RESEARCH OF SCENARIOS FOR
COAL-FIRED POWER PLANTS IN
THE NETHERLANDS
A Report for the Ministry of Economic Affairs
(MinEZ)
01 July 2016

Frontier Economics Ltd is a member of the Frontier Economics network, which consists of two separate companies based in Europe (Frontier
Economics Ltd, with offices in Brussels, Cologne, Dublin, London & Madrid) and Australia (Frontier Economics Pty Ltd, with offices in Melbourne
& Sydney). Both companies are independently owned, and legal commitments entered into by one company do not impose any obligations on
the other company in the network. All views expressed in this document are the views of Frontier Economics Ltd.

RESEARCH OF SCENARIOS FOR COAL-FIRED POWER
PLANTS IN THE NETHERLANDS

CONTENTS
Executive Summary

7

Summary

10

1

Introduction

18

1.1
1.2
1.3

18
19
21

2

3

4

Background of the Project
Approach of our analysis
Structure of the report

Power market modelling

22

2.1
2.2
2.3
2.4

22
23
25
26

Model description
Definition of the Reference Case
Modelling of Dutch coal-fired power plants
Key results of the Reference Case

Policy measures and scenarios

30

3.1
3.2
3.3

30
32
34

Additional abatement measures at the plants
Pentalateral collaboration
Early closure of coal-fired power plants

Indicator based assessment

36

4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8

36
38
47
54
57
64
68
70

Summary
Impact on carbon dioxide emissions
System costs and specific abatement costs
Impact on power prices
Impact on consumers
Security of Supply and import dependency
Impact on the development of RES-E
Other indicators

ANNEX A Reference Case assumptions

77

ANNEX B Reference Case Results

91

ANNEX C Detailed results of the policy scenarios

110

ANNEX D Model description

138

ANNEX E List of references

141

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Figures
Figure 1.
Figure 2.
Figure 3.
Figure 4.
Figure 5.
Figure 6.

Impact on CO2 emissions (cumulated 2018-2049)
12
Impact on system costs and specific abatement costs
14
Approach of the study
19
Power market model
22
Assumed CO2 price development
25
Development of electricity supply in The Netherlands (Reference
Case)
27
Figure 7. Power sector CO2 emission NL
28
Figure 8. CO2 emissions in the Reference Case (CWE and neighbouring
countries)
29
Figure 9. Carbon Price Floor (Scenario 2)
33
Figure 10. Domestic and net-reduction of CO2 emissions
44
Figure 11. CO2 emissions (NL) in 2040
46
Figure 12. Impact on system costs (NL)
50
Figure 13. Specific emission abatement costs EUR(real, 2015)/tCO2
54
Figure 14. Impact on power prices (NL)
55
Figure 15. Assumed consumption profiles
59
Figure 16. System costs vs. consumer payments
60
Figure 17. Impact on electricity payments of final consumers (households) 62
Figure 18. Impact on electricity payments of final consumers (“business and
industrial consumers”)
62
Figure 19. Comparison of operational capacities (NL, de-rated*)
66
Figure 20. Net-imports (NL)
67
Figure 21. Renewable energy share of net-demand
69
Figure 22. Emission factors of coal plants in the Netherlands
71
Figure 23. Impact on other emissions
74
Figure 24. Fuel price development (Reference Case)
78
Figure 25. Assumed CO2 price development
79
Figure 26. Development of net-power demand
80
Figure 27. Installed generation capacity (NL, 2015)
82
Figure 28. Assumed development of central and de-central CHP “must-run”
generation
85
Figure 29. Development of RES-E in The Netherlands
88
Figure 30. RES-E in the model-region
89
Figure 31. Assumed development of interconnection capacity (NL)
90
Figure 32. Development of operational capacities NL (Reference Case)
93
Figure 33. Development of electricity supply in The Netherlands (Reference
Case)
94
Figure 34. Imports/Exports NL (Reference Case)
103
Figure 35. Power sector CO2 emission NL
104
Figure 36. CO2 emissions in the Reference Case (CWE and neighbouring
countries)
105
Figure 37. Wholesale price development in The Netherlands (Reference
Case)
106
Figure 38. Price duration curve NL (Reference Case)
107
Figure 39. Comparison of base prices CWE (Reference Case) 2018 – 2040 108
Figure 40. Development of base prices in selected countries
109
Figure 41. Impact on the Dutch electricity supply (Scenario 1a)
111

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Figure 42. Impact on electricity supply (model-region) (Scenario 1a)
Figure 43. Imports/ Exports of power (NL) Scenario 1a
Figure 44. Impact on the Dutch electricity supply (Scenario 1b)
Figure 45. Impact on electricity supply (model-region) (Scenario 1b)
Figure 46. Imports/ Exports of power (NL) Scenario 1b
Figure 47. Impact on the Dutch electricity supply (Scenario 2)
Figure 48. Impact on electricity supply (model-region) (Scenario 2)
Figure 49. Imports/ Exports of power (NL) Scenario 2
Figure 50. Impact on the Dutch electricity supply (Scenario 3a)
Figure 51. Impact on electricity supply (model-region) (Scenario 3a)
Figure 52. Imports/ Exports of power (NL) Scenario 3a
Figure 53. Impact on the Dutch electricity supply (Scenario 3b)
Figure 54. Impact on electricity supply (model-region) (Scenario 3b)
Figure 55. Imports/ Exports of power (NL) Scenario 3b
Figure 56. Impact on the Dutch electricity supply (Scenario 3c)
Figure 57. Impact on electricity supply (model-region) (Scenario 3c)
Figure 58. Imports/ Exports of power (NL) Scenario 3c
Figure 59. Impact on the Dutch electricity supply (Scenario 3d)
Figure 60. Impact on electricity supply (model-region) (Scenario 3d)
Figure 61. Imports/ Exports of power (NL) Scenario 3d
Figure 62. Impact on the Dutch electricity supply (Scenario 3e)
Figure 63. Impact on electricity supply (model-region) (Scenario 3e)
Figure 64. Imports/ Exports of power (NL) Scenario 3e
Figure 65. Impact on the Dutch electricity supply (Scenario 3f)
Figure 66. Impact on electricity supply (model-region) (Scenario 3f)
Figure 67. Imports/ Exports of power (NL) Scenario 3f
Figure 68. Geographical scope of the model

112
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
136
137
139

Tables
Table 1.
Table 2.
Table 3.
Table 4.
Table 5.
Table 6.
Table 7.
Table 8.
Table 9.
Table 10.
Table 11.
Table 12.
Table 13.
Table 14.
Table 15.
Table 16.
Table 17.
Table 18.
Table 19.
Table 20.

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Coal-fired power plants in The Netherlands
26
Assumed closure dates (Scenario 3)
35
Indicator based assessment - Summary
37
Domestic emission reduction (NL)
41
Net emission reduction (model region)
45
Differences of annual CO2 emissions in 2040 (NL)
46
Impact on system costs in The Netherlands
50
Impact of policy measures on EU system costs*
52
Wholesale prices of electricity in The Netherlands
56
Impact on wholesale power prices in Germany
57
Impact on yearly costs to consumers (households)
63
Impact on yearly costs to consumers (other consumers)
63
Net-imports (NL) – difference to the Reference Case
68
Development of net-electricity supply from RES-E
70
Calculation of other emissions
72
Net power demand (model-region)
81
Investment options (conventional thermal and storage)
83
De-rating factors
86
Levelised costs of electricity (RES-E)
88
Reference Case: Operational capacities and electricity supply by

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Table 21.
Table 22.
Table 23.
Table 24.
Table 25.
Table 26.
Table 27.

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fuel type (The Netherlands)
95
Reference Case: Operational capacities and electricity supply by
fuel type (Germany)
96
Reference Case: Operational capacities and electricity supply by
fuel type (Belgium)
97
Reference Case: Operational capacities and electricity supply by
fuel type (Austria)
98
Reference Case: Operational capacities and electricity supply by
fuel type (France)
99
Reference Case: Operational capacities and electricity supply by
fuel type (Great Britain)
100
Reference Case: Operational capacities and electricity supply by
fuel type (Denmark)
101
Net-imports in other countries (Reference Case)
103

RESEARCH OF SCENARIOS FOR COAL-FIRED POWER
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EXECUTIVE SUMMARY
The Netherlands has committed itself to reaching a low-carbon energy system
that is reliable, affordable and safe in 2050. Within this context, the Dutch Energy
Agreement represents an irreversible step towards achieving this goal. As part of
the Energy Agreement, two of seven remaining coal-fired power stations that are
currently operational in The Netherlands will be closed mid-2017. On 26
November 2015, the second chamber of the Dutch Parliament has accepted a
motion that asks the Minister of Economic Affairs to develop a plan to phase-out
coal-fired electricity generation in The Netherlands.
In response to this request, the Ministry of Economic Affairs (MinEZ) has asked
Frontier to model several climate policy scenarios in the power sector and to
evaluate these scenarios based on a given set of indicators:
□ Scenario 1: Additional emission reduction at coal plants – Operators
implement additional CO2 abatement measures at the coal-fired power
plants from 2025 (co-firing of biomass, additional CCS, additional heat
production).
□ Scenario 2: Regional collaboration – Coordinated approach in The
Netherlands and neighbouring countries to achieve additional CO2
reductions in the power sector, modelled as a regional Carbon Floor Price
of at least 30 € per tonne CO2 emitted in the region.
□ Scenario 3: Early closure of coal-fired power plants – Early closure of
coal-fired power plants in the Netherlands from 2020 or later.
The results of the analysis can be summarised as follows:
 The effectiveness of additional national climate policy measures to achieve
additional CO2 reduction in the power sector is strongly dependent on the
level of displacement of power production from the Netherlands to other
countries. National policy measures will reduce emissions in The
Netherlands, but at the same time, emissions in neighbouring countries will
increase due to the high level of interconnections in the Central-Western
European power market. For example, the closure of all coal-fired power
plants in 2020 would lead to a substantial CO2 emission reduction in the
Netherlands (320 mn. tCO2 from 2018 to 2049 in total). However, a large
proportion of the domestic reduction would be offset by increased emissions
abroad. Closure of the two coal plants built in the 1990’s similarly leads to
national emission reduction (approx. 4 mn. tCO2 in 2020 and 63 mn. tCO2
from 2018 – 2049) which is offset for a large part by increased emissions
abroad. Closure of the two coal plants built in the 1990’s in combination with
additional abatement measures at the remaining plants leads to both higher
national emission reduction (209 mn. tCO2 from 2018 to 2049) as well as less
carbon leakage.
 Additional CO2 emission reduction differs significantly between the
analysed national/regional policy measures. A climate policy approach
coordinated with neighbouring countries yields the largest emission reduction
(400 mn. tCO2 from 2018-2049) in the Central-Western European power

