is still available in the Netherlands. To

promote investment, mainly in rooftop solar

power systems, electricity produced can be

subtracted from electricity consumed, thus, in

fact, granting household consumers a

remuneration of their produced electricity equal

to the retail prices. These prices are much higher

than those on the wholesale market since they

include energy taxes and levies. While this is

considered a clear stimulation policy, it does not

consider the actual value of electricity and is

therefore considered to be disruptive to the

market and ‘undermine flexibility’ (ACER &

CEER, 2017).

Although fixed feed-in tariffs have been the

most popular incentive scheme, many countries

have been moving to more market-based

schemes in the past few years. Whereas

Germany’s dominant incentive policy was based

on fixed feed-in tariffs, it was replaced by a

market-premium scheme in 2014 and gave VRE

producers the same balancing obligations as

other producers (BMWi, 2015a). Like the

Netherlands, the premium has been retracted

for negative market prices since 2016. Denmark

utilizes a market premium scheme as well and

applies the same conditions during negative

spot market prices (Ea, 2015).

The next aspect of market design considers

the market coupling with other countries and

jurisdictions. When the generation by VRES,

especially that of wind power, and power

demand is combined in a larger region, it seizes

to depend on local resource conditions, causing

much lower peaks and valleys in the system

(Fraunhofer IWES, 2015). The expansion of the

balancing area, therefore, strongly reduces the

need for the system to cope with fluctuations

caused by VRES integration. The smoothing

effect that would take place in case of perfect

market and grid connections in 2030 becomes

clear from figure 6. The peaks have reduced

significantly and power production becomes

clearly more continuous when perfect

transmission is assumed all over Europe. While

physical interconnection capacity is necessary

for further aggregation over a wider region (as

will be discussed in the next section 3.3.2.3), the

connections might remain unused if markets are

not connected appropriately.

The coupling of DAM in the North-West

European (NWE) region already improves

market liquidity, decreases overall prices, and

increases flexibility. Prices on the DAM are

coupled through ‘flow-based market coupling’.

This method considers the available

interconnection capacity and allocates expected

flows based on the DAM bid stack. The system

increases the price convergence and smoothing

effect through aggregation of power over a

larger region (IEA, 2014a). The Cross-Border

Intraday (XBID) project, which links the prices in

different bidding zones for the IDM, however, is

still being developed. Although this coupling

system of the IDM over the NWE region has

been postponed several times due to technical

and legal challenges, it is expected to go live in

the first quarter of 2018 (Cross-Border Intraday

Market Project, 2017). The XBID project, unlike

the DAM market coupling, is based on a

continuous market. Because the implicit

allocation of interconnection capacity is not

possible, it cannot adopt the same flow-based

market coupling method. This might be

22

problematic since EU guidelines for Capacity

Allocation and Congestion Management

(CACM) prescribe a market coupling

methodology that based on a continuous

market while incorporating interconnection

capacity implicitly in the prices (European

Commission, 2015a). Yet, since this combination

is impossible, the project has dropped the goal

of implicit allocation. Neuhoff et al. (2016) show

that discrete auctions, besides some other

advantages, would enable flow-based market

coupling and, therefore, more efficient

allocation of transmission capacity.

Yet, whereas market coupling strives for the

representation of interconnector capacities

between countries, the limitations within the EU

member countries’ national grids are not

reflected in their electricity prices and are

completely socialized over the country. The

price for electricity is the same wherever it is

sold or bought within the national grids.

Locational marginal pricing (nodal pricing) is an

alternative pricing mechanism which implicitly

considers network congestion similar to the

method currently used for interconnection

capacity. In a nodal pricing system, price

differences arise between different locations if

the connection between these two locations is

congested. Prices close to the electricity

generation centres will be lower than average,

while prices further from them increase if the

grid in between is congested. Nodal pricing

could have considerable benefits for system

flexibility and costs of VRES integration, as it

leads to system-efficient decisions. This method

of cost allocation could be considered to be a

method of perfect adherence to the cost-

causing principle.

Such a methodology is, to the author’s

knowledge, not under consideration for the

Netherlands, nor within the European context

for its internal market. In several jurisdictions in

the US, however, nodal pricing has occupied an

important position. The Texan ERCOT, California

21 So called Financial Transmission Rights (FTR) can be auctioned to market participants to insure them against

financial burden in case of congestion in the grid. They give the right to the income equal to the price difference

between the source location and destination location (see e.g. Lyons, Fraser and Parmesano (2000)).

ISO (CAISO), MISO, New England ISO, New York

ISO, SPP and PJM grids have transitioned from

a zonal to a nodal market (CAISO, 2017; Daneshi

& Srivastava, 2011; Neuhoff et al., 2013). While

nodal pricing might be the best option to

organize the market according to i.a. Kunz,

Neuhoff and Rosellón (2016), and Hogan,

Weston and Gottstein (2015), the market would

require a more centralised structure, faces some

liquidity risks and is considered by some market

players as a risk, because of a redistribution of

costs (Van der Welle, 2012). Kunz, Neuhoff and

Rosellón (2016), however, show that such risks

can be hedged through financial transmission

rights (FTR), a system that would financially

compensate the ‘victims’ during a transition

towards nodal pricing.21 Another option for a

market representation of grid conditions would

be to approach nodal pricing by defining

smaller bidding zones, which currently coincide

with the national borders in most EU countries.

Thus, differences in prices would arise,

representing congestion taking place in

between the zones. Such a system would

replicate the flow-based market coupling as

done for international (interzonal)

interconnectors. Therefore, it would also need

to deal with the same issues as the XBID project

to incorporate implicit interzonal capacity

allocation for a continuous market.

A final important discussion for market

design is that of capacity mechanisms. The

market models discussed until now remunerate

energy while capacity is remunerated only to

the extent of balancing products. Proponents of

‘energy-only’ markets claim that once price caps

are removed and markets released, scarcity

pricing will continue to give the right incentives

for investments in capacity. On the other hand,

since increasing shares of VRES lead to the

compression of capacity factors of conventional

power plants, the profitability of the latter is

under pressure. According to some, while the

energy only market might be efficient in theory,

it cannot guarantee the security of supply,

23

because decreasing profitability in combination

with inefficiencies makes the market too

uncertain to invest in capacity. Interference in

the market through e.g. price caps further limit

the scarcity effect of pricing in an energy-only

market (De Vries, 2007; Hogan et al., 2015;

Petitet, Finon, & Janssen, 2017). Proponents of

capacity mechanisms claim, that these energy-

only market shortcomings justify additional

market products that remunerate capacity to

give a clear and steady investment signal

through the remuneration of capacity instead of

energy. Both sides are subject to certain risks.

The risk in an energy-only market is mostly that

existing inefficiencies lead to distorted price

signals with inadequate price signals causing

investment risks and, therefore, resource

inadequacy (De Vries, 2007; Petitet et al., 2017).

Capacity mechanisms run the risk of distorting

scarcity pricing, overinvestment, and, therefore,

a “needless escalation of the costs of the

transition” (Hogan et al., 2015, p. 11). Capacity

mechanisms come in many forms as described

by De Vries (2007) and a European Parliament

briefing (2017). Notable examples are capacity

payments, capacity auctions, strategic reserves,

and capacity requirements or obligations.

Capacity payments simply remunerate any

investment in capacity through regulated tariffs

or by auctioning a certain volume of capacity.

With strategic reserves, capacity is purchased or

leased to engaged it only by the system

operator in case of shortage. Capacity

requirements or obligations regulate capacity

investment instead of influencing the market

and might, therefore, not be considered market

design instruments, but rather to belong to

supply-side flexibility measures.

As became clear earlier, the Dutch market

system is an energy-only market. Yet, a

mechanism has been introduced which can be

considered both a strategic reserve as well as a

tertiary reserve market. This so-called

‘noodvermogen’ or emergency power is

contracted yearly by TenneT to cover the

difference in demand and supply if offers in the

primary and secondary reserve markets are

insufficient (TenneT, n.d.-b). In the discussion

whether a market-wide capacity payment needs

to be installed as well, there is a tendency not

support it. The energy-only market is

considered to work efficiently and its scarcity

prices to create the right incentives.

Furthermore, as will be shown under the

heading of supply-side flexibility 3.3.2.4, The

Dutch power system is currently characterized

by over-capacity rather than a shortage.

According to several studies commissioned

by the German BMWi, a capacity market would

not be needed to create sufficient flexible

capacity, as supply-side flexible resources are

deemed adequate for the foreseeable future

(Frontier Economics & Consentec, 2014; Frontier

Economics & Formeat Services, 2014). Because

of that, BMWi decided it would not adopt a

capacity market, but it does include a capacity

reserve outside of the electricity market to

ensure power stability (BMWi, 2015b).

Other EU countries have adopted capacity

mechanisms as well, including strategic reserves

in Denmark, capacity requirements in France,

capacity payments in Spain and Portugal, and

capacity auctions in Great-Britain (ACER & CEER,

2015). Besides the consequences this might

have for the national energy markets, capacity

mechanisms also affect markets in

neighbouring countries. If cross-border

capacities are not considered, capacity

mechanisms in other countries might lead to

over-procurement and, therefore, higher costs

than necessary for the energy transition (ACER

& CEER, 2015).

For an island system that is synchronously

independent such as the Irish grid, supply-side

flexibility is especially important. A generation

capacity statement by EirGrid determines that

generation deficits will occur by 2020 in

Northern Ireland and over the whole Island

possibly by 2023. These capacity adequacy

problems are related to the introduction of wind

power, and its related reduction of the

wholesale market price of electricity. Fossil fuel

plants, having higher marginal costs, therefore,

are less able to recover their investments. If

these power plants are not remunerated for the

availability of their capacity, they will leave the

market, leaving the system with potential

24

deficits. Because of that, the regulators decided

to include a capacity payment mechanism into

the so-called Single Integrated Electricity

Market22 (EirGrid Group, 2016).

Yet one more option to stimulate flexibility in

markets is to offer additional products to

remunerate ramping ability. Whereas the Dutch

power market does not make use of such

products, California initiated the so-called

flexible ramping product to monetize the

capability of producers and demand side

resources to make capacity available at faster

rates (Xu & Tretheway, 2012). California also

makes use of a certain form of capacity

obligations. This, however, will be discussed

under supply-side flexibility (3.3.2.4), as this is

not primarily a market instrument.

3.3.2.3. System flexibility

This section includes policy and regulatory

measures that address the flexibility of the

system in between supply and demand apart

from the wholesale and balancing markets to

cope with the energy supply, balancing and

congestion challenges. This includes smart

grids, distribution grid strengthening and

automation, transmission grid expansion and

strengthening and energy storage.

The concept of a Smart grid can be defined

as:

an electricity network that can efficiently

integrate the behaviour and actions of all

users connected to it - generators,

consumers and generator/consumers - in

order to ensure an economically efficient,

sustainable power system with low losses

and a high quality and security of supply

and safety (European Commission, 2011).

22 Irelands Single Integrated Electricity market (I-SEM) refers to the combination of the Northern-Ireland and

Ireland power markets.

23 Virtual power plants are a concept to describe the control and market participations of the aggregation of

distributed energy sources and demand resources.

24 Allthough Thomsen et al. (2015) claim that participation on markets for households is possible, the potential is

relatively small. However, they expect that the possibility of the industry participating in markets with DSM

resources by means of an aggregating entity is more likely and manageable.

The concept of smart grids is, furthermore,

always connected with information and

communication technology (ICT) (Erlinghagen

& Markard, 2012). Smart grid development

activates the knowledge of the ICT sector to

control generators and consumers. It enables

balancing and control in the distribution system

by DSM, distributed energy storage, and

Distributed Renewable Energy Source (DRES)

integration. While otherwise consumer loads

and DRES are otherwise hardly controllable,

considering their great numbers and small sizes,

smart grids can employ a set of technologies to

aggregate them. The aggregation of small loads

and DRES enables effective control of the

system. Not only do smart grids activate the

technological benefits of system support, but

the aggregation of DRES also allows them to

participate in the energy market in the form of

Virtual Power Plants (VPP).23 This leads both to

technical and economic integration (El Bakari,

2014; Martinot, 2016). The same is valid for the

integration of loads in a controllable DSM pool,

which would enable them to join in ancillary and

spot markets (Thomsen, Roulland, Kellermann,

Hartmann, & Schlegl, 2015).24 As has been

discussed, another asset of smart-grids for DSM

is their ability to support dynamic pricing

models. Because metering can be carried out in

real-time, energy prices are allowed to change

on short time scales as well.

Strengthening the distribution grid, by

increasing cable capacities, will also be

necessary. Even though the smartening of the

grid lessens the necessity of increasing grid

capacity, it seems likely that the development of

higher percentages of DRES and increasing

loads such as electric vehicles in the distribution

system will require it to some extent

(Overlegtafel Energievoorziening, 2015).

25

The Dutch development of smart-grids is in

an exploratory stage. Smart grids are stimulated

through the Innovation Programme Intelligent

Networks (IPIN) in the form of 12 pilot projects

(RVO, n.d.). Locally, a strong penetration of

renewable energy produced is already causing

congestion in low voltage grids at some points.

Although “expectedly the existing grid can

accommodate much [solar photovoltaic

energy,] this does not alter the fact that

problems can arise precisely in the capillaries of

the network if the supply of [solar power] is

higher than for which [the network] is

constructed” (Overlegtafel Energievoorziening,

2015, p. 24, translation). Since virtually no

incentives exist to investigate alternatives, grid

operators have limited options except to

strengthen the grid, while this does not

necessarily entail the highest societal benefits

(Overlegtafel Energievoorziening, 2015). As has

been mentioned under demand-side

management, however, there is a strong focus

on the development of smart meters in the

short run, which is a major first step in the

direction of more technologically advanced

grids.

The development of smart grids in other

countries and states under analysis is often in

the same stage of testing and pilot mostly. Yet,

the roll-out of smart meters is seen in many

jurisdictions (Colak, Fulli, Sagiroglu, Yesilbudak,

& Covrig, 2015). In the EU, Denmark shows the

highest investment in smart grid development

per capita. Germany is considered as the first

country to move from research and

development to demonstration and

deployment projects (Colak et al., 2015).

However, because the work in the smart-grid

development sector is project based and

research in distribution grids is a local matter, it

is hard to identify national policy.