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RESEARCH OF SCENARIOS FOR COAL-FIRED POWER
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market. Early closure of all coal-fired power plants leads to the highest CO2
emission reduction in the Netherlands (320 mn. tCO2 from 2018-2049), but
this measure is at the same time associated with the highest level of carbon
leakage to other countries (see above). Additional CO2 abatement at all coalfired power stations yields moderate CO2 reduction compared to the other
scenarios (180 mn. tCO2 from 2018-2049), but has at the same time the least
impact on the power generation in other countries and leads to only little
carbon leakage.
 The effectiveness of additional national climate measures is furthermore
dependent on the interaction with the EU ETS. Since the CO2 emissions in
the EU ETS are capped at a fixed amount, any national climate policy
measure in the power sector only targeting national/regional CO2 emissions
will lead to higher emissions in other regions and sectors. Therefore, any
additional national or regional climate policy measure in the power sector
requires additional action in the EU ETS to ensure that the CO2 abatement
that has been achieved translates into real emission reduction in the EU
emission trading system (e.g. by reducing the cap for CO2 emission in the EU
ETS or by “buying and burning” CO2 certificates). These actions are
associated with additional costs.
 At the same time, the analysed policy measures lead to different impacts on
the costs of the electricity supply and costs to final consumers. While
measures that have only limited effects on the operation of power plants (i.e.
the implementation of additional abatement measures at the plants) also have
a moderate impact on system costs (+ 1.4 - 2.1 bn. EUR NPV 2018-2049)
and on costs to final consumers (+ 0.3 bn. EUR NPV 2018-2049), more
structural changes to the system (i.e. early closure of all coal-fired power
plants or a Carbon Floor Price in Central-Western Europe) significantly
increase the costs of the electricity supply system (e.g. + 7.1 bn. EUR NPV
2018-2049 in the case of an early closure of all coal plants in 2020) and the
consumer payments (e.g. + 3.5 bn. NPV 2018-2049 in the same case).
Closure of the two coal plants built in the 1990’s has limited effects on both
system costs (+ 1.1 bn. EUR NPV 2018 – 2049) as well as consumer
payments (+ 0.7 bn. EUR NPV 2018 – 2049)
 The direct impact on power generation from Renewable Energies (RES-E) is
strongly linked to the impact on biomass co-firing: Whereas biomass co-firing
can be expected to increase if power plant operators implement additional
CO2 abatement measures at the coal plants, biomass co-firing is reduced if
coal-fired power plants close before 2030. The indirect impact of the
scenarios on RES-E power production (e.g. due to the impact on power
prices) is limited.
 The impact of the policy measures on other indicators such as innovation
and employment is expected to be moderate. In the scenarios, no real risks to
the Security of Supply in The Netherlands were observed. Nevertheless, a
closure of a major part of the power plants in the Netherlands under short
notice (e.g. notification of less than 2-3 years before implementation) should
be avoided in order to allow market participants to react to the new market
situation e.g. by reactivating gas-fired power plants.

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RESEARCH OF SCENARIOS FOR COAL-FIRED POWER
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 Regarding heat supply, early closure of plants would require a replacement of
current heat production. The impact on other emissions (NOx, SO2, PM, Hg)
inside the Netherlands and abroad depends highly on specifics of the affected
power plants (including plants substituting power generation from the coalfired power plants such as gas plants and power plants abroad) and other
factors (such as fuel specifics) and should be investigated further.

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SUMMARY
Background
The Netherlands has committed itself to reaching a low-carbon energy system
that is reliable, affordable and safe in 2050. Within this context, the Dutch Energy
Agreement represents an irreversible step towards achieving this goal. As part of
the Energy Agreement, two of seven remaining coal-fired power stations that are
currently operational in The Netherlands will be closed mid-2017. On 26
November 2015, the second chamber of the Dutch Parliament has accepted a
motion that asks the minister of Economic Affairs to develop a plan to phase-out
coal-fired electricity generation in The Netherlands. In response to this request,
the Ministry of Economic Affairs (MinEZ) has asked Frontier to model several
scenarios with our European power market simulation model and to evaluate
these scenarios based on the given set of indicators.

Policy Scenarios
MinEZ has developed the outline for three main scenarios (and a number of subscenarios), each representing one policy measure addressing the future of coalfired power generation in the Netherlands:
 Scenario 1: Additional emission reduction at coal plants – In this scenario
the coal plants apply possible measures after 2025 to reduce the CO2
emission per unit of delivered electricity to such a level that the emissions are
at least equal to the average CO2 emissions of a modern gas-fired power
plant.
 Scenario 2: Pentalateral collaboration – This scenario represents a
situation in which a common approach in the Pentalateral Forum1 is taken to
achieve additional CO2 reduction. It is assumed that the countries of the
Pentalateral Forum agree on CO2 reduction targets that go beyond the targets
agreed on a European level. These additional targets lead to additional
incentives to lower the emission of carbon dioxide.
 Scenario 3: Early closure of coal-fired power plants – In the third
scenario, coal-fired power plants in the Netherlands are required to shut-down
at specific dates. These dates have been set prior to the expected technical
lifetime of the coal-plants. For scenarios with closures after 2025, it is further
assumed that additional abatements measures will be taken from 2025 that
limit emissions of these coal plants to that of a modern gas plant (same as
scenario 1). Specific sub-scenarios have also been included in which only the
two coal-fired power plants built in the 1990’s are closed in 2020.
The scenarios described above are evaluated using a European power market
model and assessed against a Reference Case reflecting current policies.

1

The Pentalateral Energy Forum represents a framework for regional cooperation toward the improvement of
electricity markets integration and Security of Supply. It consists of Netherlands, Germany, France, Belgium,
Luxembourg, Austria and Switzerland.

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Indicator-based assessment
The Ministry of Economic Affairs defined a set of indicators to be used to
evaluate the different policy measures. The indicators are based on the variables
set out in the Letter of 18 December 2015 of the Minister of Economic Affairs to
the Dutch Parliament:
□ CO2 emissions in the Netherlands;
□ Carbon-leakage of CO2 abroad (in the power sector);
□ Security of Supply;
□ Import dependency;
□ Prices of energy for businesses and households; and
□ The potential for the production of renewable energy.
□ The growth of heat networks;
□ Impact on innovation; and
□ Impact on other emissions.
In the following, we summarise our main findings regarding the impact of the
different policy scenarios on the above mentioned indicators.

Reduction of CO2 emissions
The emission reduction in the Reference Case reflects the assumed
development of CO2 prices (up to over 50 EUR (real, 2015)/tCO2 in 2050 and 80
EUR (real, 2015)/tCO2 in 2050) as well as the growth of renewable energy
sources. In the Reference Case, emissions of carbon dioxide in the power sector
in Central-Western Europe decrease by ca. 67% from 2015 to 2040. CO2
emissions in the power sector in The Netherlands decrease by 20% (-10 mn.
tCO2) from 2015 until 2030 and by 50% until 2040 (-27 mn.tCO2).
The policy scenarios all result in higher CO2 reduction in the medium term, up to
55% reduction (- 28 mn. tCO2) from 2015 until 2030, compared to the Reference
Case. In the long-run (2040), the CO2 emissions in the policy scenarios are
similar to the Reference Case due to the already achieved emission reduction
through closure of older coal plants until 2035 (due to reaching end of lifetime)
and market based co-firing of biomass in 2040.
The different policy measures assessed in this study exhibit different degrees of
emission reductions in The Netherlands and in Europe:
 Aggregated from 2018 to 2040, the closure of all coal plants results in the
highest emission reduction in The Netherlands (closure until 2020 reduces
domestic emission by 320 mn. tCO2, 30%). The majority of this reduction,
however, is substituted by emissions in neighbouring countries due to higher
imports to The Netherlands. Due to this substitution, net-reduction on a
European level amounts to just 87 mn. tCO2. If the two plants built in the
1990’s are closed in 2020 (and the other plants remain in the market), CO2
reduction in the Netherlands amount to of 63 mn. tCO2, but only 11 mn. tCO2
in all modelled countries, meaning more than 80% of emissions are

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RESEARCH OF SCENARIOS FOR COAL-FIRED POWER
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“exported” to other countries. In 2020, closure of these plants results in a
reduction of 4 mn. tCO2.
 If additional abatement measures, e.g. more co-firing of biomass, additional
heat decoupling or CCS, are implemented at the coal plants (instead of plant
closures), the aggregated emission reduction in the Netherlands is lower than
in the case of plant closures (up -180 mn. tCO2 from 2018-2049), but at the
same time the leakage of emissions to other countries is significantly reduced.
The need to import power from other countries is lower and CO2 emissions in
other countries are therefore affected to a lower degree. The net-reduction
that is achieved in this scenario on a European level is around 160 mn. tCO2.
 The highest emission reduction on a European level is achieved by the
introduction of a Carbon Price Floor in 2018 in the countries of the
Pentalateral Forum. The reason for this is that a larger share of the European
electricity supply is impacted by the measure. The net-reduction that is
achieved on a European level is 401 mn. tCO2 in the period from 2018 to
2049. In The Netherlands, this measure leads to limited additional CO2reduction, due to the relatively lower emission intensity of the power plant
park in the Netherlands, which remains competitive even with significantly
higher CO2 prices.
Figure 1.

0

Impact on CO2 emissions (cumulated 2018-2049)
Additional Additional
abatement abatement
Closure of Closure of
measures measures
Closure of Closure of Closure of Closure of
Carbon
two oldest two oldest
in 2025
in 2025
all plants all plants all plants all plants
Price Floor
plants until plants until
(costs
(costs
until 2020 until 2025 until 2030* until 2040*
2020*
2020
borne by
borne by
companies)
state)

0%

-50

-5%

-5%

-6%
-0.6%

-0.6%

-100

-0.8%

-0.8%

-0.9%

-10%

-1.0%

-1.1%

-150

-15%

mn. tCO2 (2018-2049)

-15%

-200

-17%
-18%
-19%

-250

-20%

-23%
-24%

-25%

-300
-30%

-30%

-350

-35%

-400

% difference compared to Reference Case

-0.1%

-2.9%

-450

-40%
Domestic reduction NL

Net-reduction

Source: Frontier
Note:

* additional abatement measures are implemented at the coal plants in 2025

However, it is important to note that in all scenarios the additional national CO 2
abatement takes place in the context of the EU ETS. In our power market
simulation, the effects of the policy measures on imports and exports of electricity
from and to The Netherlands are captured. The import/export of CO 2 emissions
due to the changes in the electricity trading pattern are therefore captured in the
model, too. However, beyond this impact on electricity trade, the EU ETS itself is

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RESEARCH OF SCENARIOS FOR COAL-FIRED POWER
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affected by the additional national policy measures: since the demand for CO2
certificates decreases due to additional national CO2 abatement measures in the
power sector, the price of EU allowances ceteris paribus can be expected to
decrease. This price effect induces additional CO2 emissions in other countries or
sectors. That means that regardless of national CO2 abatement measures, the
total amount of CO2 emissions in the EU ETS remains constant as long as the
total amount of CO2 certificates remains constant.2 This indirect effect is not
captured in the model, but should be taken into account in the assessment of the
scenarios.
The indirect effect of the measures on the EU ETS can be mitigated if the amount
of additional national CO2 emission reduction is in some way reflected in the
overall supply of CO2 allowances (e.g. through lower auctioning volumes or
reducing the yearly cap on emissions in the EU ETS). Such a reduction of CO2
certificates would lead to additional costs e.g. by holding back a certain amount
of CO2 certificates by the states or by buying back allowances from the CO 2
market.

System costs and distributional effects
The impact of the different policy measures on the affordability of electricity
supply is reflected in two ways: the costs of the electricity system and the
payments of final consumers:
 From a system cost perspective, the introduction of a Carbon Price Floor is
the most cost-efficient solution in The Netherlands if costs associated with
higher CO2 prices are not taken into account. In this scenario specific
abatement costs are 5 EUR/tCO2, while the total impact on system costs
amounts to 300 mn. EUR (NPV 2018-2049)).3 If the higher CO2 prices are
included, system costs increase by 4.2 bn. EUR (NPV, 2018-2049) compared
to the Reference Case. In any case, the introduction of a Carbon Floor Price
has a significant impact on power prices and consequently on the payments
of final consumers due to the high increase of power prices. Consumer
payments increase by up to 10% or 8.5 bn. EUR (NPV 2018-2049).
 The implementation of additional abatement measures at the plants increases
system costs slightly (+1.4 - 2.1 bn. EUR), but has limited impact on
consumer payments as the costs of the additional measures are either borne
by the companies or by the state (0.1 - 0.2 bn. EUR, 0.2%). The specific
abatement costs of these scenarios are the lowest of the scenarios with
purely national measures.
 Closure of the coal plants leads to an increase of system costs of 7 bn. EUR
(NPV 2018-2049) if plants close until 2020 and of consumer payments due to
higher power prices (3.5 bn. EUR, NPV 2018-2049; +2.8%). Due to the low
level of net CO2 reduction that is achieved in all modelled countries with this
scenario, specific abatement costs of this scenario from a European
2

Not taking into account the effects of the Market Stability Reserve (MSR), that reduces the auctioning
volumes by a certain amount if unallocated allowances exceed a threshold. If the allowances transferred to
the MSR are brought back to the market at a later point in time, the impact on emission and prices is only
temporary.

3

The CO2 price increase corresponds to higher state-income and is not a “cost” in the narrow sense.

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RESEARCH OF SCENARIOS FOR COAL-FIRED POWER
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perspective are higher: 91 EUR (real, 2015)/tCO2. With later closure, the
impact on costs and payments decreases and the specific abatement costs
improve. Of all scenarios with fixed closure dates, the system costs are lowest
when only the two plants built in the 1990’s are closed. Specific abatement
costs of this scenario are 27 EUR (real, 2015)/tCO2 from the perspective of
The Netherlands and 119 EUR(real,2015)/tCO2 from a European perspective.
Figure 2.

Impact on system costs and specific abatement costs
Specific abatement costs of policy measures
(EUR/tCO2)

Impact on system costs (bn. EUR)

Domestic abatement costs (EUR/tCO2)
Net EU abatement costs (EUR/tCO2)

bn. EUR (NPV 2018-2049, real 2015)
Additional abatement measures
(costs borne by companies)
Additional abatement measures
(costs borne by state)
Carbon Price Floor

8

1.4
2.1

5

0.3

23
73

4.2

Carbon Price Floor*

22

7.1

Closure of all plants until 2020

4.2

Closure of all plants until 2025
Closure of all plants until 2030
(+additional measures)

4.5

Closure of all plants until 2040
(+additional measures)

3.1

Closure of two oldest plants until
2020 (+additional measures)
Closure of two oldest plants until
2020

19
13
19

2.1
1.1

91

16

73

19
16
10

90

45

28
28
27

119

Source: Frontier
Note:

* including cost increase driven by Carbon Price Floor

Security of Supply and import dependency
The Dutch electricity system is characterised by a high degree of Security of
Supply. The introduction of the policy measures assessed in this study does have
an impact on the level of operational capacities in The Netherlands. However,
due to high levels of import capacities available, the measures do not lead to a
risk to Security of Supply:
 The closure of coal-fired power plants directly decreases generation capacity
in The Netherlands. However, this decrease is compensated by earlier
reactivation of mothballed power plants and higher imports due to vast power
generation capacity around Europe in the short and medium term. However, it
has to be noted that the reactivation of the mothballed plants depends on the
view the owners take on the future energy market. Early closure of the two
plants built in the 1990’s has a limited negative effect on the reserve margin
and import dependency.
 The additional abatement measures at the plants do not influence the
availability of generation capacities to a large extent. Consequently, Security
of Supply and import dependency are not affected.
 The introduction of a Carbon Price Floor in the short term increases the
generation capacities in The Netherlands as the Dutch power plant park has a
comparative advantage due to lower emission intensities of electricity supply
when compared to neighbouring countries. More power is generated in The

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Netherlands in the short- to medium-term and exported to neighbouring
countries.
 Nevertheless, a closure of a major part of the power plants in the Netherlands
under short notice, (e.g. less than 2-3 years before implementation of the
measure) should be avoided in order to allow market participants to react to
the new market situation e.g. by reactivating gas-fired power plants (the
longer the plants are mothballed the longer is the time period required to
reactivate). In addition, discretionary market interventions have in general
negative effects on the investment climate and investor’s certainty which
means in the medium and long term a tendency towards higher costs for
society to attract investments.

Impact on RES-E
The different policy measures can have an impact on the development of
renewable energy sources in The Netherlands either directly through a changing
framework for biomass co-firing (e.g. further subsidies for co-firing) or indirectly
through a changing market environment (e.g. higher wholesale power prices
leading to earlier market driven investment in RES-E):
 The additional emission reduction achieved in Scenario 1 is largely based on
increased co-firing of biomass in the coal plants. This measure also increases
the absolute amount of RES-E in the system.
 There is only a small impact of the Carbon Price Floor on the development of
RES-E in The Netherlands.4
 The closure of all coal plants in Scenario 3a and 3b results in a decrease of
the renewable energy sources of net-demand by up to 6%-points, as no cofiring of biomass takes place as the plants close in these scenarios. However,
it is assumed that funds not used for co-firing of biomass are not spent on
subsidies for RES-E somewhere else in the system. .
The implementation of additional abatement measures at the plants in the
Scenarios 3c-e leads to a medium-term increase of RES-E (prior to plant
closure) due to higher co-firing of biomass as an element of the additional
measures.

Other emissions
Emissions of other gases and pollutants (SO2, NOx, PM, Hg) are affected by the
different policy measures:
 Closure of coal plants leads to lower emissions of SO2, PM and Hg in The
Netherlands as the omitted generation is substituted by gas-fired power
generation which emits less of these pollutants per unit of produced
electricity.

4

The additional amount of investment in RES-E in the model is limited; therefore, the Carbon Price Floor
leads to limited additional market-driven investment in RES-E.

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Emissions of NOx are reduced to a lower extent due to the increasing
emission from gas plants and the relatively low emission intensity of the
modern coal plants.
 The introduction of a Carbon Price Floor reduces utilisation of coal plant and
increases generation from gas-fired power plants. Nevertheless, the emission
of SO2, NOx, Hg and PM decreases only slightly due to an absolute increase
of domestic power generation in the short- to medium-term compared to the
Reference Case.
 Additional abatement measures influence the emission of other pollutants due
to less emission from biomass co-firing and lower utilisation if the costs of the
measures are borne by the companies.
The emission of the above mentioned pollutants is highly dependent on fuel and
plant specifics. Furthermore, increasing emission in other countries are not taken
into account in the analysis. Therefore, the results should be understood as an
indicative estimation of the impact on local emissions and further research should
be pursued to assess the impact of these factors, in a national as well an
international context.