Yet, the Danish Ministry of Energy and

Buildings (2013) has published a smart grid

strategy. Although the document includes a

planning for the introduction of smart meters

25 IOU’s are the private energy companies that operate within the Californian jurisdiction.

and variable tariffs, it discusses flexibility options

that are not directly related to smart-grids as

well, such as heating sector integration. Except

smart metering, smart grid development is just

a small part of the smart grid strategy.

The Californian independent system

operator CAISO published a roadmap for smart

grids on a more operational and technical level

than the Danish strategic roadmap (CAISO,

2010). It describes in detail the actions that will

be undertaken until 2020 for advanced

forecasting, to measure and control grid

conditions using advanced grid applications,

building automation systems and integrating

home area networks, and providing options for

demand response, storage and distributed

energy resources. Moreover, it includes an

architecture of changes to the ISO rising from

smart grid development. An annual smart grid

report by the regulator CPUC is a continuous

check what the Investor Owned Utilities (IOU)

should do and have done for smart grid

developments.25 According to the report, IOU’s

are required to invest and have already invested

in deploying smart meters (CPUC, 2015).

While policy and regulation for the

distribution system mainly address congestion

issues, transmission system expansion and

strengthening address the balancing and

energy supply challenges as well. As has been

discussed in terms of market coupling,

aggregation of demand and supply over a wider

region causes a reduction in flexibility needs

due to a smoothing effect. The amount of

smoothing depends strongly on the ability of

transmission grid to transfer the power from

generation centres to load centres and

therefore on the grid transmission capacity and

other limiting factors such as the market. The

development of modern HVDC technologies

contributes to the ease of long-distance and

low-loss power transmission (Weigt, Jeske,

Leuthold, & von Hirschhausen, 2010). The

automation of control aspects of transmission

system improvement can further improve

26

flexibility by utilizing more of their potential with

real-time control of the capacity based on its

conditions.26

In the Netherlands, the internal transmission

grid congestion is low, and interconnection with

neighbouring countries is already substantial

(Frontier Economics, 2015) and is planned to be

increased (TenneT, 2016). Entso-e’s Ten-Year

Network Development Plan (TYNDP) attempts

on a European scale to reduce congestions

between countries considering long-term

development plans for VRES and changes in

demand. Moreover, the framework of The

North Sea Countries’ Offshore Grid Initiative is

to create a stronger cooperation and planning

for offshore power lines needed both for the

connection of wind parks as well as to harvest

the smoothing potential by stronger

interconnection.27

Because in Germany the supply centres of

renewable energy and demand centres are far

apart, the country experiences pressure on the

transmission grids, which is expected to

increase. Whereas supply centres of wind power

are in the north-west, demand centres are in the

south. Therefore, it plans the expansion of

transmission capacity, most importantly from

north to south by use of high voltage direct

current (HVDC) transmission lines (see e.g.

Agora Energiewende, 2015, fig. 22).

In Denmark, the flexibility of the electricity

system relies on strong integration with

neighbouring grids of Europe including the

well-developed Nord Pool market as well as the

Central West European (CWE) market. These

interconnections enable them not only to profit

from the smoothing effect but also to make use

of the large hydro storage capacities in the

Nordic countries for balancing purposes (Ea,

2015; Martinot, 2016).

26 For example, Entso-E (2015) proposes a dynamic transmission line rating depending on atmospheric

conditions. Using ICT, tranmission system operators can control the amount of power flow over a tranmission

line, depending on its conditions, enabling at times higher capacities than when rated based on the most

hottest conditions.

27 The North Sea Countries Offshore Grid Initiative consist of France, Luxembourgh, Germany, Switzerland, The

United Kingdom, Ireland, Norway, Sweden, Belgium and The Netherlands.

As opposed to several European countries,

the regulator California Public Utilities

Commission (CPUC) identifies that: ”California

may have many low‐cost and “no regrets”

options to pursue before considering

transmission strengthening" (CPUC, 2015, p. 42).

According to the CPUC, the system would

benefit much less from a strengthened

transmission grid as compared to European

grids. In Europe, stronger regional imbalances

between supply centres and demand centres

cause congestion whereas, in the Californian

case, grid strengthening is a relatively expensive

solution to reduce fluctuations in residual load,

because of its limited effect (CPUC, 2015).

Energy storage is another system asset that

could generate flexibility by serving as a buffer

between supply and demand. It is expected that

it will become important only in the longer term

(Agora Energiewende, 2014; Papaefthymiou &

Dragoon, 2016). The role of storage as a

flexibility option is self-evident: it can be used to

absorb energy during the strong availability of

VRES and re-inject the energy into the system

or use it in times of shortage. As has been

discussed under DSM, notable storage media in

the end-use sector are water storage, thermal

storage, and electrical storage. This section,

however, only discusses Electrical Energy

Storage (EES). As shown in table 3, EES only

covers technologies that convert electricity into

other energy forms with the intention to be

converted back into electricity. Within this

category, Papaefthymiou and Dragoon (2016)

include Pumped-Hydro Energy Storage (PHES),

Compressed-Air Energy Storage (CAES) and

battery storage. An addition to these are other

chemical storage technologies such as power-

to-gas and mechanical storage such as

flywheels. PHES makes use of gravitational

energy, storing water at heights by pumping to

27

retrieve it with turbines. The technology is

regarded as the most feasible bulk storage

options to increase system flexibility, both for

large grids and island systems. However, the

potential is limited considering the dependency

on water and specific landscape conditions. The

round-trip (or cycle) efficiency is relatively high

at about 70 to 85% (Kloess & Zach, 2014;

Rehman, Al-Hadhrami, & Alam, 2015). CAES is

another relatively mature technology, in which

air is compressed into containers, which is used

later as a source for a gas turbine to generate

electricity. Several alternatives exist, with

diabetic CAES as the lower-cost but less efficient

(40-50% cycle efficiency) and the adiabatic

CAES as the more expensive and more efficient

(60-80% cycle efficiency) technology. In

comparison, CAES faces several drawbacks:

relatively low efficiencies, low energy density

and, in the case of Diabetic CAES, the need for

additional fossil fuels (Gallo et al., 2016).

Chemical storage has been opted in the form of

gas production by electricity (power-to-gas).

The gas produced can be either hydrogen (H2)

or methane (CH4). Even though all round-trip

efficiencies for all power-to-gas variations are

relatively low, storage of the gas is much

cheaper and are well-adapted to the current

energy system (Lehner, Tichler, Steinmüller, &

Koppe, 2014). The ability to store CH4 for longer

terms (weekly, monthly, and even seasonally) by

making use of the large capacities in the existing

gas grid makes the technology relevant as a

flexibility option. Due to the high costs of

electricity generated from synthetic gas, its

viability depends strongly on the development

of power market prices (Kloess & Zach, 2014).

Battery storage is the most well-known example

of electricity storage, but it remains relatively

unlikely that it will play a significant role for bulk

energy storage, as its life cycle costs are much

higher than those for PHES and CAES and it is

not available for long-term storage (Zakeri &

Syri, 2015). It should be noted that there is a

considerable difference between technologies

meant to respond within the balancing time-

scale and those that reduce long-term

imbalances (energy supply). Long-term energy

storage is more likely to take place using H2 and

CH4 storage, while short-term energy storage

will probably be dominated by PHES and CAES.

As mentioned, the integration of energy storage

and system inertia is expected to start playing

an important role only in the longer term at

higher percentages of VRES.

Specifically for the Netherlands, Frontier

economics (2015) mentions in its report that

storage will not be necessary at least until 2035.

Yet, considering the role that storage might play

eventually, postponing clear regulation and

stimulation would be a missed opportunity.

According to DNV-GL’s roadmap energy

storage 2030, however, lacking policy focus and

coordination within the area of energy storage

is one of the barriers to its further development

table 3: Categorization of storage types based on Papaefthymiou and Dragoon (2016)

Storage type Description Examples

Primary storage Storage of primary energy

inputs, before conversion to

electricity.

Gas and oil fields, hydro reservoirs,

molten salt.

Electrical Energy Storage Conversion of electricity into

another energy form for

conversion back into

electricity at a later time.

Pumped hydro, compressed air, batteries,

power to fuel, flywheels.

End-use energy storage Storage after final

conversion from electricity

into another energy form .

Hot and cold storage (e.g. building

heating or inertia), water storage,

product (material) storage.

28

(Van de Vegte, 2015). As one of the only policy

actions mentioned in the energy agenda, EZ

considers taking away a taxation barrier that

unjustly taxes electricity doubly when stored by

a third party (EZ, 2016a).

The German system has several pumped-

hydro reservoirs at its disposal that are

participating on the balancing markets.

According to the German BMWi, however,

“Additional novel long-term storage

installations which can offset seasonal

fluctuations are only required when there are

very high shares of renewable energy” (2015b,

p. 12). Whereas the short-term balance can be

maintained by the participation of storage

systems in these markets, seasonal fluctuations

will not be addressed by pumped hydro

technology.

As has been discussed, the flexibility strategy

of Denmark has focussed on sector integration

between the power and heat sectors. As far as

storage is concerned, “Denmark has no plans

for electricity storage, relying instead on heat

storage” (Martinot, 2016, p. 12). Furthermore,

abundant storage capacity and flexible

renewable supply are available over the border

in the Nordic grid, the technical and market

access to which is seen as one of the most

important flexibility sources of Denmark (Ea,

2015).

In California, the CPUC decided to initiate

targets for the procurement of storage facilities

by IOU’s. A federal order intends to push utilities

to invest in a total of 1325 MW of storage

capacity by 2020 (Kintner-Meyer, 2014). A

roadmap for energy storage discusses further

actions that need to be undertaken by

regulators to create business cases for storage,

reduce the cost of its grid integration and

decrease uncertainty in the development of

storage facilities (CAISO, CPUC, California

Energy Commission, 2014).

3.3.2.4. Supply-side flexibility

On the supply side, flexibility is provided by

conventional as well as renewable capacity,

including VRES. Different technologies have

different capabilities for flexibility. While nuclear

power is not easily switched off and older coal

power plants can only shut down or start up

very slowly, modern gas-fired power plants

respond very quickly. Important metrics are

capacity, ramp-rate, and controllability of the

supply resources. The ramp-rate is mainly

important to address the balancing challenge,

the energy supply challenge is rather about

having enough readily available capacity. While

wind power can decrease its power production

very quickly, it can only do so if it already

produces, which is dependent on the wind

conditions. Therefore, while wind power is

compatible with the intraday market, it cannot

sell its capacity for balancing purposes over

long time frames.

Flexibility by design of variable renewables

lies in the hand of VRES producing companies.

However, their flexibility can be stimulated by

requiring or incentivising flexible generation

and market participation, as discussed in market

design.

Another important aspect of supply-side

flexibility is the aggregation of distributed VRES.

Since aggregation supports the ability for

supply to match demand, it might help

exploiting their flexibility. Whereas large

producers are already exposed to market

conditions in the Netherlands, smaller-scale

producers have an incentive to feed-in

whenever resources are available. Because

aggregators can sell the distributed VRES under

their portfolio on the balancing markets, they

will adapt the use of their generators to market

conditions. Notably, these actors will curtail

power production under negative prices on the

spot market.

As shown in figure 7, a large fleet of gas-fired

power plants is available in the Netherlands.

Since these can provide flexibility in all markets,

there is no direct need for further flexibilization

by other means. The figure also shows a strong

overcapacity within the conventional share of

power plants. In 2017, the amount of

conventional capacity is much higher than the

peak load. As shown in figure 2, the generation

by gas-fired power plants in 2030 will be much

lower than in the current mix, both in absolute

29

terms and relative to total generated electricity.

The available capacity for gas-fired power

plants have decreased in the past few years and

continues to decrease at least until 2025, but

somewhat stabilises in between 2020-2025 (see

figure 7). According to Frontier Economics

(2015), however, flexible capacity will remain

sufficient as a flexible resource until at least

2035.28 Still, since chances are that the CO2

emissions within the energy sector have to

decrease to 0 by 2050 (EZ, 2016a),29 little room

is left for flexibility from gas-fired power plants

on the long term, if these are not combined with

CO2 capture and storage (CCS). Moreover, an

energy-only market with low energy prices due

to the feed-in of wind and solar power

combined with high CO2 prices leave even less

space for gas power. On the other hand, scarcity

pricing might increase wholesale market pricing

during low wind and solar power feed-in and

thus re-introduce an incentive for its availability.

If not, then an additional capacity mechanism

28 Furthermore, the recently published government agreement has indicated a coal phase out before 2030,

although this most certainly has implications for the numbers presented here, an analysis could not be included

because of time limitations.

29 According to the energy agenda of the Ministry of Economic Affairs, this depends on a potential raise of

European climate ambitions from 80% in the direction of 95% savings as compared to 1990 levels (EZ, 2016a,

p. 23). In this case, since emission savings in some other sectors are limited, the energy sector should move

towards climate neutrality.

might need to be reconsidered (see market

design, section 3.3.2.2).

Dispatchable RE technologies, such as

biomass, can be an important renewable

alternative to obtain flexible capacity. The

Netherlands currently obtains a large amount of

its renewable flexibility from this source. In 2016,

28% of the renewable electricity is produced

from biomass (see figure 2). Although the

absolute amount of biomass will be rising, its

contribution to renewable electricity is expected

to decrease to only 6% by 2030, when wind

power has taken over the most important role

in power production. The share of total flexibility

derived from these plants, therefore, decreases

and needs to be replaced by other resources.

As for aggregation, the Dutch government

has pledged to consider and take away barriers

for aggregators, as has been discussed under

demand-side management in 3.3.2.1. The

exploitation of the flexibility of larger scale VRES

is determined by the market because of the

figure 7: Installed capacity per generation type in the Netherlands. The graph is based on 2015-2017 historical data from Entso-

e (n.d.) and the 2020 and 2025 projections from Entso-e’s (2016) mid-term adequacy forecast.

0

5

10

15

20

25

30

35

40

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Gen

erat

ion

Cap

acit

y (G

W)

Nuclear Other non renewable Hard coal

Gas All hydro Wind

Solar Other renewable peak demand

30

market exposure trough the feed-in premium

scheme (as has been discussed in 3.3.2.1).

On the supply side, Germany copes with its

flexibility needs using flexible generation of coal

and, to some extent, gas and pumped hydro

facilities (Fraunhofer IWES, 2015, Chapter 5.1;

Martinot, 2015). However, nuclear power plants

are phased out, variable renewable energy

generation is increasing and the growth

potential of pumped hydro is limited. To ensure

resource adequacy, a strategic reserve is

installed as mentioned under market design

(section 3.2.2.2).