Heat networks and supply
Some of the coal power plants currently provide heat to regional heat networks or
steam to industrial installations. Depending on the development of coal-fired
generation, e.g. if plants cease operation earlier than expected, alternative heat
supply needs to be developed for the plants that are currently producing heat for
district heating or industrial processes. This could be achieved by;
 Connecting the heat network to other heat networks with sufficient capacity to
replace the heat from coal/biomass fired power plants;
 Investing in new facilities to provide heat to heat networks. In the short- to
medium-term, these are likely to be modern gas boilers;
 Discontinue the provision of heat to industry and households by replacing it
with local heat production.
All options will lead to additional costs as investments have to be made into the
expansion of heat network and new facilities to provide heat. We estimate that
the additional costs for heat supply from gas boilers would amount to 48.8 - 89.5
mn. € per year.
Furthermore, additional heat supply can constitute an abatement measure to
reduce specific emissions of a power plant. In such a case, additional
investments might have to be undertaken in order to fully utilise the additional
heat provided by the power plant. This could include for example the cost of
expanding the heat network. On the other hand, an increased heat supply from
coal-fired power plants saves new investments into alternative heating
technologies.

Impact on innovation
The policy measures can have the following impacts on innovation:

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 Implementation of additional abatement measures can increase
innovation – The implementation of additional abatement measures can lead
to higher innovation with regard to the development of CCS and biomass
supply chains (e.g. international implementation of Dutch sustainability criteria
for biomass). In addition, the innovation potential related to the transportation
and storage of carbon dioxide can be transferred to the implementation of
CCS at gas plants.
 Closure of coal plants could lower innovation activities – If the newest
coal plants are closed early, currently planned testing of CCS might not be
realised.
 Impact on innovation with respect to RES-E – Some scenarios result in
higher investment in wind-offshore and solar PV. In these scenarios,
additional operation of RES-E could lead to higher learning effects for these
technologies. These effects, however, are deemed to be rather small due to
the already achieved cost reductions and the relatively small impact on
investments.

Employment
The closure of the five coal plants under investigation can have direct and
indirect effects on employment:
 Direct employment effects: Up to 1000 people5 are directly employed at the
five coal-fired plants. After closure of these plants, these employees would
have to be transferred into other workplaces.
 Multiplier effects: The closure of the plants can have indirect effects on
employment especially through multiplier effects example given negative
effects on suppliers of the coal plants and spending power of employees in
the affected regions.
 Compensating effects: On the other hand, the substitution of coal-fired
power generation with power supply from other sources can offset at least to
some extent the impacts on employment at the coal plants. These
compensating effects cannot be expected to totally balance out the loss of
employment at the coal plants (at least in the short term).

5

Based on full-time-equivalents (FTE)

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1 INTRODUCTION
1.1 Background of the Project
The Netherlands has committed itself to reaching a low-carbon energy system
that is reliable, affordable and safe in 2050. Within this context, the Dutch Energy
Agreement represents an irreversible step towards achieving this goal. As part of
the Energy Agreement, two of seven remaining coal-fired power stations that are
currently operational in The Netherlands will be closed mid-2017. On 26
November 2015, the second chamber of the Dutch Parliament has accepted a
motion to phase-out coal-fired electricity generation in The Netherlands. In its
proposal, the Parliament
 has taken the view that no permissions to build new coal-fired power
station in The Netherlands will be granted; and
 has asked the government and the electricity sector to develop a plan to
phase-out existing coal-fired power generation.
In his letter to the parliament from 18 December 2015 about this proposal, the
Minister explains that scenarios for the potential phase-out of coal plants in the
Netherlands should be developed and points out several variables that need to
be examined in order to evaluate these scenarios:
 CO2 emissions in The Netherlands - How do the different scenario affect
the emission of carbon dioxide in The Netherlands, also taking into account
the emissions from potential alternative heat-production?
 Carbon leakage of CO2 abroad - Would a coal phase-out induce a transfer
of domestic CO2 emission to neighbouring countries; i.e. would emissions in
other countries increase due to a phase out of coal plants in the Netherlands
and if so, what is the net-reduction effect?
 Security of Supply - Coal-fired power generation accounts for approximately
17% of the electricity supply6. Would phasing-out all coal-fired plants affect
the Security of Supply level in The Netherlands?
 Import dependency - How would different scenarios of phasing-out coal-fired
generation affect the import/export balance of The Netherlands?
 Prices of energy for businesses and households - How does a coal
phase-out impact wholesale and retail prices for power in The Netherlands?
 Potential for the production of renewable energy - How does a coal
phase-out affect the production and integration of renewable energy sources
in the electricity system?
 Impact on heat networks - How do the policy measures impact the up-keep
of district heating and the maintenance of heat-networks?
 Impact on innovation - Will the policy measures lead to more or less
innovations related to emission abatement?
6

Letter from the Minister of Economic Affairs to the Second Chamber of the Dutch Parliament (18.12.2015).

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Based on these questions, MinEZ has asked Frontier to model several scenarios
with our European power market simulation model and to evaluate these
scenarios based on the given set of indicators.

1.2 Approach of our analysis
In the following, we describe our approach for the power market simulations and
the indicator based assessment of different climate policy scenarios (Figure 3).
Figure 3.

Approach of the study
Power market model

●

Combined investment and dispatch model (used in 2015 study for MinEZ)

●

Taking into account plant specific information provided by plant operators

Policy measures / scenarios

Reference scenario
1.

Scenario definition and assumptions

1.

2.

Modelling of reference scenario
(taking into account plant specific
information for Dutch coal plants)

Scenario definition for policy
measures/scenarios

2.

Modelling of scenarios
(taking into account plant specific
information for Dutch coal plants)

3.

Output analysis

3.

Output analysis

Indicator-based assessment of policy measures
●

Definition and assessment of quantitative and qualitative indicators that allow for comparison of
different policy alternatives (scenarios and sub-scenarios):
□
CO2-emissions
□
RES-E production
□

Security of Supply

□

Impact on innovation

□

Import dependency

□

Impact on heat networks and local emissions

□

Prices and affordability

Source: Frontier Economics

We apply the following steps in our analyses:
 Power market modelling – In this assignment, we use our power market
model applied in the study “Scenarios for the Dutch electricity supply system”
(2015) undertaken on behalf of MinEZ.7 We adapted the power market model
especially regarding a more detailed representation of the coal-fired power
plants under investigation and the implementation of the policy scenarios. We
explain the applied framework of power market modelling in section 0 further.
This includes a description of the power market model used as well as
information on the specifics of the Dutch coal plants.
 Reference Case – We define a Reference Case that serves as the
counterfactual for the analysis of the different policy scenarios. The Reference
Case represents an up-to-date view on recent and future market
developments in The Netherlands and Central-Western Europe. It is largely
based on our 2015-study8, the National Energy Outlook (Nationale
Energieverkenning) published by ECN and PBL as well as the targets set out

7

Frontier Economics (2015): Scenarios for the Dutch electricity supply system.

8

Frontier Economics (2015): Scenarios for the Dutch electricity supply system.

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in the Energy Agreement. ANNEX B includes a description of the key results
of the Reference Case.
 Policy measures and scenarios – MinEZ has developed the outline for
three main scenarios (and a number of sub-scenarios), each representing one
policy measure addressing the future of coal-fired power generation in The
Netherlands:
□ Scenario 1: Additional emission reduction at coal plants – In this
scenario the coal plants apply possible measures after 2025 to reduce the
CO2 emission per unit of delivered electricity to such a level that the
emissions are at least equal to the average CO2 emissions of a modern
gas-fired power plant (350 gCO2/kWhel).
□ Scenario 2: Pentalateral collaboration – This scenario represents a
situation in which a common approach in the Pentalateral Forum9 is taken
to achieve additional CO2 reductions. It is assumed that the countries of
the Pentalateral Forum agree on CO2 reduction targets that go beyond the
targets agreed on a European level. These additional targets lead to
additional incentives to lower the emission of carbon dioxide.
□ Scenario 3: Early closure of coal-fired power plants – In the third
scenario, coal-fired power plants in The Netherlands are required to shutdown at specific dates. These dates have been set prior to the expected
technical lifetime of the coal plants. For scenarios with closures after 2025
it is further assumed that additional abatement measures will be taken
from 2025 that limit emissions of these coal plants to that of a modern gas
plant (same as Scenario 1). Specific sub-scenarios have also been
included in which only the two coal-fired power plants built in the 1990’s
are closed in 2020.
Section 3 provides a more detailed description of the different scenarios.
 Indicator based assessment – MinEZ defined a set of indicators to be used
for the evaluation of the different policy scenarios. The indicators are based
on the variables set out in the Letter of 18 December 2015 of the Minister of
Economic Affairs to the Dutch Parliament:
□ CO2 emissions in The Netherlands;
□ Carbon-leakage of CO2 abroad (in the power sector);
□ Security of Supply;
□ Import dependency;
□ Prices of energy for businesses and households;
□ The potential for the production of renewable energy;
□ The growth of heat networks;
□ Impact on innovation; and

9

The Pentalateral Energy Forum represents a framework for regional cooperation towards the
improvement of electricity markets integration and Security of Supply. It consists of Netherlands, Germany,
France, Belgium, Luxembourg, Austria and Switzerland.

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□ Impact on other emissions.
Section 4 provides a summary of the main results of the indicator based
assessment as well as a description of the methodology used for the
individual indicators.

1.3 Structure of the report
The report is structured as follows:
 Description of our approach towards modelling of the Dutch and European
power market, including the aim and outlook of the Reference Case (Section
2);
 Definition of the policy measures and scenarios (Section 3);
 Indicator based assessment of the different policy measures and scenarios
(Section 4)
Detailed information on the model, the modelling assumptions as well as on the
results can be found in the Annexes.

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2 POWER MARKET MODELLING
The following section describes the structure and underlying logic of the power
market model.

2.1 Model description
Figure 4 illustrates the structure of the power market model including the most
important inputs and outputs.
Figure 4.

Power market model

Input - Dispatch

Combined Investment and
Dispatch Model (CID)

Hourly load

Output - Dispatch

Fuel costs/ CO2

Generation / emissions

Power plant capacity and DSR

Core region
(investment and dispatch)
Non-core region (dispatch)

availability

Hourly prices

interconnectors

Hourly dispatch / DSR

Fixed O&M + variable costs

Residual load

RES-In-feed

Profitability

Input - Investment
Potentials
Investment costs
Mothballing costs

Coal plant specific
information
Market framework

System cost

Satelitte region

● Time horizon until 2050
● For photo-years 2015, 2018, 2020,
2025, 2030, 2035, 2040 and 2050
(results until 2040)

Output - Investment
Capacity balances

● High granularity of 4032 hours p.a.

Investments

● Differentiated between highly
detailed core-region and lessdetailed non-core/satellite regions

Security of Supply
Mothballing and closure

Policy measures

Source: Frontier

The main characteristics of the model can be summarised as follows:
 Cost optimisation model – The model is an integrated investment- and
dispatch model for the European power sector. The model is set up as an
optimisation problem minimising the system costs for serving power demand
across the modelled regions. The model optimises the hourly dispatch of the
power plants as well as the development of installed capacity based on
representative hours and selected photo-years (investments, divestments,
mothballing and reactivation).
 Geographical scope – Our model focusses on Central-Western Europe as
core-region, including The Netherlands. Other neighbouring countries are
included as non-core regions or satellite regions. This differentiation allows for
modelling of the power plant park in the core-region on a very detailed (unitbased) basis. Power exchange with regions modelled with lower granularity
and level of detail are at the same time included:
□ Core-regions: The Netherlands, Belgium, Germany, Austria and France.
The power plant park is modelled on a very detailed (unit-based) level, the

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dispatch of power plants and demand-side response (DSR), as well as
investment or divestment, are model outcomes.
□ Other model regions: Great Britain, Denmark, Poland, Czech Republic,
Switzerland, Italy. The power plant park is modelled as aggregated blocks.
Capacity is set exogenously, i.e. investment and divestment decisions are
not optimised.
□ Satellite regions: Other adjacent regions - for example South-Eastern
Europe, the Noordpool region and Spain - are modelled as satellite
regions. Power can be traded with those regions based on typical prices
representing the marginal costs of generation in those countries/regions.
 Temporal resolution – The time frame for optimisation follows the technical
lifetime of power plants. The time horizon for our analysis is from 2015 until
2049 with an hourly resolution of 4032 representative hours per photo-year,
the model optimises until the time period 2050.10
A more technical and detailed description of the model can be found in ANNEX
D.

2.2 Definition of the Reference Case
The Reference Case serves as a basis against which the different policy
scenarios can be evaluated and compared. The Reference Case represents the
current and intended policies in The Netherlands and North-Western Europe
without additional national measures to reduce CO2 emissions in The
Netherlands and other modelled countries beyond what has already been
politically decided. As a principle, we only take political decisions into account as
definitely decided at the beginning of May 2016. This holds for The Netherlands
as well as foreign countries.11
The reference scenario is characterised by the following key assumptions:
□ The EU ETS remains the central instrument to trigger a market-based
phase-out of coal-fired power generation; however, additional national
climate policies are included in the analyses as far as these measures
have already been definitely decided (e.g. the lignite reserve in Germany
and the Carbon Price Floor in the UK);
□ The Netherlands and other European countries pursue the goal of
lowering carbon emissions from power generation through increasing
shares of renewable energy sources (RES); and
□ No additional CO2 abatement measures beyond currently planned
investments and developments are taken into account for coal-fired power
plants in The Netherlands. Decided measures taken into account in the
Reference Case include subsidised biomass co-firing in coal plants of up

10

Analysed photo-years: 2018, 2020,2025, 2030, 2035, 2040

11

As a consequence, we don’t take any additional political action into account which may be developed or
decided in the future following the Paris Agreement (COP 21). This is consistent with the aim of the study to
evaluate specific options for further political in comparison to a reference case not including these actions.

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to 25 PJ place from 2020 until 2028 and the realisation of a CCS
demonstration project in 2020.
In previous work for MinEZ12, we developed a comprehensive “base case”
scenario taking into account the latest development in the Dutch and European
electricity market:
□ Key trends in The Netherlands have been derived from the National
Energy Outlook (Nationale Energieverkenning) and the Energy
Agreement.
□ Key trends for neighbouring countries and longer-term visions are based
on inter alia national plans or the European Commission’s climate and
energy package.
The underlying assumptions of the Reference Case have been checked for
consistency by ECN. The assumptions are described in ANNEX A in more detail.

Incorporation of the EU Emission Trading System (ETS)
The European Emission Trading System (EU ETS) constitutes the central
instrument to combat climate change on the European level. It is designed as a
cap-and-trade system within which an annual cap on total emission from sectors
covered (especially power & heat / industrial sector) is implemented (volumebased control). For each ton of carbon dioxide emitted, the participants of the
scheme have to submit one certificate (EU Emission Allowance – EUA). As the
total number of allowances is fixed and decreases over time (-2.2%/a), the
system provides an individual incentive to reduce emissions. Participants of the
power sector need to purchase the required amount of allowances through
auctions in their respective member states. Alternatively, allowances are also
traded on secondary markets. Therefore, the primary incentive to lower emission
is induced by the costs of emission, i.e. the price of the emission.
The EU ETS is incorporated in the model by a price-based approach (exogenous
price) since only parts of the EU ETS are captured in the power market model
and a volume based approach (CO2 cap on emissions in the model) can easily
lead to distorted results. This means we define the carbon price as a model input.
Assumptions on the CO2 emissions price development are based on the National
Energy Outlook, the Frontier study (2015) on scenarios for the Dutch electricity
supply system, and other relevant publicly available sources (e.g. World Energy
Outlook) (see ANNEX A).
We derive our CO2 price assumptions according to the following logic:
 Short-term (until 2017) development according to current market
expectations – We use CO2 price futures (trading day 28 April 2016) to derive
our short-term price projection.
 Medium-term (2018-2035) price development based on the National Energy
Outlook – We use the CO2 price assumptions derived in the National Energy
Outlook in 2016.13
12

Frontier Economics (2015): Scenarios for the Dutch electricity supply system.

13

ECN/PBL (2016, forthcoming), scenario “Voorgenomen beleid”.

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 Long-term price development (after 2035) is modelled as linear
extrapolation based on the price projection of the National Energy Outlook
2016 for the years 2030 and 2035.
Figure 5.

Assumed CO2 price development
90
80

70

€_2015/tCO2

60
50
40
30
20
10

0
2015

2020

2025

2030

2035

2040

2045

2050

Source: Frontier based on ECN/PBL (2016)
Note:

Prices are noted in real values (2015)

2.3 Modelling of Dutch coal-fired power plants
Currently, seven coal-fired power plants are operating in The Netherlands. As
part of the Energy Agreement, three older power plants have already been
decommissioned and two plants will cease operation in the near future:
□ Amercentrale 8 (AC 8, built in 1981): decommissioning 01 Jan 2016 (645
MWe);
□ Borssele (built in 1987) : decommissioning 31 Dec 2015 (400 MWe);
□ Gelderland (built in 1981) : decommissioning 31 Dec 2015 (Gelderland
592 MWe); and
□ Maasvlakte MV1 / MV2 (Uniper) (built in 1987/1988): decommissioning
until 01 July 2017 (total 1,040 MWe).
At the same time, a number of new power plants has or will come online:
□ Eemshaven A / B in 2015 (total 1,540 MWe);
□ Maasvlakte (Engie) in 2014 (735 MWe); and
□ Maasvlakte 3 (MPP3) in 2016 (1,069 MWe) (see Table 1).
After 2017, 4.6 GW of coal-fired power plants will be operational in The
Netherlands. The newest addition to the coal-fired power plant includes the
Rotterdam capture and storage demonstration (ROAD) project, a demonstration
plant for carbon capture and storage (CCS).
As part of this project, plant specific information has been provided by the plant
operators. This information includes:

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□ Technical information on the dispatch and emissions of the plants;
□ Economical information on variable and fixed cost of operation; 14 and
□ Options and costs of additional measures to reduce CO2 emissions at the
plant side, i.e. further co-firing of biomass, additional CCS as well as
additional heat production (see section 3.1)15
Table 1 includes a summary of the Dutch coal-fired power plants currently or
recently operating in The Netherlands.
Table 1.

Coal-fired power plants in The Netherlands

Plant name

Operating /
Owner
company

Online
date

Net
generating
capacity

Recent /
known
decommissioing

Amercentrale 8

RWE / ESSENT

1981

645

End of 2015

Amercentrale 9

RWE / ESSENT

1993

600

-

EPZ

1987

400

End of 2015

RWE / ESSENT

2015

1.540

-

Gelderland

Engie

1981

592

End of 2015

Hemweg

Nuon NV
(Vattenfall)

1994

650

-

Maasvlakte 1/2

Uniper

1987/ 1988

1.040

Mid 2017

Engie
Maasvlakte

Engie

2014

735

-

MPP3

Uniper

2016

1.069

-

Borssele

Eemshaven A / B

Source: Frontier based on information provided by plant operators

2.4 Key results of the Reference Case
In the following, we summarise the main results of the Reference Case. ANNEX
B provides a more detailed description.
 Coal plants stay operational until the end of their assumed technical
lifetime – Under current market conditions with an assumed increase of RESE and increasing CO2 prices, the five coal-fired power plants in The
14

The information itself is treated as confidential information is not included in this report.

15

The information itself is treated as confidential information is not included in this report.

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Netherlands stay operational until the end of their assumed technical lifetime
(40 years). Due to the assumed increase of the CO2 price, co-firing of
biomass becomes economically viable in the long-run (2040).16
 Significant increase of RES-E – According to the current political targets
and long-term vision of the European and Dutch power sector, renewable
energy sources play an increasingly important role in the power system. This
development is reflected in the assumptions of the Reference Case. The
renewable share of net demand is assumed to increase from ca. 12% today
to almost 50% in the 2025. After 2025, the combined effect of additional
growth of the RES-E share and the cessation of co-firing due to the end of
subsidies for biomass co-firing, leads to a slight reduction of the renewable
share to 47%. With additional investments in RES-E, the share increases to
71% of net-demand in 2040.
 Changing import position in the medium-term – With increasing tightening
of the power market in neighbouring countries and an increase of RES-E, The
Netherlands move from being a net-importer of power in the short-term to a
net-exporter of power after 2025.
Figure 6.