In California, supply-side flexibility has been

stimulated by the Californian ISO through a set

of policies. Since the state electricity system is

coping with especially increasing fast and large

ramps, CAISO has introduced the flexible

ramping product, negative pricing on the real-

time market,30 and flexible resource adequacy

criteria and must offer obligations. The ramping

product and negative market prices, as

discussed before, incentivise flexibility through

market signals. The flexible resource adequacy

criteria and must offer obligation (FRAC-MOO),

in contrast, are prerequisites to connected

entities as defined by the system operator,

which can be categorized as capacity

requirements as discussed under market design

(section 3.3.2.2). These criteria and obligations

demand local grid operators and power

generators to comply with the ISO’s flexibility

needs. The flexible resource adequacy criteria

require from local grid operators to ensure the

availability of flexible capacity in their

jurisdiction. The must-offer obligation requires

flexible resources to make bids in the day-ahead

or real-time market when necessary (CAISO,

2014b; CPUC, 2015). CAISO also considers rules

and regulation for the aggregation of

distributed energy resources (CAISO, 2016;

CAISO, CPUC, & CEC, 2014). The so-called

distributed energy resource provider can

aggregate resources to achieve a minimum of

0,5 MW of capacity which it can use to

30 Real-time markets are the equivalent of the European intraday markets.

participate on the day-ahead, real-time and

ancillary service markets.

Supply-side flexibility in Denmark is

stimulated by incentivising system friendly wind

turbine designs. High capacity wind turbines

magnify the peak because their maximum

power production often lies at higher wind

speeds. During times of high wind speeds,

however, such peaks are less valuable. In 2014

legislation has been changed and the amount

of electricity over which the producers receive

feed-in premium now depends on both the

generator size and the rotor size. This has

reduced the skewed incentive to invest in

system unfriendly wind turbines with their peaks

at high wind speeds (Ea, 2015).

Another subject within the category supply-

side flexibility is the role of requirements for

generators (RfG) as defined in grid codes. While

in the Netherlands, all connected generator

technologies need to satisfy the same

requirements, e.g. Denmark and Ireland have

dedicated grid codes for VRES technologies. In

Denmark, differences exist between the RfG for

small power plants (<11 kW), larger PV plants,

larger wind generators, medium size and large

(>1,5 MW) thermal power plants (Energinet.dk,

2017). Ireland has a special category for wind

power as well (IEA-RETD, 2015b). ENTSO-E

names two reasons that dispute the merit of

dedicated RfG per generation type. Firstly, a

single code contributes to the aim for an even

treatment of users of the grid and hence

technology neutrality. Secondly, technology-

specific codes “would have been highly

inefficient in terms of keeping the network code

as simple as possible” (ENTSO-E, 2012, p. 23). A

single code has some disadvantages for the

integration challenge as well. A single grid code

might contain impractical requirements for

VRES and specific properties of VRES can

potentially disrupt system balance, power

quality, or voltage level. Dedicated codes might

be able to improve the integration of wind and

solar power by taking into account their specific

properties.

31

Another final method of reducing flexibility

needs on the supply side is to diversify energy

sources and optimize the energy mix. In the

Netherlands and most other EU countries,

however, the mix is largely decided by the

market, rather than planned top-down. Since

the electricity market has been liberalized, such

design would only partially be possible in the

Netherlands. The abilities to do so would be

limited to stimulation of certain technologies by

subsidies or other programmes. This, however,

would strongly deviate from the technology-

neutral approach as currently pursued.

Nevertheless, the energy report by EZ states that

“an integral approach offers more flexibility and

leads, economically and socially, to more

optimal outcomes than the optimization of

fragments of the system” (EZ, 2016b, own

translation). However, the policy publication

energy agenda (EZ, 2016a) does not refer to

decreasing the flexibility needs as one of the

reasons for aiming at a certain energy mix.

4. Interview Results As is mentioned in the methodology section,

the interviews that were held were semi-

structured (for the questions and interviewees,

see annex A and annex B respectively). The

results will be presented in the same order. The

first section presents general challenges and

discussion in the Dutch power system related to

flexibility, flexibility policy and changing roles in

the power sector. The second section describes

the positioning and ideas of stakeholders in

discussions surrounding policies for flexibility.

4.1. Challenges

As has been mentioned in the methodology

section, the interviews were designed to find the

31 In Germany this situations is often referred to as a kalte Dunkelflaute. This translates to a cold, dark and windless

period of time. In these situations both demand is high due to heating, while power supply by solar and wind

resources is at its lowest. For these situations long-term storage, or additional flexible capacity is necessary,

potentially using power-to-x type resources such as hydrogen or sythentic methane, or natural gas possible in

combination with CCS.

32 As will be discussed further in the next section when discussing capacity mechanims under the market design

heading, interviewees indicated that there are currently a number of signs that there is an overcapacity,

because of strong investments in the last decade. Also refer to the literature sections about market design

(3.3.2.2) and supply-side flexibility (3.3.2.4)

different positions within the discussions

surrounding flexibility policy of different actors

within the Dutch power system. Yet, a high

degree of unanimity was found on many points,

certainly when speaking more generally about

the challenges and flexibility options. The

urgency of flexibility challenges in the power

system was considered unanimously by the

interviewees to be low within all its dimensions:

energy supply, balancing and congestion. An

exception, however, albeit on a relatively small

scale, was that of local congestion problems,

depending on local grid conditions, rooftop PV,

EV, and heat pump penetration grades.

Congestion in the high-voltage grid operated

by TenneT is mostly considered as

unproblematic. Balancing problems were

mentioned to be virtually non-existent at this

point in time. In the words of Frank Wiersma

(TenneT) “We do not think there are

fundamental problems, but there are

developments that need investments to prepare

the system for them.” Yet, energy supply during

the dark and cold hours of the year was

mentioned by different stakeholders as an

important issue that requires more thought.31

These periods are characterised by peak

demand during low wind and solar feed-in.

Certainly when variable resources are combined

with the electrification of heating, seasonal

peaks further increase due to the simultaneous

electricity use in cold winter hours. Yet again,

while the issue is considered to be an important

one, the urgency until now is very low due to

the current overcapacity rather than a

shortage.32 This problem was expected to be

unlikely to arise before 2030, but will probably

continue to grow after that until 2050, in which

year the power sector might possibly be

32

required to have moved towards climate

neutrality (see footnote 29). In the other

direction, dealing with the surplus of energy

during high wind and solar feed-in is also

problematic. This could, however, be improved

fairly easily by creating a better business case

for power-to-x facilities through changes in the

grid tariff structure, as will be further discussed

in the next section under demand-side flexibility

(section 4.2.1).

The reason that the Netherlands was

considered to be largely on track to follow the

developments in the integration of VRES and

electrification of the heat and mobility sectors,

was mentioned to be the well-functioning

electricity market, its many players and its

healthy competition. The liberalized markets,

which were contrasted with other EU member

countries such as France, create relative

freedom and availability of a larger number of

players. Interviewees mentioned, furthermore,

the strength of this market is that it shows

variations in prices according to scarcity and

parties respond to these prices. The ability of

the market prices to vary with availability is

shown i.a. by low prices occurring currently,

which are explained by the amount of

overcapacity available. The Dutch system was

also praised for its clear system of balancing

responsibility and well-defined balancing

markets with access for a wide range of actors.

Finally, the actors active in the Dutch power

system are aware of the changes that occur due

to increasing shares of renewable energy and

other developments. Market players were

praised for their agility and creativity in adapting

and testing new concepts and authorities for

creating enough space for pilot projects.

33 It should be noted that adjacent to the discussion of flexibility needs due to VRE integration are several other

important developments that influence this discussion. Not only the increase in VRE causes an increase in

flexibility needs in grids, balancing and energy supply. E.g. the electrification of the heating sector could

strongly increase peak demand during cold winter hours. Also, notwithstanding the synergies that exist

through different vehicle to grid opportunities, the electrification of the mobility sector will impact distribution

grid needs. A complete discussion of flexibility needs ought to include such developments as well, but is

considered secondary in this paper for conciseness.

4.2. Flexibility options

As mentioned in the previous section, problems

regarding local congestion were rated as most

urgent, problems regarding shortages and

surpluses were expected to arise further ahead,

and balancing problems are not likely to come

anytime soon. Naturally, the most urgent issues

create the strongest demand for flexibility

options. Because of that, flexibility options in the

distribution grid, supply-side flexibility and

power-to-x technologies were mentioned to be

important. However, since most interviewees

thought that the role of policy and regulation

was mostly to ensure a level playing field in the

market (see section 4.3), they named market

design as one of the major aspects from a

governance perspective to create flexibility. As

becomes clear from figure 4 as well, the market

design is key to deal with changes in the power

system due to the influx of VRES. System

planning and the integration of energy storage

were considered less important for policy and

regulation. As mentioned in the literature

section, system planning was not regarded as a

task of governmental institutions but regarded

to be fundamentally dependent on the market.

Similarly, the integration of energy storage

should compete on equal terms with demand-

side management and supply-side flexibility.

The next subsections discuss the interview

findings on the various flexibility options.33

4.2.1. Demand-side flexibility

Most interviewees regarded demand-side

solutions as an important response to flexibility

challenges. It should be noted, however, that

different demand-side management options,

impact different aspects of the flexibility

challenge. While some flexibility options impact

balancing and energy requirements others

33

address grid needs. Dynamic prices and

aggregation are two flexibility options that can

be used to do both.

For creating a stronger price elasticity by

allowing variable prices for end-consumers,

dynamic pricing was discussed as an option. The

interviews showed that, although dynamic

pricing should be allowed as an option for

energy companies, this option has several

barriers and even some disadvantages for the

system. While dynamic pricing of end

consumers allows them to respond to

differences in prices in the wholesale market, it

was the general belief of the interviewees that

price differences would be too low for end

consumers to have an actual impact. While end

consumers pay about 20 €-cent per kWh of

electricity, only about 5 €- cent is paid for the

power itself. The other 15 €-cents remain

invariable under dynamic tariffs, causing only

small fluctuations when compared to the total

tariff. Although the co-variation of energy taxes

with power market prices would have an

additional effect, this would be a complicated

change in the tax system, on which the Finance

Ministry is dependent: “the energy tax is no

guiding tax anymore (…) it is mainly a source of

income, (…), that blocks giving good market

incentives” (J.L. de Ridder, EZ). Moreover, not

only the tax components would remain fixed,

but grid fees would also remain independent of

the time of use. Except further ‘damping’ of the

total variations in electricity tariffs, this also

causes another issue. Two interviewees pointed

out that if consumers respond to power prices,

dynamic energy pricing will increase the

simultaneity in electricity use and might,

therefore, increase the stress on local

distribution grids. The variation in dynamic

electricity tariffs as proposed is only dependent

on the wholesale market prices and does not

consider congestion at certain times and places.

The randomness that occurs now, is

something that grid operators enjoy.

[Dynamic pricing takes] the randomness

out, and you will get artificial peaks in the

low voltage grid. The costs of

strengthening [to accommodate that

peak] are probably much greater than the

savings you get by the use of the available

wind power. (T. van Melle, Ecofys)

Grid fees, however, could be included in

dynamic pricing. Thus, dynamic pricing would

address grid congestion as well, rather than only

responding to the energy supply and balancing

challenges. Various possibilities are available.

Alliander, for example, uses ToU schemes for

newly installed EV connections, just to prevent

peaks on the grid due to simultaneous EV

charging in the evening (M. Bongaerts,

Alliander). Price differences could also be more

dependent on the actual situation, by feeding

real-time prices for grid use to the consumer.

Another option was mentioned by Machiel

Mulder (Universiteit Groningen) and Jan Luuk

de Ridder (EZ). According to them, EZ and grid

operators are considering a ‘traffic light’ system.

In case of a green light, consumers could use

the grid as much as they need, since there is

enough capacity available. With orange light,

the consumer should remain under his or her

contracted capacity. A red light might e.g. mean

that the consumer would get an incentive to cut

its use down. Yet:

This is difficult too because parties could

start to act strategically. If you can go over

the contracted capacity in 90% of the

cases, you might as well contract a low

maximum capacity. This means that with

costs stay equal for the grid operator,

costs are redistributed towards less

flexible parties. (J.L de Ridder, EZ)

This last point relates to the discussion in section

4.3 about the redistributive effects of some

flexibility options, which in some cases have the

strongest effect on those with the least ability to

invest. Yet, these effects do represent the actual

costs of grid use, or in the case of dynamic

pricing, the actual cost of electricity at a certain

point in time. All in all, dynamic pricing for

household consumers was not considered as a

large source of flexibility because there is

uncertainty about price variation and the actual

response to them. Thus, savings would be small,

responding to prices would require much effort

or extensive automation of devices, flexible

34

resources in households are limited, and it

would have debatable redistributive effects.

Dynamic pricing for energy is already standard

in the industry, but neither are they subject to

any incentive for the time of use of the grid. This

important aspect of grid tariffs will be discussed

later this section under sector integration.

Aggregation, in contrast to dynamic pricing,

was expected by the interviewees to have a

much larger impact on the flexibility of the

demand side, both for small consumers and

industry, both for grid purposes and balancing.

While the response to variable tariffs is quite

unpredictable, aggregation is based on

contracts and would, therefore, be more

predictable. Aggregating services are already

quite active in the Dutch market in several

formats. Generally, the position among the

interviewees is that any aggregating party

influencing the power system is and should

remain balance responsible itself, or contract a

balancing responsible party (BRP): “balancing

responsibility or a comparable mechanism is a

requirement. I think that it is a critical factor for

the system and, therefore, for the market. (…)

One should not meddle with that” (S. Hers, CE

Delft). Indeed, as mentioned in section 4.1,

balancing responsibility is considered a crucial

aspect of the power system, a change in which

could have detrimental effects. Secondly, most

interviewees were convinced of the need for

aggregation entities to continue to engage in a

contractual relationship with the energy

supplier of a certain connection: “if you would

like to make agreements with a small consumer,

which also has an energy supplier, then this is

possible in our market model, but it demands a

consistency between the two agreements” (F.

Wiersma, TenneT). The requirements favoured

by the interviewees seems to come closest to

the USEF contractual model (see USEF (2017, p.