Development of
(Reference Case)

electricity

supply

160

in

The

Net-imports

80%
71%

140

Netherlands

other
70%
solar

120
60%

56%

wind_on

100

TWh

60

47%

wind_off

50%
40%

36%

40

RES-E (%)

48%
80

30%

ROR
other_RES
(incl. co-firing)
gas (decentral)

23%
20

oil
20%

0

gas

12%
10%

-20

-40

0%
2015

2018

2020

2025

2030

2035

2040

coal
nuclear

RES-E (%)

Source: Frontier

 Decrease of power market-related CO2 emissions – The development of
the Dutch electricity system is characterised by a strong increase of RES-E in
the Reference Case. Accordingly, the power related carbon emissions in The
Netherlands decrease significantly from 51 mn. tCO2 in 2015 to 25 mn. tCO2
in 2040. The development of CO2 emissions can be summarised as follows:

16

The total amount of biomass co-firing allowed in the Reference amounts to 25 PJ/a.

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□ Short-term decrease of carbon dioxide emissions by c. 27% to 37 mn.
tCO2 in 2020 after closure of coal-fired power stations built in the 1980’s
in The Netherlands until 2018.
□ Medium-term (model period 2025) increase to 42 mn. tCO2 with higher
exports of power to neighbouring countries.
□ Long-term decrease by 51% from 2015 until 2040 to 25 mn. tCO2.
The specific emissions per unit of electricity produced in the Dutch power
system decreases (almost) steadily until 2040 (Figure 7).
Figure 7.

Power sector CO2 emission NL
Total emissions in the Netherlands

Specific emissions (tCO2/MWh_el)

60

0.60
51
0.50
0.49
42

mntCO2

40

0.41

42

41
0.40

37
30

0.33

30

0.30
0.30

0.30

20

25

0.20

0.23
0.17

10

tCO2/MWh_el net generation

50

0.10

0

0.00
2015

2018

2020

2025

2030

2035

2040

Source: Frontier
Note:

Including emissions from CHP
Specific emissions calculated based on total net electricity generation

As in The Netherlands, power supply in Europe is moving towards carbonneutrality in the long-term. In the following, we provide information on the
development of carbon dioxide emissions in Central-Western Europe
(including The Netherlands), in Great Britain and Denmark.17 Power market
related emissions of these countries decrease by ca. 67% from 2015 until
2040.18 Based on this decrease, the Reference Case tends to be broadly in
line with the ambition of the EU to come to a total CO2-reduction in 2050 of 80
– 95%.

17

Great-Britain and Denmark are not part of the “core-region”, i.e. plant dispatch is modelled with a lower level
of detail and capacity development is assumed exogenously.

18

Historical emissions based on UNFCCC data (1.A.1.a - Public Electricity and Heat Production) are
comparable only to a limited extent (due to different definitions of included installations).

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Figure 8.

CO2 emissions in the Reference Case (CWE and neighbouring
countries)

mn. tCO2

NL

DE

FR

BE

GB

AT

CH

DK

800
700
600
500
400
300
200

100
0
1990*

2005*

2015

2018

2020

2025

2030

2035

2040

Source: Frontier
Note:

* 1990/2005 based on UNFCCC data (1.A.1.a - Public Electricity and Heat Production)

As explained in Section 2.2, the Reference Case represents the current and
intended policies in The Netherlands and North-Western Europe without
additional national measures to reduce CO2 emissions in The Netherlands and
elsewhere beyond what has already been politically decided. That means,
possible policy actions that might be taken in the future in relation to the Paris
Agreement have not been taking into account since It is currently not possible to
predict what such actions might be and what effects these would have on the
power markets in the EU.
However, one possible outcome might be that future CO2 prices would be (even)
higher than assumed in this study. It is straightforward that a higher CO2 price
would lead to (even) higher CO2 abatement in the EU as well as in the
Netherlands (at least in the long term) than compared to the current Reference
Case: Coal plants in the Netherlands can be expected to be dispatched less
often in the long run, and shares of RES-E can be expected to increase further in
The Netherlands and in the EU (including additional usage of biomass co-firing).

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3 POLICY MEASURES AND SCENARIOS
MinEZ has developed the outline for three main scenarios (and a number of subscenarios), each representing one policy measure addressing the future of coalfired power generation in The Netherlands:
 Scenario 1: Additional abatement measures at the plants – In this
scenario the coal plants apply possible measures to reduce the CO2 emission
per unit of delivered electricity to such a level that the emissions are at least
equal to the average CO2 emissions of a modern gas-fired power plant (350
gCO2/kWhel).
 Scenario 2: Pentalateral collaboration – This scenario represents a
situation in which a common approach in the Pentalateral Forum19 is taken to
achieve additional CO2 reduction. It is assumed that the countries of the
Pentalateral Forum agree on CO2 reduction targets that go beyond the targets
agreed on a European level. These additional targets lead to additional
incentives to lower the emission of carbon dioxide.
 Scenario 3: Closure of coal-fired power plants – In the third scenario, coalfired power plants in The Netherlands are required to shut-down at specific
dates. These dates have been set prior to the expected technical lifetime of
the coal plants. For scenarios with closures after 2025 it is further assumed
that additional abatements measures will be taken from 2025 that limit
emissions of these coal plants to that of a modern gas plant (same as
Scenario 1). Specific sub-scenarios have also been included in which only the
two coal-fired power plants built in the 1990’s are closed in 2020.
In the following, we describe the assumptions of these scenarios in more detail.

3.1 Additional abatement measures at the plants
In the first scenario, it is assumed that operators implement additional measures
at the coal plants to reduce the CO2 emission per unit of delivered electricity to
such a level that the emissions are at least equal to the average CO2 emissions
of a modern gas-fired power plant (350 gCO2/kWhel). It is assumed that these
measures are effective in the model period 2025, which means implementation of
the measures has to happen before 31 December 2024.
Plant operators of the Dutch coal plants have been asked to provide information
on possible additional abatement measures that could be implemented at their
power plants to lower their emission to the threshold of 350 gram/kWhel20 , which
is comparable to a highly efficient gas-fired power plant.
In the following, we describe which measures have been included and how they
are implemented in the context of the power market model.

19

Netherlands, Germany, France, Belgium, Luxembourg, Austria and Switzerland.

20

Based on 58% electrical efficiency and 203g CO2 /kWh.

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3.1.1 Emission abatement measures
Measures that could be implemented by the plant operators include:
 Co-firing of biomass - Co-firing up to 25 PJ/a across all Dutch coal plants is
included in the Reference Case, subsidised co-firing takes place from 2020
until 2028. In addition to this amount, plant operators could use higher shares
of co-firing compared to the Reference Case. Biomass co-firing is regarded as
CO2-neutral and reduces the specific emissions of the plant accordingly.
Based on the information received from the operators, all coal plants would
implement biomass co-firing as a measure to reduce the specific carbon
emissions to the level of a modern gas plant.
 Increase utilisation of residual heat output - Two of the power plants in
focus already dispose of combined-heat and power production (CHP) in the
Reference Case. In this scenario, additional utilisation of heat decoupling
could be implemented in order to lower specific emissions of the power plant.
For each additional MWh_th heat output, a heat credit for CO2 emission
reduction is granted that equals the avoided amount of carbon dioxide
emissions in the heat sector. Based on the information received from the
operators, one power plant would increase its heat output to lower the specific
emissions per unit of electricity produced. Other plant operators indicated that
additional heat decoupling is theoretically possible, but not included in this
context.
 Implementation of Carbon Capture and Storage (CCS): The ROAD-facility
at the Maasvlakte represents the only CCS installation included in the
Reference Case. In addition to this, plant operators could implement CCS to
lower their emission. One plant operator indicated that additional CCS would
be used in order to lower specific emissions of the power plant in this
scenario. Furthermore, one additional plant operator indicated that the
implementation of CCS at its plant is in general possible, but not necessary to
achieve the target emission-intensity in this context.

3.1.2 Modelling framework
The abatement measures described above only include measures that are not
economically viable by themselves in 2025. Scenario 1 consists of two subscenarios which are differentiated by different treatment of the costs associated
with the implementation of the additional emission reduction:
 Scenario 1a: Emission reduction measures at the plants (no
compensation) – Plant operators have to bear the costs associated with the
additional emission reduction themselves. This includes investment costs to
achieve the required emission reduction, increased variable and fixed
operating and investment costs as well as efficiency losses. In this scenario,
abatement measures and associated costs are included as off 2025. Based
on the parameters included, the model optimises whether the plants stay
operational until the end of their lifetime or cease operation earlier.
 Scenario 1b: Emission reduction measures at the plants (compensation)
This sub-scenario includes the same abatement measures as sub-scenario

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1a. The cost associated with the optimised emission reduction, however, are
not included in the firm’s cost base. Therefore, this scenario can be
interpreted as a framework in which plant operators are compensated for
additional costs arising from the implementation of additional abatement
measures at their plants.

3.2 Pentalateral collaboration
In the second scenario, it is assumed that the countries of the Pentalateral
Forum21 reach an agreement to implement common measures to achieve
additional CO2 reductions from 2018 onwards. It is assumed that the agreed CO2
reduction targets go beyond the targets agreed on European level.