35)). This model requires full balancing

responsibility, contractual arrangements with

the supplier, and the possibility of a third party

(outside of consumer and supplier) on one

connection. Yet interviewees mentioned that in

the case of the contractual model, more

experience would be needed in the form of

these contracts:

It is really about efficiency and therefore

about minimalizing transaction costs, if

one would like to make a deal with such a

small party, then margins are small.

Therefore, standardized agreements

between BRP’s and aggregators are very

important, there is a learning curve we

can expect. (S. Glismann, TenneT)

However, two interviewees mentioned that the

aggregator is a role that should rather be

fulfilled by the supplier itself. This idea points

more in the direction of the USEF integrated

model, in which both functions of aggregation

and energy supply are combined in one

organisation, avoiding such contractual

relations:

An aggregator that turns a refrigerator off

or on would, according to me, be a task

for the supplier and not for an

independent player, because (…) a

producer could not price its customer

properly. It is unnecessarily complex. The

independent player could request a

supplier permit itself if it would like to

offer its services to a client. This would fit

in a liberalised market in which parties

compete on equal conditions. (D. Plomp,

Vattenfall)

Moreover, since energy suppliers price their

consumer on their expected energy use, some

claim not to be able to do so with another party

operating on the same connection. The point of

multiple parties on one connection was also

considered problematic by Jan Luuk de Ridder

(EZ):

If an independent aggregator is active on

your connection and starts shifting your

consumption or feed-in, this affects the

portfolio of the supplier or its balancing

responsible party. Suppliers and

aggregators should agree about who is

responsible for the changes and who

should bear its costs. That would be in line

with the [EU] Electricity Balancing

Guideline: ‘all injections and withdrawals

are subject to balancing responsibility’.”

(J.L. De Ridder, EZ)

35

A change in the grid codes to accommodate

two suppliers on one connection has been

proposed by Netbeheer Nederland and NEDU

and is currently under consideration by ACM

(ACM, 2017). In any case, the other set of

requirements that have to be fulfilled are usually

not seen as an issue in the Dutch system,

because of the aforementioned

competitiveness of the market:

The discussion about the role of the

aggregator is being discarded by several

stakeholders as a non-issue, because we

have a market with many parties and,

therefore, competition. Yet, it is the

question whether the sitting parties would

like to move along. (S. Hers, CE Delft)

Although the discussion is much livelier in other

countries with smaller amounts of players and

more market power such as France,

interviewees deemed the role of aggregator

important but noted it should not be favoured

over other parties. Neither should any regulated

tariffs for supplier compensation be installed,

which instead should be taken care off by the

market itself through contractual agreements.

Although aggregation is often used in the

context of small consumers, it might well, and

perhaps more easily, be used for industry. For

aggregation as an added value to the balancing

challenge, the industry would probably be the

better client. Timme van Melle (Ecofys)

mentioned that aggregation on the low voltage

grid can lead to the same simultaneity problem

as with dynamic pricing, thus creating artificial

peaks. Moreover, margins for the aggregation

of industrial electricity consumption would be

much larger. On the contrary, he noted that the

value of aggregation for grid purposes would

be higher on the low voltage grids and

therefore usually at household and other small

34 Altough demand-side management would be an important source for such flexible resources for grid

purposes, the subject is broader than that, since storage technologies or supply side flexibility might equally

be used. For this reason the subject is categorized under system flexibility.

35 Arbitratrage refers to the market mechanism of profiting from differences in prices in different markets, or at

different times. In the case of strorage technologies, the operators profit by buying electricity at low prices,

and selling them at high prices. Storage operators are dependent on these price differences that occur in the

market.

consumers. Since grid problems are more likely

to occur on low-voltage grids, load and

rooftop-PV aggregation on the household level

can contribute to this challenge.

Centring this latter subject is a debate about

the role and responsibilities of the DSO in the

context of unbundling. Although the changing

power sector requires alternative possibilities to

deal with grid congestion, DSO’s in the

Netherlands are required by law to strengthen

the grid at any congestion against any cost.

Congestion management through DSM, for

example, could be considered to conflict with

this requirement. Secondly, unbundling rules for

distribution and energy functions of the power

system do not allow DSO’s to engage in energy

sales and can therefore not act as aggregating

entities. This subject will be further discussed

under the heading of system flexibility.34

Except for the use of the existing flexible

resources on the demand side, flexibility might

also be found by the integration of other sectors

in the power sector and the flexible conversion

of electricity to other forms of energy. Power-

to-x type technologies were seen as an

important aspect to create absorption capacity,

enabling a response to low electricity prices.

While storage as a flexibility option generates

revenue from arbitrage,35 power-to-x

technologies profit from the relatively stable

value of their products (heat, synthetic gas,

hydrogen or ammonia). Power-to-x only needs

enough hours per year with low prices. Further

emphasis was placed on the option of power-

to-heat (PtH) specifically. The advantage of PtH

is the relatively low investment cost for electric

boilers. Although the efficiency of electric

boilers is actually very low as compared to e.g.

heat pumps, they are much less expensive in

investment (CAPEX). While their operating costs

36

(OPEX) are much higher, they are more

economical and pose less investment risk when

used for surplus (low electricity price) situations.

Sebastian Hers (CE Delft) explained that another

advantage for the Dutch context is the already

available infrastructure of CHP plants. Many of

these plants are already flexible, turn off their

power production at low prices, have large

electricity connections and require relatively

modest investments for electric boilers to use

low priced power for heat production. Power-

to-x and especially PtH have strong business

cases in a scenario with increasing VRE and,

therefore, an increasing amount of time with

low electricity prices. Yet, at least two policy

barriers exist for them from flourishing and to

compete on equal footing with other flexibility

options. Firstly, Frank Wiersma (TenneT) and

Timme van Melle (Ecofys) mentioned the

barriers of CO2 allocation:

with power-to-heat [the district heating

sector] uses more than average wind

power, while they pay for an average

emission factor. [They] are not rewarded

for the fact they demand electricity at

times with much wind and solar [power]

in the system, which yields low CO2 heat.

(T. van Melle, Ecofys)

Since power is used mostly during strong VRE

feed-in, heating system operators claim that this

leads to less-than-average CO2 emissions, for

which they are not recognized. The second

barrier is found in the tariff structure of grid fees.

Sebastiaan Hers (CE Delft) and Wieger

Wiersema (ACM) mentioned the importance of

changing this structure:

The problem is that we need absorption

capacity only for 500 hours per year (…).

The transport tariffs are very expensive

(…) for something that is barely used, but

sporadically at very high capacity. (…) One

could question whether capacity-use

should always be discouraged so

stringently, or only when there is a risk of

overload because the dimensioning of

the grids cannot handle the transport

demand. If high feed-in of wind and,

therefore, low prices coincide with the

moments of low grid load (…) one could

choose to limit the costs for capacity use

for consumers, such that it remains

attractive to respond to the price signal

and contribute to system balance. (S.

Hers, CE Delft)

Since the tariff for the maximum capacity grid

capacity used is independent on the time-of-

use of the grid, power-to-x technologies would

pay the same capacity tariff, while it is likely they

use the grid only a small number of hours per

year during surplus of available grid capacity.

The grid fees deteriorate the business case of

power-to-x technologies since they do not

adhere to the cost-causing-principle.

Like PtH solutions, the electrification of

heating in the household sector might increase

flexible capacity to cope with short-term power

surplus and the supply of balancing services.

However, when households move to fully

electric heating systems, electrification will most

probably also increase seasonal imbalances:

“You would have an enormous peak when heat

for households is supplied using power. (…) it

could bring a certain rigidity because you will

need enough power plants to keep the house

warm. “ (D. Klip, CIEP). While heating systems

might have a reasonable ability to deal with

short-term fluctuations, by making use of heat

storage tanks or heating inertia of buildings,

winter demand will remain much higher than

summer demand. Since the dimensioning of the

power system is dependent on peak demand,

the increase in seasonal peaks could lead to

higher system cost.

4.2.2. Market design

Some market design issues have been

discussed in the last section because demand

resources are part of the market as well. This

section, however, discusses the market design

itself, with emphasis on the wholesale and

balancing markets. As in the literature study, the

market design contains the subjects of market

access, completeness, pricing, VRES

participation, representation of grid conditions,

integration with neighbouring countries, and

the capacity mechanism discussion.

37

Generally, the market was considered the be

open, complete and to have the right incentives

for different needs of the system. “The market

works well, more and more types of player are

joining, there are more and more products on

the market, in both actively and passively. I am

honestly quite positive about it” (M. Mulder,

RUG). Market access is well accounted for,

providing the ability for (Distributed) VRES,

aggregation services and demand-side entities

to enter the markets as long as they are

balancing responsible. Yet:

Fundamentally, our market model is

technology neutral in, for example, the

specification of balancing products, but if

you look at it in more detail then it

contains elements which have been

designed for large power plants. One

could think about how to tweak this such

that these are not favoured over DSM and

aggregation. (F. Wiersma, TenneT)

One of these possibilities is to equalize access

to balancing market for large consumers which

could act as balancing agents on the demand

side (W. Wiersema, ACM). According to Timme

van Melle (Ecofys), Sebastiaan Hers (CE Delft)

and Machiel Mulder (RUG) it is rather the

attention and knowledge of the industry that is

lacking than the accessibility: “The barrier is not

only the market but also the attention of the

industry. They do not have the knowledge for it

[and] do not start with it because they save too

little for the complexity it brings” (T. van Melle,

Ecofys). Where access barriers do exist for

balancing markets, interviewees noted that they

are either justified or, when unjustified, there is

a tendency to reduce them. “There is a lot of

attention towards [market access barriers] in

legislation and regulation. For example, the

requirement for equal up- and downward

[symmetrical red.] capacity, such barriers are

gradually reduced“ (A. van der Welle, ECN).

36 This situation might occur because players make their actual contribution in real-time. Market participants,

therefore, do not know of one another what they are doing, while they only know the imbalance volume and

prices 5 minutes before real-time. For example, in case of a shortage, many parties might decide to make use

this system, which could overshoot the shortage. This might leave the system with a positive imbalance, which

still needs to be corrected by TenneT.

Finally, even when certain technologies

would be unable to sell their capacity or energy

in the balancing market, Sebastian Hers (CE

Delft) and Machiel Mulder (RUG) noted that the

way the Dutch system allows for passive

contributions is, in fact, another way of entry to

the balancing markets which makes relieving

these barriers less urgent. He noted, however,

that this system might start to lose its merit once

larger volumes are used in the passive

correction of imbalance and passive

contributions might ‘overshoot’ the actual

imbalance.36 Except for this note, the system

was widely regarded as an advanced and well-

designed market attribute.

The wholesale and balancing markets,

furthermore, were considered to be functional,

without too many disturbing or overregulated

elements. Still, many interviewees noted that

price caps disturb maximum and minimum

prices, even though these are rarely reached:

In certain situations, for which you need

very high prices to balance demand and

supply, then prices would be cut off (…).

These are precisely the moments that are

of great importance in the business case

of flexible capacity. That is why price caps

are not desirable. (F. Wiersma, TenneT)

The other option would be to couple the

maximum prices to the so-called value of lost

load (VoLL), referring to the value one would

place on not decoupling a certain load without

the consent of the consumer. The discussion

about the value this should have, however, is

considered very tough. In any case, most

interviewees mentioned to maximize the prices

caps as much as possible, to allow the maximum

price variations, such that any flexibility option

would receive the maximum incentive.

Even though market liquidity on the intraday

market is often mentioned one of the less well-

performing aspects of the Dutch power market,

38

it is the belief of some interviewees that it will

improve once the need for flexibility will

increase. The absence of liquidity in the ID

market is regarded merely as evidence that such

short-term trade is not necessary up to this

point:

Demand and supply in the intraday

market will probably grow compared to

the day-ahead and forward markets as

solar and wind power grow and shorter

forecasting times become relevant. It is a

development that (…) will be driven by

[demand for flexibility] and not something

for which the market should be arranged

fundamentally different. (F. Wiersma,

TenneT)

The suggestion of adding additional auctions to

the continuous trade, such as is the case in the

German IDM, was neither accepted as a good

proposal nor rejected. It was unclear which

effects this would have. While the addition of

auctions might attract market liquidity, it

concurrently takes away the freedom of bidding

at any time, which is possible in a continuous

market.

15-minute pricing, on the other hand, was

considered a no-regret change for the IDM and

might also be beneficial for the DAM. The

advantage of 15-minute instead of hourly

products is that portfolios can be managed

more precisely, which becomes more important

once fluctuations become more apparent within

the hour.37 The usefulness of shorter temporal

granularity also increases with improving

production and consumption forecasts. Only if

parties know their expected production and

consumption within the hour from a day ahead,

shorter products would be useful for the DAM.

The disadvantage, as noted by some of the

interviewees, is an increase in administration

both for market platforms and for market

37 If strong fluctuations of scarcity occur within the hour due to VRE abundance or scarcity, the imbalances that

occur within this hour are settled by the TSO, but against higher costs. 15-minute products would mean that

only imbalances within each quarter-hour need to be settled against imbalance prices.

38 The amount of electricity that is subsidized is based on a number of full-load hours, which is determined

differently for different technologies, and for wind power determined on the base of a project proposal (RVO,

2017).

players, because of a quadrupling of data.

According to David Plomp (Vattenfall) “15

minutes is a right balance between unnecessary

administrative work and the time needed to

balance the system. We should not move

towards 5 minutes.” All in all, the benefits are

likely to be greater than the disadvantages.

Another discussed topic is the degree of

market participation by VRES. The general

conclusion is that participation of VRES under

the SDE+ subsidy scheme is reasonably

accounted for. Since the SDE+ is a market

premium scheme, parties under the subsidy

scheme are exposed to the market as well. Yet,

unlike other technologies, SDE+ subsidized

generators are spared from some market risks.

Until a generator has produced the defined

number of full-load hours,38 it has an incentive

to produce at any above-zero price on the

power market to receive its subsidy. Once the

prices become negative for a prolonged time,

the market premium drops to zero. Although

one could claim that, theoretically, the subsidy

disturbs the way VRES act in the power market,

it does not give a strong perverted incentive. It

should be noted, however, that as mentioned in

section 4.1 some interviewees would rather see

the EU-ETS work as an overarching method.

This system is goal-based, minimizes

government intervention in the power market,

would give the least disturbances, and would,

therefore, work in favour of flexibility. In the

words of Frank Wiersma (TenneT):

A CO2 price based on societal costs would

be the social-economic ideal stimulation

model, but while we do not have that, the

SDE+ seems to be a good approach, as

long as the owners are required to

arrange their balancing responsibility and

are, therewith, subject to prices in the

energy market.

39

Net-metering is another subsidy scheme

which impacts the market, but more so the retail

than the wholesale market. Interviewees noted

that the scheme theoretically does not adhere

to the cost-causing principle, since grid costs,

caused by those responsible for peaks and

congestion, are socialised. However, net-

metering is not designed for this purpose. The

overall opinion was that net-metering has been

a huge success in its original functions of

creating public support and engagement in the

energy transition, overriding the critique that it

disengages household energy production from

the energy market and decouples them from

the variation in the value of electricity.

Moreover, the adverse effect of net-metering

on system balance should, according to

interviewees, not be overestimated. The only

real impact would take place at times of

negative prices on the power market, when

there is no incentive to shut off household PV

systems. Although this is expected to increase,

this situation currently rarely occurs. At any

positive price, a change in the scheme would

not change the balancing situation. An

alternative to yearly net-metering could be a

combination of dynamic tariffs and net-

metering, in which the costs are settled each 15-

minutes. This would create a stronger

adherence to the cost-causing principle.

Sebastiaan Hers (CE Delft) and Timme van

Melle, however, noted that this would remove

another unintentional positive aspect to yearly

net-metering. The inclusion of short-term

settlement would give household ‘prosumers’

the incentive to use their own power, and invest

e.g. in battery storage, since one saves on their

taxes this way. In case of a 15-minute settlement:

“one would have an incentive to use the power

him/herself, since you would save the [energy]

taxes, but saving taxes is a distributive effect and

not a saving for the economy” (T. van Melle,

Ecofys). This scheme would not be an optimal

situation from a system perspective, because it

would lead to extra costs for storage, but just

39 It is likely that it is because of this reason the investment subsidy would be preferred by the storage industry,

as mentioned by EZ according to Solar Magazine (2017). As mentioned, while the tax wegdge increases the

incentive to invest in household storage, this would be an inefficient investment for the economy.

shifts benefits from the state to the consumer.

Net-metering removes the ‘tax wedge’ between

energy bought and energy sold and, thus,

prevents inefficient investment in storage.

Although from a flexibility perspective one

might argue that any investment in storage

would be a desirable development. Yet, this

argument shows that storage as arbitrage

between low, tax-exempted, energy costs from

one's own resource and high, taxed energy

costs from an energy supplier is not efficient.

Since the revenue from the investment is based

on tax savings, it becomes clear that the market

value of the storage is actually much lower and

might not justify the investment. Investment in

storage would only be efficient if it would profit

by arbitrage between wholesale market power

prices or from relieving grid congestion. EZ,

however, is now considering to replace the net-

metering scheme for the period after 2023 by

either a feed-in subsidy or an investment

subsidy (Solar Magazine, 2017). The feed-in

subsidy would top up the feed-in payment by

the energy company. The investment subsidy

would be a one-off subsidy to reduce the total

investment costs. Since these options were only

announced during the interviews, these were

not discussed. It could be noted however, that

like net-metering, a feed-in subsidy would

reduce the tax wedge.39

Another point that was discussed in the

interview were the possibilities to incorporate

and represent grid conditions into prices for

grid users. While grid costs are charged to grid

users, this is done in a socialised matter.

Therefore, grid use is independent of the time

and location of use, both for industrial and small

consumers. As mentioned before, a change in

the tariff structure for grid fees could improve a

level playing field and, thus, improve the

business case of power-to-x technologies.

Nodal pricing would be an important option

coming to mind to integrate both locational and

temporal aspects into the energy prices.

40

Although some responses were positive about

nodal pricing, most interviewees thought it will

probably remain a theoretical discussion, and

did not believe it would have actual practical

applications in the near future for the

Netherlands. The arguments were disparate.

Firstly, on a descriptive level, nodal pricing was

considered politically unfeasible, because of the

expected distributive effects: “the disadvantage

is the distributive effects, and that makes the

opposition against such a system so great” (A.

van der Welle, ECN). As Sebastiaan Hers (CE

Delft) noted, society would never except that

your energy cost would increase because of

others in your neighbourhood who cause grid

congestion.40 Moreover, it would create

incentives to move to other locations, which

would be the purpose for industrial consumers

and producers, but would be undesirable for

households.41 Still, regarding political feasibility,

it was mentioned to be unlikely considering the

European integration efforts. Firstly, the

European integration efforts attempt to create

more uniformity, while nodal pricing would lead

to further disparity of prices: “There are

advantages to nodal pricing, but if you see the

European integration as a value, in which we try

to reach price convergence, it is not especially

good“ (S. Glismann, TenneT). Secondly, nodal

pricing does not fit in the European Target

model: “I think it would not fit in the current

system, then other member countries should do

it too, I do not see nodal pricing working next

to other systems in neighbouring countries“ (K.

de Bruin, ACM). If such a transition would take

place, in consequence, it should not be a

national, but a regional decision. Moreover, as

mentioned by Samuel Glismann (TenneT) and

Adriaan van der Welle (ECN) nodal pricing

presupposes a central dispatch market, where

40 If another consumer causes stronger grid congestion by e.g. installing a EV charging system, this could lead to

higher energy costs for those that did not cause to problem, but happen to be connected to the same

distribution system.

41 Another note that was not mentioned by the interviewees, that even if relocationing of people would be

desirable because of local congestion, the costs would likely be much too small to actually have that effect.

Because of that, it would likely just cause household consumers to have changed costs. This would, therefore,

not be a saving of system costs, but rather be a distributive effect.

production facilities are managed centrally by a

single algorithm, optimizing the whole system.

The European system is organized according to

a self-dispatch model, where producers are free

to make their own dispatch decisions and trade

bilaterally. As such, a transition to nodal pricing

would require a compromise on a certain

degree of freedom. Besides its political

feasibility, Timme van Melle (Ecofys) noted that

prices differences between nodes would

probably be very small due to the absence of

any structural congestions. Because of that, he

considered nodal pricing to be a high-risk

investment. Yet, Adriaan van der Welle (ECN)

noted the change to a nodal pricing system,

despite its drawbacks and political barriers, has

been implemented in several US ISO

jurisdictions within a short period of time, and

its implementation should, therefore, not be

ruled out. He as well as Machiel Mulder (RUG)

and Diederik Klip (CIEP) agreed that the system

would, at least theoretically, be superior. Yet, as

mentioned, that is not to say implementation is

likely or even desirable. If not a complete

implementation, Sebastiaan Hers (CE Delft)

mentioned that a process occurring

spontaneously might cause de facto locational

aspects to power prices:

Concepts are being developed that bring

about [locational pricing] via the back

door. If an aggregator develops a

platform which reflects local constraints

besides market provisions, (…) than you

are creating price differences outside of

the market. (Sebastiaan Hers, CE Delft)

Since aggregators might work for grid

operators as well as in the power market, they

41

might create locational incentives, without a

top-down market design for it.42

As an alternative to nodal pricing, many

interviewees mentioned smaller price zones

within the country. Like nodal pricing, however,

many disadvantages were raised by the same

group. The advantage would be that it could

address systematic congestion between certain

areas while remaining in the same self-dispatch,

market-based path. Some of the same

problems, however, remain present as well.

Inequality through multiple prices within the

country and its related political opposition

remain an issue. Moreover, it might lead to

issues of market power, market liquidity and

possibly arbitrary redefinitions of zones, while

attempting to solve a lacking structural

congestion problem.

Within the topic of market integration with

neighbouring countries, it was a general belief

that stronger European market connections are

already being made. According to Adriaan van

der Welle the Clean Energy Package (or winter

package) could give a boost to further

harmonisation. The XBID project was an

explicitly discussed example of such

harmonisation efforts. According to the largest

European market platform EPEX, the

introduction of XBID means that any market

player within its scope would be able to trade

on the intraday market with any other market

player, irrespective of its bidding zone. Thus,

zones share and hence increase their liquidity

(EPEX Spot, n.d.). Multiple interviewees (from

ECN, TenneT, Vattenfall, CE Delft) agreed with

this and mentioned that this project will

probably lead to an increase in IDM market

liquidity and therefore improve its effectiveness.

“That would be the big breakthrough for the

Dutch intraday market, if liquidity will increase

strongly with it, trading on this market will

become worth it” (S. Hers, CE Delft). Yet, some

noted that the advantages might only come

over time, once more reliance on the IDM would

42 Even though this subject might be an important point in nodal pricing and aggregator discussions, it was not

further discussed and only brought up by one of the interviewees.

become necessary because of stronger

variations and increased predictability.

Further integration and unification efforts

should, according to Adriaan van der Welle and

Martijn van Gemert (Vattenfall), be directed

towards shifting to more regional and less

national grip operation:

It is a very important issue for us that

system operations are still this

fragmented. An internal market means

one should not discriminate between a

power line within the Netherlands and, for

example, a power line from Amsterdam to

Berlin. We would prefer independent

regional grid operation. (Martijn van

Gemert, Vattenfall)

Supranational grid operation, however, needs

to deal with the barrier of significant differences

between EU member countries, including

different power market models. While the

Netherlands is strongly based on a competitive

market in its set-up, other countries depend

more on monopolies and governmental

intervention. Kick de Bruin (ACM), for instance,

mentioned that e.g. France is not equally willing

to change its market structure. It remains the

question, however, whether this will continue to

frustrate harmonisation efforts.

A final overarching discussion within the

market design for flexibility is resource

adequacy and whether a capacity mechanism is

required for that. A capacity mechanism would

operate next to the energy market to guarantee

the security of supply by either securing returns

on investment or requiring energy companies

to adhere to certain standards. The common

position among the interviewees was that a

market-wide capacity payment or auctioning

would not be desirable nor necessary, both

currently and within the foreseeable future.

Several arguments were used. Firstly, a capacity

market would contradict the efforts to have

clear, undisturbed scarcity pricing signals which

are present in the energy-only market.

42

Secondly, Machiel Mulder (RUG) posed that the

argumentation for investment security of

proponents of capacity markets is false.

Producers would like a capacity remuneration to

ensure profitability in a market with decreasing

prices while, according to him, these lower

prices actually indicate that there is no scarcity

and, therefore, no need for capacity

investments. Instead of an indication of market

failure, the low prices are an indication of the

absence of scarcity. The market did not fail to

show the scarcity value of capacity, but market

players rather failed to predict that their

combined investments would lead to an

overcapacity. More interviewees confirmed that

the market is functioning right, and through

that, does create the right investment signals. A

third argument mentioned by many

interviewees is the issue of governmental

intervention itself. In a capacity payment

mechanism, governmental institutions would

take up the task of determining and

remuneration capacity, which would be a shift

contrary to the liberalisation of the power

market. While, according to Sebastiaan Hers, a

governmentally organised power market is not

per definition inefficient, a capacity market

would lack the creativity which is present now,

and neutralize scarcity prices:

I think that a capacity market would

squeeze out all flexibility, depending on

how the market is designed. If one would

pay for available capacity based on a

singular objective, then available capacity

would always be valued, but scarcity

pricing does not occur any more.

Conventional capacity and perhaps in

some cases industrial demand-side

management might profit from this, but

flexible options with limited availability

would bring in insufficiently. (…) With that,

a lot of innovation in flexibilization, that

has set in with the energy transition,

would be nullified. (S. Hers, CE Delft)

Thus, capacity markets could completely shift

the situation in favour of some technologies,

while discriminating against others.

Furthermore, because its negatively impacts the

energy markets scarcity pricing, it could do

permanent damage to the current system.

Notwithstanding the general preference for an

energy only-market, Jos Sijm (ECN), Diederik

Klip (CIEP) and David Plomp (Vattenfall)

mentioned that a capacity mechanism should

not be ruled out, if it would become necessary

in the future. The form of the capacity

mechanism, however, should be designed such

that it ensures a level playing field, without it just

being a tool for the protection of the

conventional industry (J. Sijm & A. van der

Welle, ECN). To limit its impact, David Plomp

(Vattenfall) noted that if a capacity mechanism

would be installed, it should be a strategic

reserve rather than a market-wide capacity

payment.

4.2.3. System flexibility

As in the literature study, this section contains

the regulatory flexibility options in between

supply and demand apart from the market

design. Although much of the grid discussion

mostly covers issues of spatial aggregation,

some points are motivated by temporal

imbalances as well and, thus, address the

balancing and energy supply challenges.

One of the liveliest discussions within this

section is that of the role of the DSO in relieving

local congestion. The question is whether DSO’s

should be allowed to use a set of congestion

management methods as an alternative to grid

strengthening. The common opinion among

the interviewees was that although the DSO

should have other options than strengthening,

these alternatives should only be applied in a

predefined set of circumstances. As has been

mentioned under DSM, it is equally considered

important (from regulator ACM to grid operator

Alliander) that the assets are not owned by the

DSO, but are outsourced to a market player:

We are proponents of the concept that

grid operators do not [own flexible

resources] themselves, but tender it

unless the market is unable to deliver. This

would be in line with the proposals in the

Clean Energy Package of the [European]

Commission. (J.L de Ridder, EZ)

43

As an example, Martijn Bongaerts (Alliander)

mentioned a project by Alliander (largest DSO)

to tender their flexibility needed to manage a

local congestion. The supplier of flexibility,

whether it would be an aggregator or

otherwise, would have two income flows. Firstly,

it would receive a remuneration for relieving

grid congestions and, secondly, it could sell its

flexibility on balancing markets. This option was

favoured by most interviewees, because of the

strong emphasis on maintaining the unbundling

principles, which prevent DSO’s to be active on

the power market. While this construction

addresses the issue of the DSO role, it still

conflicts with the ‘strengthening only’

requirement. The overlegtafel

energievoorziening, a discussion group

comprising members from many different

institutions in the power system, has taken steps

to create a transparent methodology to

consider when strengthening is necessary and

when other options should be allowed (see e.g.

(Overlegtafel Energievoorziening, 2015)). This

should be installed to prevent corroding the

reliability of the grid and the freedom of grid

connection. Generally, the interviewees agreed

that emphasis should remain on strengthening,

unless circumstances would make it too

expensive or otherwise undesirable to do so.