3.2.1 Definition of the collaborative approach
There are several possible ways to implement a regional system to incentivise
additional CO2 abatement beyond the EU ETS, e.g.
 Regional CO2 emission limit – The governments of the Pentalateral Forum
could agree on a carbon dioxide limit below the corresponding limit derived
from the EU ETS. This volume-based approach ensures that the envisaged
amount of CO2 is abated. The cost associated with the CO2 reduction is
derived by the market. While this is theoretically possible, a CO2 emission
trading scheme on top of the EU ETS and restricted to a specific European
region seems rather unlikely.
 Emission performance standards – An alternative policy option is to cap
the specific or annual CO2 emission of power plants. This can be done by
defining how much CO2 may be emitted for the production of one unit of
electricity (relative emission performance standard). Plants that do not meet
the standards either need to invest in efficiency improvements or face
decommissioning. Alternatively, the total amount of carbon dioxide emitted by
coal plants annually could be capped (absolute standard). Without additional
CO2 abatement measures at the Dutch coal plants, this option would result in
a de-facto reduction of the running-hours of the plants.
 Carbon price adjustment – Alternatively, governments of the Pentalateral
Forum could agree on a carbon price adjustment, i.e. an additional price
incentive on top of the CO2 price observed in the EU ETS.
In this study, the collaborative approach pursued by the countries of the
Pentalateral Forum is modelled as a carbon price adjustment: it is assumed that
the governments of the Pentalateral Forum agree on an additional price incentive
on top of the CO2 price provided by the EU ETS carbon price. This price
adjustment could be implemented in the following ways:
□ There could be a Carbon Price Floor on the price achieved in the EU ETS;
□ A carbon tax could be imposed that applies alongside the price signals of
the EU ETS;
21

The Netherlands, Germany, France, Belgium, Luxembourg, Austria and Switzerland

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□ Additional price incentives could arise from an uplift of the carbon price
either by a constant or varying amount (EUR/tCO2).
A similar approach has been introduced in Great Britain with the Carbon Price
Floor that aims to support low carbon technologies. The Carbon Price Floor has
been introduced in April 2013 as an administered levy on fossil fuels used to
generate electricity. Currently, the Carbon Price Floor amounts to GBP 18/t CO2,
which is added to the price of one EU Allowance in the EU ETS. The Carbon
Price Floor was set up to reach a price of GBP 30/t CO2 in 2020.22 Recently, the
French government announced that it also intends to introduce a Carbon Price
Floor by 2017. According to media reports, the floor price could amount to 30
EUR/ t CO2.23

3.2.2 Modelling framework
Based on the reasoning above, the collaborative approach is modelled as a
Carbon Price Floor. The level of the floor price has been chosen in accordance to
the price levels discussed in France and to the Carbon Price Floor in Great
Britain:
□ The Carbon Price Floor starts at 30 EUR(real, 2015)/tCO2 in 2018;
□ Gradually increases to 42 EUR(real, 2015)/tCO2 in 2030; and
□ Reaches the Reference Case carbon price of 53 EUR(real, 2015)/tCO2 in
2040 (Figure 9).
From 2040 the Carbon Floor Price no longer applies since the carbon price itself
exceeds 50 EUR(real, 2015)/tCO2.
Figure 9.

Carbon Price Floor (Scenario 2)
Carbon price support

CO2-price (Reference Case)

Carbon price floor

90

EUR(real, 2015) / tCO2

80
70
60
50
8

40
16

30

19

20

22

21

10
0
2015

2018

2020

2025

2030

2035

2040

2050

Source: Frontier
Note:

CPF applies to fossil fuelled generation in NL, DE, FR, BE, AT,CH

22

HM Revenue & Customs (2014): Carbon Price Floor: Reform and other technical amendments.
Department of Energy and Climate Change (DECC) (2011): Planning our electric future: a White Paper for
secure, affordable and low‑carbon electricity.

23

Reuters (17 May 2016): France will set Carbon Price Floor at about 30 euros/T ;
http://af.reuters.com/article/commoditiesNews/idAFL5N18E1R3?sp=true

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The Carbon Price Floor affects the variable costs of all fossil fuelled generation in
the countries of the Pentalateral Forum.
It is important to note that under the EU ETS, the total amount of emissions per
year is subject to the cap defined according to the Linear Reduction Factor.
Therefore, total emissions in the EU ETS stay constant and are not affected by
national or regional CO2 abatement such as the CPF if no additional measures
are implemented. The introduction of a carbon price floor reduces demand for
emission allowances in some parts of the EU ETS, which leads to a price
reduction in the overall system. This, in return, increases emissions in other
regions or sectors that are not subject to the price floor. We do not take the CO2
price reducing effect of national/regional CO2 abatement measures into account.
The repercussion on the demand for and the price of emission allowances is
therefore not included in the analysis. This holds for all of the Policy Scenarios
analysed in this study.

3.3 Early closure of coal-fired power plants
The third policy scenario is based on the pre-term closure of coal plants in The
Netherlands. The six sub-scenarios are differentiated by the dates at which the
coal plants have to cease operation. Further, this scenario differentiates between
scenarios in which no emission reduction measures in addition to the
implemented measures of the Reference Case are included (3a/3b/3f) and
scenarios in which the abatement measures of Scenario 1 are also taken into
account (3c/3d/3e) (Table 2):
□ Scenario 3a: Closure until 2020 (31-12-2019);
□ Scenario 3b: Closure until 2025 (31-12-2024);
□ Scenario 3c: Closure until 2030 (31-12-2029) + additional abatement
measures;
□ Scenario 3d: Closure until 2040 (31-12-2039) + additional abatement
measures;
□ Scenario 3e: Closure of 1990’s plants until 2020 (31-12-2019) + additional
abatement measures;
□ Scenario 3f: Closure of 1990’s plants until 2020 (31-12-2019).

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Table 2.
Plant name

Assumed closure dates (Scenario 3)
Scenario
3a

Scenario
3b

Scenario
3c

Scenario
3d

Scenario
3e

Scenario
3f

Amercentrale 9

2019

2024

2029

2039

2019

2019

Eemshaven
A/B

2019

2024

2029

2039

2019

2019

Hemweg

2019

2024

2029

2039

-

-

Engie
Maasvlakte

2019

2024

2029

2039

-

-

MPP3

2019

2024

2029

2039

-

-

Additional
abatement
measures at
the plants
after 2025

no

no

yes

yes

yes

no

Source: Frontier

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4 INDICATOR BASED ASSESSMENT
In this chapter, we summarise the results of the indicator-based assessment of
the different policy measures and scenarios. Details can be found in ANNEX C
The section is structured as follows:
 Summary of the main findings (Section 4.1);
 Impact on carbon dioxide emissions in The Netherlands and Europe (Section
4.2)
 Impact on the affordability of the power system (Section 4.3);
 Impact on power prices (Section 4.4) and consumer payments (Section 4.5);
 Impact on Security of Supply and import dependency (Section 4.6);
 Impact on the development of RES-E (Section 4.7); and
 Impact on other indicators (Section 4.8).

4.1 Summary
Table 3 summarises the indicator based assessment. The definition of the
different indicators in the table is specified as follows (more detailed description
can be found in the following chapters):
 Impact on CO2 emissions - Accumulated difference of CO2 emissions
compared to the Reference Case (2018-2049) in The Netherlands (domestic
emission reduction); total CO2 emission reduction in all modelled countries,
including The Netherlands (net emission reduction).
 Impact on wholesale prices for electricity in The Netherlands - Difference
of the yearly average wholesale power price compared to the Reference
Case.
 System costs and specific abatement costs - Impact on the system costs
of the electricity supply in The Netherlands and in all modelled countries,
expressed as net present value from 2018-2049, compared to the Reference
Case. Specific abatement cost have been calculated by dividing additional
system costs by additional CO2 emission reduction - from a Dutch perspective
(Domestic abatement costs) and a European perspective (Net-EU abatement
costs).
 Impact on consumer payments - Difference to the Reference Case of
consumer payments for electricity supply and RES-E support, expressed as
net present value from 2018-2049.
 Impact on Security of Supply and import dependency - Impact on the
average reserve margin (based on peak load and de-rated generation
capacities) from 2018-2049 and impact on average level of net-imports from
2018-2049, compared to the Reference Case.

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 Impact on RES-E - Impact on the average share of renewable energy
sources of net-demand (%-points), compared to the Reference Case.

Table 3.

Indicator based assessment - Summary

Scenario

Scen.
1a

Scen.
1b

Scen. 2

Scen.
3a

Scen.
3b

Scen.
3c

Scen.
3d

Scen.
3e

Scen. 3f

Impact on emissions
Domestic
emission
reduction
(mn.tCO2,
sum 20182049)

-180
(-17 %)

-162
(-15 %)

-58
(-5 %)

-322
(-30 %)

-258
(-24 %)

-242
(-23 %)

-194
(-18 %)

-209
(-19 %)

-63
(-6 %)

Net emission
reduction all
countries
(2018-2049)

-121
(-0.9 %)

-152
(-1.1 %)

-401
(-2.9 %)

-87
(-0.6 %)

-82
(-0.6 %)

-114
(-0.8 %)

-132
(-1.0 %)

-113
(-0.8 %)

-11
(-0.1 %)

Impact on wholesale prices for electricity in the Netherlands
Price
increase in
2020
EUR/MWh

-

-

10.5

4.1

-

-

-

0.9

0.9

Price
increase in
2030
EUR/MWh

0.8

0.0

3.6

3.7

3.7

3.7

0.8

1.1

0.7

System Costs and specific abatement costs
Impact on
system costs
in the
Netherlands
(bn. EUR)

1.4
(1.7 %)

2.1
(2.6 %)

0.3 *
(0.4 %)

7.1
(8.8 %)

4.2
(5.2 %)

4.5
(5.6 %)

3.1
(3.9 %)

2.1
(2.7 %)

1.1
(1.3 %)

Impact on
system costs
in EU (bn.
EUR)

2.3
(0.3 %)

2.8
(0.4 %)

9.4 *
(1.2 %)

7.9
(1.0 %)

6.0
(0.8 %)

5.1
(0.7 %)

3.6
(0.5 %)

3.1
(0.4 %)

1.4
(0.2 %)

Domestic
abatement
costs
(EUR/tCO2)