Examples of such cases would be for congestion

occurring very rarely, or in the built environment

where strengthening would lead to

unacceptable costs compared to the added

value. Some doubts were expressed about the

value that congestion management would have

as well, considering that it will and should be

rarely applied:

Perhaps one should reassess the

expectations of a couple of years ago,

when everyone expected that

flexibilization in the context of preventing

grid strengthening would have a great

potential and would make possible great

costs savings. (…) I have the idea that the

size of the potential and of cost savings

are smaller than we thought a couple of

years ago. (J. Sijm, ECN)

Another note about congestion management

by Frank Wiersma and Samuel Glismann

(TenneT) identified a tension between different

interests. While short-term interests of

shareholders might pressurize DSO’s to achieve

short-term savings by applying congestion

management, this might contradict long-term

benefits that could have been harvested from

timely investment in strengthening. Timme van

Melle (Ecofys), however, indicated that

congestion management might be the lower

risk option in some cases, because of its shorter

depreciation period. If it is unknown whether

congestion will occur, or exactly how much

capacity will be needed to prevent it, congestion

management methods might be used as a more

temporary measure. Certainly when considering

the challenge of predicting power flows on the

distribution level for very long investment

terms, shorter-term investments in congestion

management assets might be an outcome to

observe the developments. Yet, most

interviewees found that it is more likely to be

necessary to restrict DSO’s in their efforts to

apply congestion management than it is to

stimulate it, because they have directed

themselves to such measures already. Data the

distribution grid, let alone about power flows far

in the future is scarce. To apply congestion

management, but also to make efficient

investments in grid strengthening, it would be

necessary to create an information

infrastructure. According to Sebastiaan Hers (CE

Delft) the investments become disproportionate

to the potential flexibility when speaking about

neighbourhood scale forecasting.

The transmission grid, on the other hand, has

a much greater data supply and is much less

dependent on individual changes in the grid.

The transmission system “is somewhat easier to

plan, because it happens on a bigger scale. You

know better what is happening, unlike the

distribution grid where one, so to speak, needs

to predict a single street“ (T. van Melle, Ecofys).

According to many interviewees the

transmission sector, including the

interconnections with neighbouring countries is

quite well organised. Just two discussions came

to light during the interviews. The first one,

44

which has already been touched as well in the

market design section, is the lack of regional

approach in network planning.

We have something called the TYNDP

[Ten-year network development plan],

but we should get much better at taking

a European perspective, for which we also

need a lot of solidarity. And if The

Netherlands profits from [foreign

investment into transmission capacity],

then it should not all come out of one

purse. A lot should change there, because

(…) how policy is made is determined by

voters in a certain region. (S. Glismann,

TenneT)

Since grid operation and its regulation is

determined nationally, intranational

strengthening receives more attention than

international strengthening. Grid operators are

primarily mandated to ensure enough national

capacity is available.

Whether further international connection

capacity and trade are more cost-effective than

other flexibility solutions, is not unambiguously

determined from the interviews. Jos Sijm

expected that further grid strengthening and

extension will be one of the most important

sources of flexibility, if not the most important

source. According to Sebastiaan Hers (CE Delft),

on the other hand:

You will get a peak load of 500 hours [per

year] for which you will need to scale

capacity, then it might become very

expensive because you speak about the

grid from Rotterdam to the German

border. I suspect that would be a bad

deal.

He considered that local conversion options to

hydrogen or further conversion might prove

more important than increasing interconnector

capacity.

Apart from the grid, the category of energy

storage contains another set of technologies

that enable flexibility in between supply and

demand, both for grid and for balancing

purposes. While most interviewees confirm that

storage plays and will continue to play a certain

role in providing short-term flexibility, they also

find it to be just one of the flexibility options. As

became clear earlier, the consensus about

technology neutrality means that, despite the

attention towards storage, it should not get any

preference above other options. As mentioned

by Martijn Bongaerts (Alliander), storage does

not have any value in itself and is only just as

valuable as the price differences of electricity at

different times. Storage, moreover, is thought to

have less urgency than many other flexibility

options by some interviewees:

Energy storage is definitely necessary

within the system later, but before that

situation, one can continue with options

that are more cost efficient such as

demand response, power-to-heat [and]

existing flexibility in the production park

while there is still gas. (J. de Joode, ACM)

As Sebastiaan Hers (CE Delft) and Frank

Wiersma (TenneT) mentioned, storage requires

the explicit acquisition of assets, while some

options are able to make use of the existing

infrastructure or require little extra investment

for flexibilization. It would, for example, be

much more interesting to make use of the

batteries in electric mobility, than investing in

storage explicitly for balancing. Yet, it is the role

of policy and regulation to ensure storage has

equal opportunities to provide services, if this

would be cost effective. The most obvious

barrier, as mentioned in the literature review, is

the double taxation of electricity when it is used

for storage and sold again as electricity.

However, according to Jan Luuk de Ridder (EZ),

this barrier is currently being considered and

probably relieved by the ministry of finance.

4.2.4. Supply-side flexibility

Most policy and regulatory actions necessary

for flexibility on the supply side qualify as

market design aspects, but this is partially so

because of the clear valuation of market

principles among the interviewees and in the

Dutch power market in general. Although the

Netherlands has little instruments and little wish

to set strong demands to power producers, this

is different in other regions. Except for some

basic requirements for generators as defined in

45

the grid codes, producers are essentially free to

use their resources as they please. Suggestions

in the interview for adopting measures to

demand a certain level of flexibility or

controlling the power park top-down to ensure

flexible resources (as discussed in section 4.1)

were generally not accepted. Neither were there

any obvious barriers to reap the possible

potential of the available flexibility. Flexibility on

the supply side was expected to come from a

mix of sources that is strongly dependent on

technology costs, new technology

developments and economic conditions. Some

interviewees mentioned that for the present, the

largest share will probably be taken up by the

gas-fired power production park. Certainly

when considering the recent coalition

agreement deciding on a coal power plant

phase-out before 2030, gas power is likely to be

the most important flexibility option. When

moving towards higher CO2 prices, however, it

is likely that either the role of gas power in

flexibility will reduce if not combined with CCS.

Which flexible technologies will take over this

role, remains to be seen, but likely some

combination of biogas, CCS and curtailment of

VRE.

4.3. Overarching discussions and

underlying values

Different positions within some of the preceding

discussions are explicable by underlying values

pursued in policy. While these values are often

discussed implicitly, making them explicit might

help in understanding different positions within

these discussions, because they might silently

explain the outcome of the position.

A first important discussion concerns the

socialisation of costs versus the application of a

cost-causing principle. Whereas socialisation

strives to share costs equally, the cost-causing

principle strives to apply tariffs for electricity and

grid use as much as possible according to the

costs caused by a certain user. An example

discussed in the last section is the application of

nodal pricing. A full application of nodal pricing

would cause a clear and precise incentive to the

producer and user of electricity depending on

the grid conditions. Yet, it would lead to

distributive effects and could cause users to

experience disadvantages due to the use by a

neighbouring user of the grid. Secondly, it

might give some the opportunity to profit, but

possibly to the cost of others which do not have

the opportunity to respond flexibly to time and

location dependent prices. Such issues play a

role in several different discussions about policy

and regulatory frameworks. The values of

flexibility in these cases are often at odds with

values that are met by socialisation of costs.

Other examples related to this point discussed

in the previous sections are dynamic pricing,

dynamic grid tariffs and RE subsidy schemes.

Secondly, some consider decentralisation as

a value, since it connects people more clearly to

their resources. Because of that, some power

consumers strive to be self-dependent and

disconnect from the grid. If this would be done

on a larger scale, however, due to e.g. falling

prices for electricity storage, interviewees

mentioned this could lead to high societal costs,

paid for by the group unable to invest in

‘autarky’. In the words of Timme van Melle

(Ecofys): “the connection of demand and supply

over the whole of the Netherlands does really

have an advantage, so let’s not try to make our

houses independent of each other, we neither

cultivate our own vegetables.” Because a shared

robust large system would lead to lower societal

costs shared more fairly, let alone creating a

stronger European integration, autarky is

considered unfavourable and should be

regulated.

Another overarching discussion is that of the

role of policy and regulation within the context

of flexibility. There was a wide consensus among

the interviewees about the primacy of the

market, which refers to the principle that the

energy (-only) market should solve any issue

itself, unless clearly shows to be failing. The role

of policy and regulation is to ensure a level

playing field for actors in the electricity market

and additional policy should be installed only in

case of danger to the system security. It should,

therefore, remain on the sideline as much as

possible and remain technology neutral when it

does interfere with the market. Not only was it

46

seen as impossible to make the right

assumptions about the future power system to

make the right policy decisions about certain

technologies, but making technology choices

would also “make one vulnerable to lobbying”

(J. de Jong, CIEP). If subsidy schemes, for

example, are aimed to favour a certain

technology, this could lead to sub-optimal

overstimulation while disregarding

technologies that could potentially do the same

thing more effectively, or at a lower cost.

Therefore, Influencing the power market should

be done as much as possible through market

design and placing incentives rather than

installing regulations outside of the energy-only

market. Since the interviewees generally

mentioned the Dutch market to be well

developed and open, to show price variations

according to scarcity, and to respond to those

varying prices, there is little reason for

restructuring, let alone political intervention.

Indeed, some respondents explicitly regarded

the possibility of political intervention in the

energy-only market in case of scarcity a possible

danger. This point plays a major role in the

discussion of i.a. capacity mechanisms,

technology support, system planning and the

role of aggregation. When taking this point of

non-interventionism to the furthest, no other

stimulating or steering policy should exist

except for CO2 pricing: “You could even take

[technology neutrality] that far, that you should

not have other policy than CO2 limits, not even

flanking policy such as renewable energy

directives” (D. Klip, CIEP).43

Some respondents mentioned, furthermore,

that the level (EU, national, sub-national) at

which policy and regulation are issued, is of

importance. Although the perspective of this

paper is national, many of the issues under

discussion are likely to be governed on a

European level, because they cross borders.44

While the market is mostly nationally regulated,

more tasks are likely to shift towards EU

43 Whether this would actually be desirable, was not thouroughly discussed in the interviews.

44 Except that issues cross borders, European integration was also mentioned as a value in itself, because it

strengthens the ties between the member countries by creating common interests.

institutions such as ACER and Entso-e. The

discussions of national regulation, therefore,

becomes of smaller importance. “The

Netherlands takes part in the CWE region and

has strived for further European integration, we

have to search for solutions together with other

countries, it is hard to make it alone” (A. van der

Welle, ECN). Yet, these discussions discussed in

this paper are equally important for the EU and

are, therefore, still relevant to discuss.

Moreover, even though there might be a

consensus about subjects involving the role of

policy and regulation in the Netherlands, issues

such as capacity mechanisms are strongly

debated in, and between, other EU member

states. Ideas about the Dutch system, therefore,

are a contribution to the EU discussions as well.

5. Discussion As mentioned in the introduction, this paper’s

foremost purpose is to assess the non-technical

barriers of flexibility in the mass grid integration

of VRES in the Netherlands. It has shown what

are the most important discussions when it

comes to policy addressing flexibility and which

factors are prioritized in the Netherlands, as

assessed by the interviewed experts. There are

two reasons that this means there are

limitations to what this paper can conclude

about such options, let alone what should be

decided on the basis of these arguments.

Firstly, the decision is inherently political,

since argumentation is often base on different

values. As has been mentioned in the

methodology, discussions can be often

explained by different interests of parties. This

paper, therefore, has not attempted to find

argumentation to defend one side of the

discussion, but rather to give an overview of the

various sides and to show its underlying values.

Some of such underlying discussions, as has

been noted in chapter 4.3 are socialisation

versus the application of a cost-causing

principle, centralisation versus decentralisation,

47

the primacy of the free market versus

intervention and control, and the level of

policymaking. These subjects came to light as

determining factors in many of the flexibility

options. Although sources might present an

option to be singularly positive or negative, they

are often disputable based on other values. The

choice between different values makes such

decisions inherently political and not as much

scientific.

The second reason that conclusions about

policy options presented here are limited is that

the data and argumentation is not exhaustive.

In some cases, this paper might have shown a

consensus, or a single side of the discussion. It

should be noted that in these cases, counter-

arguments might simply not have been

represented either in literature, or among the

interviews. Notably, when looking to figure 1,

which shows an overview of players in the

power market, the perspective of consumers

and power markets is missing from the

interviews. Although consumers are perhaps

the most important user group in the grid, the

level of organisation is low, certainly for small

household consumers. Because of that, it is hard

to get an overview of their needs. Besides the

lacking views of consumers in general,

interviews were taken of a limited number of

experts from each part of the system. While the

ideas and beliefs about flexibility policy from a

certain type of institution might seem

unambiguous, the experts’ positions are

certainly not directly to be generalised over

their respective fields. Different opinions and

arguments might have been missed. Although

the most important discussions are included,

not all sides of the discussion might have been

heard and represented.

Nevertheless, this paper does contribute to

policy discussions for power system flexibility.

Firstly, a methodological addition with respect

to existing literature is the integration of

phronetic planning principles. Because existing

literature usually either positions itself towards

the matter discussed, or supplies the discussion

with data, it does not always integrate other

values into its discussions, or perceives the

discussion from a perspective of power relations

in the field. Although an unexpected amount of

uniformity was found among the interviewed

experts in many discussions, it has shown the

difficulty of deciding in others. For example, a

consensus was apparent in that the primary

instrument to create flexibility in the market.

However, considerable discussion was apparent

around the subject of nodal pricing or other

locational pricing mechanisms. As mentioned,

this discussion is likely to be determined by the

underlying values of fairness in terms of the

responsible costs-causing party paying the

price on the one hand, and equality in terms of

the socialisation of costs on the other.

Academics have shown support for locational

pricing mechanisms which can be logically

explained considering its economic-theoretical

superiority through its adherence to cost-

causing principles. Policymaking and

consultancy experts have shown to be more

critical about it, because it might be impractical,

or not be effective, but perhaps more

importantly, because it leads to inequalities that

might be politically undesirable.

The methods have shown to be valuable as

it gives an overview rather than discussing

single solutions. Because of that, it shows the

connections between different aspects of the

flexibility challenge. The ‘market and flexibility’

report by CE Delft (Hers et al., 2016) is perhaps

closest to the currently used perspective. The

addition of this paper to these results are

twofold. Firstly, it incorporates more views on

the same flexibility options, such that it shows

counter-arguments. Secondly, the

consideration of foreign policy and its possible

application to the Netherlands, broadens the

view over possible and perhaps impossible

options.

Despite the limitations that were mentioned

about the ability of this paper to position itself

towards the discussed subjects, some issues

were quite clearly indicated by literature and

uniformly agreed upon by the interviewees. Due

to reasons of conciseness, the author refers to

the findings in chapter four to show this paper’s

policy implications.

48

Future research should keep the flexibility

challenge in mind, since many important

challenges still need to arise. While certain

policy options might not have been considered

relevant or useful by the interviewees in the

current situation, increasing shares of VRES and

scarcity of flexibility might change perspectives.

Moreover, new policy options might be

developed, the political situation might shift

towards other values, or new technologies

might reduce flexibility concerns. In all these

and other cases, research should attend to the

needs of the power system and to the

possibilities, arguments and counterarguments

for policy makers.

Besides continuous attention, further and

deeper investigation into many topics discussed

in this paper would be advisable on the short-

term. While, for example, nodal pricing, capacity

markets, and the role of the DSO have been

discussed here, it should be noted that each of

these subjects require a thorough investigation

in themselves. The methodology used here,

applied to specific options would be an

important addition to the existing literature. This

might deal with one of the limitations that were

mentioned, namely that of potentially missing

sides and argumentation. Dedicated Interviews

about such a topic would strongly improve the

completeness of its discussion, and the ability to

make a weighed political decision or agreement

possible. The width of the perspective used her

is this papers’ strength, but it is also its

weakness.

Another possible addition to the literature

would be a stronger focus on the existing power

relations in the electricity sector and to

determine where decisions are made and why.45

Although the Dutch ‘polder’ model of decision

making increases the chances all stakeholders’

positions are considered,46 less powerful parties

might still remain unheard. As has been

45 As an example for work on power structures see the work Energy, Power, Reason: the comprehensive look on

the energy transition (trans.) on power in the German Energy sector (Creutzig & Goldschmidt, 2008).

46 The ‘polder’ model refers to a mode of decision making in which stakeholders are activated in the discussion

about certain policy decisions, as has been the case with the energy agreement in 2013. The negotiation of

such agreements, instead of top-down decisions increase the engagement of all involved parties.

mentioned in the methodology section, the

truth of the powerful parties is often considered

more real, because of which that of others

might be considered fiction.

6. Conclusion An energy transition is clearly present in the

Netherlands, with important stretches of

renewable energy integration until 2030 (as

shown e.g. in figure 2 and figure 7). Besides a

set of other barriers for the adoption of

renewable energy, flexibility of the power

system should be considered a key issue to

large scale rollout of solar and wind power.

Therefore, this paper has set out to investigate

the state of Dutch flexibility policy, the

discussions for adapting it to increasing shares

of variable renewable energy sources and the

positions and arguments within these

discussions.

The flexibility challenge, consisting of the

various dimensions of balancing, energy supply

and congestion, is also under discussion in the

Netherlands, albeit in a relatively mild form.

This, however, does not surprise regarding the

modest impact VRES integration has had until

now. Both the literature and interviews generally

show the Netherlands to be well positioned to

deal with the rise in VRES expected until 2030,

certainly in the dimension of balancing. In some

local grids, congestion is expected to increase,

mainly due to the integration of rooftop PV

units. Energy supply is no issue at all in the

current situation due to overcapacity (see figure

7), but this situation might get less favourable

when power market prices decrease due to

compression and merit-order effects. These

concerns were voiced in the interviews as well,

which found that the combined impacts of

electrification of the heating sector and the

integration of VRES strongly increase seasonal

49

peaks, and, therefore, increases pressure on the

security of supply.

Several discussions have been highlighted

concerning the approach of policy and

regulation addressing demand-side flexibility,

market design, system flexibility and supply-side

flexibility. While some discussions were

characterized by considerable unanimity

among the interviewees, others showed

disagreement among different stakeholders.

Examples of the former are the necessity of

balancing responsibility of aggregators, the

merit of 15-minute prices on the intraday

market, the contracting of flexibility products by

distribution system operators and the

problematic aspects of capacity mechanisms.

Disagreement was found in discussions about

e.g. dynamic electricity prices and grid tariffs for

household consumers, the exact model for

aggregation services, the merit of nodal pricing,

and the merit of further strengthening the

export and import capabilities.

Implicit in the discussion of concrete

flexibility options are several underlying values.

Different positions could be understood better

by understanding differences in values pursued

by policy. Major discussions with implications

for flexibility policy concern the values of cost-

causing principles versus socialisation,

decentralisation versus a centralised power

system, market primacy versus intervention, and

the level of policy making. Although the

position of powerful players in these discussions

partially determine the outcome of discussions

in flexibility policy, each policy proposal and

parties favoured and harmed should be

considered with care. Because of that, this paper

proposed for research to direct continuous and

focussed attention towards the developments

of flexibility in the electricity sector and its policy

options, while taking into consideration its

underlying values, power structures and

interests.

50

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Annex A: Interview questions

1. Algemene vragen

1.1. Uitdagingen

1.1.1. Algemeen: Wat, in het algemeen, zijn volgen u de belangrijkste problemen die

worden veroorzaakt door de integratie van hogere percentages fluctuerende

duurzame energie voor de flexibiliteit van het elektriciteitssysteem

(Netwerkcongestie, balanshandhaving en tekorten en overschotten aan energie)?

1.1.2. Urgentie: In hoeverre is er in Nederland op de korte termijn aandacht nodig voor

de flexibilisering van het elektriciteitssysteem ten behoeve van de integratie van

fluctuerende duurzame energie?

1.1.3. Percentage: Vanaf welk percentage van variabele energiebronnen verwacht u

grootschalige veranderingen moeten worden gemaakt, zowel technisch als

sociaaleconomisch om de leveringszekerheid van het systeem te garanderen?

1.1.4. Paraatheid: In welke mate is Nederland voorbereid en loopt men op schema om de

snelheid van de integratie van fluctuerende energiebronnen bij te houden?

1.1.5. Organisatie specifiek: Welke uitdagingen gelden specifiek voor uw organisatie?

1.1.6. Rollen: Hoe verwacht u dat de rol van uw organisatie en dat van andere actoren in

het systeem zal veranderen tijdens de transitie naar hogere percentages variabele

duurzame energie?

2. Oplossingsrichtingen

2.1. Algemeen

In het literatuuronderzoek zijn een 8-tal richtingen geïdentificeerd met potentie om

flexibiliteit te vergroten of noodzaak voor aanvullende flexibiliteit te verminderen:

• Vraagsturing;

• Slimme distributienetten en verzwaring van het distributienetwerk;

• Versterking en automatisering van het transmissienetwerk, import en export

van elektriciteit;

• Integratie van energieopslag en elektromobiliteit;

• Marktontwerp en de allocatie van kosten voor flexibiliteit;

• Flexibiliteit aan de aanbodkant vergroten en exploiteren;

• Niet-markt gebonden systeemregulering en controle;

• Systeem brede planning optimalisatie en diversificatie;

Welke van deze oplossingsrichtingen zou u voor Nederland prioriteit toekennen

op de korte termijn, welke zouden op de langere termijn richting 2040 een rol gaan

spelen en welke onderdelen zijn minder belangrijk?

58

2.2. Vraagsturing

2.2.1. Dynamische tarieven kleinverbruik: Zijn het toelaten, stimuleren of vereisen van

dynamische tarieven voor kleinverbruik volgens u effectieve maatregelen om het

elektriciteitsverbruik te verplaatsen naar tijdstippen met een groot duurzaam

aanbod en pieken te verkleinen? Verwacht u dat de prijsverschillen die zullen

ontstaan sterk genoeg zijn om als prikkel een regulerend effect te hebben? Wat zijn

de nadelen van dynamische tarieven?

Het wordt in Nederland vanaf 2019 toegestaan om op grote schaal dynamische prijzen (per kwartier) aan

te bieden aan kleinverbruikers. In ander landen, zoals Spanje zijn hier al langer mogelijkheden voor.

Dynamische tarieven zijn volgens sommigen de juiste stimulans om flexibiliteit uit kleinverbruikers te

verkrijgen, het is volgens anderen echter de vraag of kleinverbruikers genoeg prikkel zullen ondervinden

om het zelf balanceren te stimuleren.

2.2.2. Aggregatoren: Denkt u dat aggregatoren zouden kunnen bijdragen aan de

flexibiliteit van het energiesysteem, en wat zou daarvoor moeten gebeuren? Op

welke schaal gebeurt dat al en wat zijn de barrières voor een effectieve inzet van

dergelijke marktpartijen?

Sommige vormen van vraag zouden kunnen worden gebruikt in de onbalansmarkten, maar in de gevallen

van kleinschalig verbruik moet dit kunnen worden opgeschaald door een aggregator om toegang te

krijgen tot deze markten. Het Ministerie van Economische Zaken zegt in de energieagenda te zullen kijken

naar de opties om de weg vrij te maken voor een dergelijke marktpartij.

2.2.3. Integratie met Warmtesector: In Denemarken wordt veel aandacht besteed aan

vraagsturing via de elektrificatie van de warmtevoorziening. Omdat dit een gebied

is waar flexibele consumptie verwacht wordt toe te nemen ligt er potentie om deze

flexibele consumptie in te zetten voor het opvangen van pieken en verminderen van

vraag tijdens lage invoeding van hernieuwbare bronnen. Zou Nederland dezelfde

strategie kunnen en moeten handhaven, en liggen er barrières tussen om dit te

bereiken?

2.2.4. Overig: Welke andere mogelijkheden en barrières ziet u voor Nederland om gebruik

te kunnen maken van de potentie voor vraagsturing?

2.3. Smart-Grids en netwerkverzwaring

2.3.1. Effect van slimme distributienetwerken: In welke mate denk u dat investeringen

in slimme distributienetten ondersteunend zijn voor het oplossen van

flexibiliteitsproblematiek?

59

Hoewel slimme distributienetwerken geen directe besparing opleveren, noch in staat zijn direct flexibiliteit

te leveren, kan een slimmer gebruik van de bestaand netten de randvoorwaarden leveren voor

vraagsturing, dynamisch de maximale netcapaciteit te benutten en te monitoren om congestie te

voorkomen.

2.3.2. Netverzwaring: Bent u het eens met de stelling dat netbeheerders geen andere

opties hebben dan de distributienetten te verzwaren terwijl dit vaak niet de

goedkoopste oplossing is? Zo ja, op welke manier zou dit veranderd kunnen

worden?

Volgens een rapport van de Overlegtafel Energievoorziening (2015) zijn distributienetwerken op sommige

plekken overbelast door grote hoeveelheden lokale zonne-energie.

2.3.3. Congestiemanagment: Bent u het eens met de stelling dat zeer korte pieken in het

netwerk betekenen dat de nadruk om hiermee om te gaan meer zou moeten liggen

op congestiemanagement dan op netverzwaring? Zo ja, wat is er beleidsmatig voor

nodig om congestiemanagment makkelijker mogelijk te maken?

Hoewel de interne congestie in Nederland klein is, wordt verwacht dat de gemiddelde piekbelasting op

het netwerk tot 2023 met gemiddeld ongeveer 6% zal stijgen terwijl de dalen juist dieper worden (Hers et

al., 2016). De korte duur van congestie zou kunnen betekenen dat de nadruk minder zou moeten liggen

op netverzwaring en meer op congestiemanagment.

2.4. Transmissienet verzwaring en import en export

2.4.1. Interne capaciteit: Denkt u dat de strategie om sterkere fysieke verbindingen te

creëren in het interne netwerk van Nederland belangrijk is voor het verminderen van

temporale fluctuaties of belangrijker zal worden bij hoge percentage variabele

duurzame energie in het systeem op de lange termijn?

Het uitbreiden van het gebied waarin gebalanceerd wordt is een manier om fluctuaties van variabele

duurzame energiebronnen te verminderen. Als bijvoorbeeld windkracht over grote gebieden samen wordt

samengenomen zonder enige barrière in het netwerk nemen de pieken en dalen van de totale variabele

opwek af.

2.4.2. Import- en exportcapaciteit: Geldt dit ook voor uitbreiding van de netcapaciteit

met buurlanden, inclusief de versterking van het overzeese netwerk met de

Noordzeelanden?

Denemarken heeft als belangrijke aanvulling op flexibele capaciteit sterke verbinding en marktintegratie

met de Scandinavische Nordpool markt. Doordat zich in deze regio veel flexibele duurzame energie uit

60

waterkracht en opslag in de vorm van gepompte waterkracht kan Denemarken relatief makkelijk omgaan

met fluctuaties.

2.5. Integratie van energieopslag

2.5.1. Rol van energieopslag: Bent u het eens met de stelling dat energieopslag op korte

termijn nog geen belangrijke rol hoeft te spelen? Denkt u dat opslag wel een

belangrijke rol zal gaan spelen en op welke termijn en bij welke percentages

variabele duurzame energie zal dit dan het geval zijn?

Volgens meerdere bronnen is in de huidige situatie opslag van elektriciteit nog niet noodzakelijk en hoeft

daarom nog niet op grote schaal te worden geïmplementeerd. Er zouden veel andere (goedkopere)

flexibiliteitsopties open staan die relatief eenvoudig meer flexibiliteit in de markt zouden kunnen brengen.

2.5.2. Rol beleid voor energieopslag: Als u verwacht dat energieopslag een grote rol

speelt, zal spelen of zou moeten spelen, wat zijn de grootste barrières en wat vindt

u dat beleid en regulering zou moeten doen om dit te verbeteren?

2.5.3. Doelstellingen voor industrie: In Californië worden doelstellingen voor de

elektriciteitsbedrijven uitgesproken voor energieopslag, terwijl het percentage

variabele duurzame energie nog slechts 12% is. Denkt u dat een dergelijke aanpak

zou kunnen helpen om te zorgen dat er op tijd voldoende wordt geïnvesteerd in

energieopslag?

2.5.4. Belasting op opslag: In de energieagenda wordt genoemd dat de overheid

overweegt om dubbele belasting op energie die wordt opgeslagen door derde

partijen weg te nemen. Denkt u dat dit een belangrijke zet zou zijn?

Op dit moment wordt belasting geheven over elektriciteit die wordt afgenomen door een installatie voor

energieopslag, ook als deze de opgenomen elektriciteit later weer in het net voedt.

2.6. Marktontwerp en kostenallocatie voor flexibiliteit

2.6.1. Markttoegang

2.6.1.1. Algemeen: In hoeverre en door welke barrières worden vraagsturing en

variabele energiebronnen volgens u verhinderd om in markten bieden, is het

61

belangrijk dit te veranderen en zo ja, welke beleidsacties zou men moeten

ondernemen om de situatie te verbeteren?

Vraagsturing en variabele duurzame energiebronnen hebben volgens verschillende bronnen

problemen om toegang te krijgen tot de elektriciteitsmarkten. (zie bijv. Van de Vegte, 2015).

2.6.1.2. Onafhankelijke aggregatie: Zou aggregatie onafhankelijk van PV partijen of

energieleveranciers een goede stap zijn om sneller en meer vraagsturing in de

markt te brengen?

In Zwitserland en Frankrijk worden onafhankelijke aggregatie diensten toegestaan, zonder dat

daarvoor een contract nodig is met een leverancier of programmaverantwoordelijke. In Nederland

is dit niet het geval en moeten aggregatoren contractuele relaties aangaan met een PV partij.

2.6.1.3. Productdefinities: Moeten, en zo ja op welke manier, de minimumeisen van

producten op de verschillende markten worden aangepast om verschillende

marktpartijen, en vooral kleinschalige productie en vraag, meer toegang te

verlenen?

Denk hierbij vooral aan verkleining van minimum volume en snelheid die gevraagd worden van

individuele leveranciers (CE Delft & Microeconomix, 2016).

2.6.2. Volledigheid van de markt

2.6.2.1. Algemeen: Zijn er volgens u missende verbanden tussen de korte-

termijnmarkten die door een vervormd prijssignaal voorkomen dat markten

de real-time waarde van elektriciteit laten zien? Zo ja wat zijn mogelijkheden

om sterkere verbanden te leggen tussen de verschillende markten?

Behalve toegangseisen kan ook missende continuïteit in de markt bepaalde actoren weerhouden

om op een weloverwogen manier in de markt te kunnen bieden. Bijvoorbeeld Agora Energiewende

(2016) stelt dat sterkere verbindingen in prijzen tussen de verschillende markten beter laten zien

wat de daadwerkelijke waarde van schaarste is. Voorbeelden van vervormingen in prijzen zijn de

socialisatie van balanskosten en niet geharmoniseerde productlengtes tussen de verschillende

korte-termijnmarkten.

2.6.2.2. Kwartierlijkse producten: Wat vindt u van het voorstel om de productduur

van day-ahead en intra-day markten te verkorten tot kwartierwaarden, wat

zouden de nadelen hiervan zijn?

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2.6.2.3. Balansmarkt: Duitsland stapt voor zijn tertiaire, ofwel reservevermogen, over

op dagelijkse veiling. De Nederlandse markt kent in tegenstelling tot de Duitse

echter ook vrije biedingen in de markt voor reserve-energie, waarbij

onbalansdata kort voor real-time worden gepubliceerd. Denkt u dat een

combinatie van deze regelingen de markt beter bestendig zouden maken voor

de toekomst?

De markten voor reservevermogen worden in Nederland ver van tevoren gesloten. De primaire

regeling wordt wekelijks afgehandeld, regelvermogen en reservevermogen worden jaarlijks

verhandeld. Dit betekent dat actoren lastig inschatting kunnen maken of het interessanter is te

bieden in deze of in andere markten omdat nog niets bekend is over de marktprijzen op deze korte

termijn. Vrij biedingen met data over de onbalans vlak voor real-time maken ‘passieve’ bijdragen

aan het oplossen van de onbalans mogelijk.

2.6.2.4. Intraday veilingen: Denkt u dat intraday veilingen een belangrijke aanvulling

zou kunnen zijn op de huidige standaard van continue intraday markten? Wat

zouden de nadelen zijn van een dergelijke aanvullende markt in de APX?

Vanuit onderzoek wordt aangegeven dat ter aanvulling van de continue intraday markten, discrete

veilingen meer mogelijkheden bieden geven voor partijen om te bieden op de intraday markt en

daarmee het volume dat kort voor real-time wordt verhandeld zal vergroten. Door een preciezere

inschatting zou dit betere mogelijkheden geven te reageren op fluctuaties. (Zie bijv. Neuhoff et

al., 2016). Duitsland kent sinds eind 2014 dergelijke kwartierlijkse veilingen naast de continue

markt.

2.6.3. Marktparticipatie

2.6.3.1. SDE+: Denkt u dat het huidige stimuleringsmodel de juiste is om te zorgen

dat gesubsidieerde duurzame energiebronnen onderhevig zijn aan

marktcondities en dus voldoende prijsprikkels ontvangen om de door hen

mogelijk geleverde flexibiliteit te benutten?

Nederland heeft, in tegenstelling tot veel andere landen, al langer ervaring met een meer op de

markt gebaseerd model voor het bevorderen van duurzame energie met de SDE+. De meeste

andere landen hebben langer vastgehouden aan vaste ‘Feed-in Tariffs’. In dit model zijn

producenten van elektriciteit onderhevig aan marktprijzen, wat niet het geval is bij vaste

tarieven.

2.6.3.2. Saldering: Bent u het eens met de kritiek op de salderingsregeling voor

kleinverbruikers dat het slecht is voor de systeembalans? Denkt u dat bij een

afschaffing een alternatieve stimuleringsregeling nodig is, en hoe zou deze

eruit kunnen zien zonder over hetzelfde struikelblok te vallen?

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In Nederland kennen we een salderingsregeling voor kleinverbruik, die ten minste tot 2020 zal

blijven bestaan. Behalve een effectieve stimuleringsmaatregel, wordt de salderingsregeling voor

kleinverbruikers ook gezien als problematisch voor de systeembalans, omdat de producenten

betaald worden voor elke geleverde kWh, op welk uur van de dag dan ook, onafhankelijk van

schaarste.

2.6.4. Marktverbinding met buurlanden

2.6.4.1. XBID: Verwacht u dat het XBID-project grote veranderingen met zich mee zal

brengen voor de Nederlandse Intra-Day markt en dat het daardoor zal leiden

tot een kleinere behoefte aan reservecapaciteit en daarom lagere totale kosten

voor balanshandhaving? Wat verwacht u voor eventuele problemen in deze

ontwikkeling?

Vanaf dit jaar wordt naar verwachting marktkoppeling van de intraday market in een

gemeenschappelijke Europese markt bewerkstelligd met het zogenaamde Cross-Border Intra-Day

ofwel XBID project. Naast het koppelen van de continue intraday markten heeft het als doel om

impliciet netwerkallocatie mee te nemen voor de netcapaciteit over de grens.

2.6.4.2. Internationale samenwerking: In welke mate is volgen u internationale

samenwerking, coördinatie en harmonisatie van belang voor beter verbonden

markten en fysieke verbindingen in de regio? Wat zou internationale net- en

marktintegratie kunnen versnellen op beleidsvlakken

2.6.5. Marktrepresentatie van netcondities

2.6.5.1. Nodal pricing: Denkt u dat nodal pricing een goede manier is om kosten voor

netwerkgebruik bij de juiste actoren te leggen en denkt u dat een dergelijk

systeem positieve effecten zou hebben binnen de Nederlandse markt? Denkt

u dat een dergelijk systeem in te passen zou kunnen zijn in het Nederlandse

markt gebaseerde systeem?

Nodal pricing, of Locational Marginal Pricing, is de standaard in een aantal Amerikaanse staten

en verscheidene andere regio’s. Deze methode wordt ook regelmatig door onderzoek aangedragen

als een goede manier om de kosten van het gebruik van het netwerk bij de juiste actoren te leggen

en als prikkel voor flexibele invoeding en verbruik, afhankelijk van de locatie.

2.6.5.2. FTR: Denkt u dat bij een eventuele verschuiving naar nodale prijzen, een FTR-

systeem voldoende tegen risico’s van prijsfluctuaties zouden kunnen

beschermen, en onder welke voorwaarden zou dat kunnen helpen voor de

investeringszekerheid?

64

Bij een eventuele verschuiving naar een nodaal prijssysteem voor elektriciteit worden Financiële

transmissierechten (FTR’s) aangedragen als oplossing om te voorkomen dat individuele actoren er

sterk op achteruitgaan en dat risico’s verminderd worden (Zie bijv. Kunz et al., 2016).

2.7. Flexibiliteit uit de aanbodzijde

2.7.1. Stimuleren netvriendelijk ontwerp: Denkt u dat het mogelijk is de SDE+ zo aan te

passen dat het een bijdrage zou kunnen leveren aan een stimulering van

systeemvriendelijke turbines en zonnesystemen, door niet alleen ingevoede

elektriciteit, maar ook andere aspecten mee te nemen?

In de SDE+ wordt een bepaald aantal jaar, een maximale hoeveelheid energie gesubsidieerd aan de hand

van de verwachte aantal vollasturen. In Denemarken is de hoeveelheid subsidiabele energie voor

windkracht afhankelijk van zowel de capaciteit van de generator als van de grootte van het oppervlak

van de wieken. Dit is zo geformuleerd om te voorkomen dat een prijsprikkel ontstaat om in windturbines

te investeren met relatief grote capaciteit die slechter zijn voor het systeem omdat het grotere pieken

heeft.

2.7.2. Duurzame flexibele bronnen: Denk u dat biomassa of eventueel andere flexibele

duurzame energiebronnen als een belangrijk deel van de oplossing zouden kunnen

in een scenario met zeer lage uitstoot in de elektriciteitssector rond 2050? Zo ja, hoe

zou deze technologie gestimuleerd moeten worden in de markt te blijven?

In een zeer vergevorderd stadium van de energietransitie blijft er waarschijnlijk weinig ruimte over voor

de flexibiliteit uit fossiele energiebronnen. Als een energy-only markt met lage elektriciteitsprijzen

gecombineerd wordt met hoge prijzen voor de uitstoot van CO2., zou de business case voor bijvoorbeeld

gascentrales aanzienlijk zijn verslechterd. Mogelijkerwijs is er wel ruimte voor technologieën met weinig

tot geen uitstoot.

2.7.3. Aggregatie: Zit aan de aggregatie van gedistribueerde energiebronnen nog

aanvullende uitdagingen vergeleken met de aggregatie van vraagzijde sturing?

Zoals besproken bij vraagsturing zouden aggregatoren meer ruimte kunnen krijgen om diensten te

leveren, zodat de door kleinverbruikers verbruikte elektriciteit kan worden ingezet op de balansmarkten.

Dit soort organisaties zouden gelijktijdig elektriciteit uit gedistribueerde bronnen kunnen verkopen op de

elektriciteitsmarkten, zoals de elektriciteit uit kleinschalige zon-pv installaties.

2.7.4. Capaciteitsmarkt of -reserves: Ziet u op de middellange termijn een noodzaak

voor een capaciteitsmechanisme, ofwel een capaciteitsmarkt ofwel een

capaciteitsreserve? Op welke manier zouden criteria in een dergelijk systeem de

flexibiliteit van de extra capaciteit kunnen garanderen?

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In Duitsland wordt in een capaciteitsreserve gehanteerd die opereert buiten de markt om voldoende

capaciteit te garanderen.

2.8. Systeemregulering en controle

2.8.1. Netwerkcode: Denkt u dat het maken van een onderscheid tussen technologieën

in de netwerkcode zou kunnen bijdragen aan de participatie en hun bijdrage aan de

flexibiliteit in het systeem?

In enkele landen, bijvoorbeeld Denemarken en Ierland, zijn meerdere netcodes gedefinieerd voor

verschillende technologieën. Entso-E meent echter dat een enkele netwerkcode de gelijke behandeling van

technologieën bevordert en bijdraagt aan de eenvoud van regulering. Een ander perspectief is echter dat

gelijke behandeling voor verschillende technologieën niet leidt tot een gelijk speelveld.

2.8.2. FRAC-MOO: Denkt u dat naar het ISO-model eisen en verplichtingen gesteld

kunnen worden vanuit overheidsbeleid of regulering aan het generator portfolio van

energiebedrijven en aan het aanbieden van hun flexibele bronnen?

De Californische Independent System Operator (ISO), in tegenstelling tot netbeheerders in Europa,

vereisen een bepaalde flexibiliteit in het portfolio van de generatoren en lokale netbeheerders en deze ook

daadwerkelijk in de markt aan te bieden (FRAC-MOO: Flexible Resource Adequacy criteria en Must-Offer

Obligations). In tegenstelling tot het hier gebruikte model van het toedienen van prikkels in de markt,

worden onder dat systeem vaker verplichtingen opgesteld.

2.9. Systeem brede planning optimalisatie en diversificatie

2.9.1. Holistische planning: Denkt u dat het meenemen van de interactie tussen

verschillende technologieën in overheidsbeleid een belangrijke strategie zou kunnen

zijn in Nederland, waar nu vooral een voorkeur is voor een ‘technologie neutrale’

aanpak? Op welke manier zou dit te operationaliseren zijn?

In Californië wordt gestuurd richting een portfolio van energiebronnen die zo goed als mogelijk

overeenkomt met de vraag. Dit betekend dat de interactie tussen verschillende bronnen wordt

meegenomen in de regulering, zodat een zo efficiënt mogelijk portfolio wordt opgebouwd. Men kan

bijvoorbeeld in bestaande stimuleringsmaatregelen meenemen welke technologieën op dat moment

zorgen voor zo min mogelijk extra flexibiliteitsbehoefte en deze voordelen geven boven andere.

3. Afsluiting:

3.1. Inhoudelijk: Ziet u nog aanvullende problemen, concrete of generieke oplossingen die nog

niet zijn besproken?

3.2. Feedback: Heeft u nog op- of aanmerkingen over dit interview, zowel inhoudelijk als over

de vorm?

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Annex B: list of interviewees

# Institution type Institution name Interviewee names

1 Research institute Energieonderzoek Centrum Nederland

(ECN)

Adriaan van der Welle

Jos Sijm

2 TSO TenneT Samuel Glismann

Frank Wiersma

3 Regulation Authoriteit Consument & Markt (ACM) Jeroen de Joode

Wieger Wiersema

Kick Bruin

4 Consultancy Ecofys Timme van Melle

5 Academia/ Research University of Amsterdam/ TNO Annelies Huygen

6 Research Clingendael International Energy

Programme (CIEP)

Jacques de Jong

Diederik Klip

7 Energy Company Vattenfall David Plomp

Martijn van Gemert

8 Consultancy CE Delft Sebastiaan Hers

9 Academia Rijksuniversiteit Groningen (RUG) Machiel Mulder

10 Policy making Ministerie van Economische zaken (EZ) Jan Luuk de Ridder

11 DSO Alliander Martijn Bongaerts