7.5

12.8

5.1*

21.9

16.2

18.7

16.0

10.3

27.5

Net-EU
abatement
costs
(EUR/tCO2)

18.6

18.7

22.7*

90.9

73.5

45.1

27.7

27.7

119.2

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Scenario

Scen.
1a

Scen.
1b

Scen. 2

Scen.
3a

Scen.
3b

Scen.
3c

Scen.
3d

Scen.
3e

Scen. 3f

Impact on consumer payments
Impact on
household
payments
(bn. EUR/%)

0.1
(0.3 %)

0.0
(0.0 %)

2.1
(9.6 %)

0.9
(4.2 %)

0.5
(2.4 %)

0.4
(1.6 %)

0.2
(0.9 %)

0.2
(0.9 %)

0.2
(0.7 %)

Impact on
other
consumer
payments
(bn. EUR/%)

0.2
(0.2 %)

0.0
(0.0 %)

6.4
(8.0 %)

2.6
(3.3 %)

1.5
(1.9 %)

1.0
(1.3 %)

0.6
(0.8 %)

0.6
(0.7 %)

0.5
(0.6 %)

Security of Supply and import dependency
Impact on
average
Reserve
Margin (GW)

0.0

0.1

1.0

-1.2

-1.0

-0.5

-0.1

-0.2

-0.3

Impact on
average netimports
(TWh)

2.6

1.2

1.2

14.3

11.5

8.4

3.7

4.6

2.8

-2.1%

-1.8%

-0.2%

2.0%

2.7%

-0.5%

Impact on Renewable Energy Production
Impact on
average
RES-E %points

3.6%

4.8%

0.7%

Source: Frontier
Note:

Values shown in table above represent differences compared to the Reference Case
* Not including the increase of variable costs related to the carbon price floor

The results are described and explained in more detail in the following chapters.

4.2 Impact on carbon dioxide emissions
The policy scenarios defined in section 3 aim to reduce the carbon dioxide
emissions from Dutch coal plants through different policy measures. In this
chapter, we describe the impact of the different measures on the CO2 balance in
The Netherlands and the other countries modelled.

4.2.1 Methodology
The carbon dioxide emissions from power production are calculated as all power
related emissions, based on net-electricity production and plant or technology
specific CO2 emission intensities. Emissions from CHP-production are taken into
account on the basis of plant-specific emission intensity. If the policy measures
include an improvement of the plant specific emission intensity based on an
increase of heat utilisation, a credit for this increase in the form of lower emission
intensity is granted.24

24

Based on the emission intensity of an alternative heat source.

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CO2 emissions are reported as differences to the Reference Case and defined
as:
 Domestic emission reduction in the Netherlands, that takes into account
lower emissions from Dutch coal plants and an increase of emissions from
other Dutch power plants; and
 Net emission reduction taking into account changes of emissions in all
modelled European countries, including the Netherlands.
In addition, we analyse to what extent the development path of emissions from
2015 until 2040 is affected by the implementation of the policy measures.
EMISSION REDUCTION IN THE EU ETS
National measures can have an impact on emissions in the EU ETS in two ways:
 First-order effect: Generation in The Netherlands decreases due to e.g. phase-out
of coal-fired generation. The omitted amount of generation is partially substituted by
higher generation in interconnected countries. Subsequently, emissions of CO 2 in
these countries increase. This first-order effect is included in the electricity market
model.
 Second-order effect: Annual emission levels in the EU ETS are fixed according to
the EU-wide annual CO2 emission cap and should therefore not be affected by
national additional CO2 abatement measures in the power sector as long as the cap
is not reduced or CO2 emission certificates are taken out of the market. In this case,
total CO2 emissions in the EU ETS stay the same irrespective of additional CO2
25
abatement measures in the power sector in a specific country or region. More
explicitly, a reduction of emissions in one country ceteris paribus leads to less overall
demand for allowances and therefore induces downward pressure on the price of EU
allowances. This has an adverse effect of higher emissions in other countries or
sectors. The total emissions in the system in such a situation stay the same.
This second order effect of national climate policy could be avoided by the
implementation of additional measures such as e.g.
□

An overall reduction of the CO2 emission budget/cap in the EU ETS (e.g. yearly
EU ETS cap) corresponding to the amount of emission reduction achieved in The
Netherlands / in the countries of the Pentalateral Forum;

□

A cancellation of CO2 certificates from the market (e.g. “buy and burn”),
corresponding to the amount of emission reduction achieved in The Netherlands /
in the countries of the Pentalateral Forum.

This adverse second-order effect is not captured in the model as the price of EU
allowances is kept constant despite the implementation of the national climate policy
scenarios.

4.2.2 Results
The policy measures have the following impact on carbon dioxide emissions in
The Netherlands:

25

Not taking into account a possible reduction of the yearly auctioning volumes in the EU ETS through the
Market Stability Reserve.

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Domestic emission reduction differ significantly between scenarios
 Scenario 1: Additional abatement measures at the plants from 2025 –
Implementing additional abatement measures at the Dutch coal plants
reduces the CO2 emission intensity to the level of a modern gas-fired plant as
off 2025.
□ In Scenario 1a, the costs of the emission reduction are borne by the plant
operators. This leads to an earlier decommissioning of one of the coal
plants built in the 1990s: For this plant, operation with an increased
(unsubsidised) share of biomass co-firing becomes no longer economical
viable after 2028 and the plant closes before 2030 instead of until 2035. In
total, the implementation of additional abatement measures in Scenario 1a
reduces the CO2 emissions in The Netherlands by ca. 180 mn. tCO2
(aggregated emission reduction from 2018-2049).26 The highest yearly
emission reduction is achieved in 2030 with 14 mn. tCO2 less emissions
than in the Reference Case.
□ In Scenario 1b, the abatement costs are not fully incorporated into the
firm’s cost base (increased fuel and fixed costs are assumed to be
compensated by the state)27. This leads to lower variable costs of
generation in the medium term and therefore higher utilisation of coal
plants compared to Scenario 1a.28 Further, earlier decommissioning of
coal plants does not take place. Therefore, emission reduction in The
Netherlands in Scenario 1b are (moderately) lower than in Scenario 1a (162 mn. tCO2, aggregated from 2018-2049).
 Scenario 2: Introduction of a Carbon Price Floor in CWE – Introducing a
Carbon Price Floor in Central-Western Europe in 2018 leads to an emission
reduction in The Netherlands of 58 mn. tCO2 from 2018-2049 (aggregated).
Due to the comparatively low emission intensity of the Dutch power sector
(e.g. as compared to Germany), Dutch power plants achieve a cost
advantage due to higher CO2 prices. This increases utilisation of Dutch plants
while generation of plants with higher carbon intensity abroad (e.g. German
lignite) decreases. Therefore, the majority of the achieved emission reduction
in the modelled region takes place in other countries in Central-Western
Europe, especially Germany.
 Scenario 3: Early closure of coal plants – The effect of closing all coal-fired
power plants on total CO2 emission reduction depends significantly on the
assumptions regarding the date of closure:
□ Scenario 3a/b: Closure of coal plants until 2020 reduces emissions in The
Netherlands by 322 mn. tCO2 from 2018 until 2049 (-30 %). If all plants
are closed until 2025, 258 mn.tCO2 (-24%) is emitted less in The
Netherlands. Due to the earlier closure of coal-plants, less gas-fired plant
capacity is mothballed in 2018. Consequently, domestic power supply and
26

Emission reduction from 2018 until 2049 have been calculated based on the representative modelled years.

27

Calculated costs of the additional measures (excl. efficiency losses) amount to 2.6 bn EUR (NPV 20182049); see section 4.3.1.

28

Emission reduction measures are implemented to achieve a reduction of the specific emission factor to at
least 350 gCO2/kWh_el .

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emissions in The Netherlands increase slightly in 2018/2020 before plants
close in 2020/2025 (Table 4).
□ Scenario 3c/d: Assuming a later closure date while implementing
additional abatement measures at the coal plants lowers the achieved
emission reduction in The Netherlands to 242 mn. tCO2 (-23%) if plants
close before 2030 or to 194 mn. tCO2 (-18%,) if closure is pursued until
2040.
□ Scenario 3e/f: If the two oldest plants close before 2020 and additional
abatement measures are implemented at the remaining plants (Scenario
3e), total emissions in The Netherlands decrease by 209 mn. tCO2 (-20 %)
from 2018-2049. If, however, no additional abatement measures are
implemented, the emission reduction only amounts to 63 mn. tCO2 (-6%).
Closure of the two oldest plants results in around 4 Mton CO2 reduction in
2020 in The Netherlands.
Table 4 summarises the domestic reduction of emissions in The Netherlands
compared to the Reference Case.
Table 4.

Domestic emission reduction (NL)

mn.t CO2

Sum 20182049

2018

2020

2025

2030

2035

2040

Scenario 1a

-180
(-17 %)

0
(0 %)

0
(0 %)

-10
(-24 %)

-14
(-33 %)

-6
(-22 %)

-3
(-12 %)

Scenario 1b

-162
(-15 %)

0
(0 %)

0
(0 %)

-9
(-21 %)

-12
(-29 %)

-6
(-21 %)

-3
(-12 %)

Scenario 2

-58
(-5 %)

3
(7 %)

0
(0 %)

-4
(-10 %)

-5
(-13 %)

-3
(-10 %)

0
(0 %)

Scenario 3a

-322
(-30 %)

1
(1 %)

-12
(-33 %)

-16
(-37 %)

-17
(-42 %)

-11
(-36 %)

-4
(-18 %)

Scenario 3b

-258
(-24 %)

1
(1 %)

1
(2 %)

-16
(-37 %)

-17
(-42 %)

-11
(-36 %)

-4
(-18 %)

Scenario 3c

-242
(-23 %)

0
(0 %)

0
(0 %)

-10
(-24 %)

-18
(-44 %)

-11
(-37 %)

-5
(-19 %)

Scenario 3d

-194
(-18 %)

0
(0 %)

0
(0 %)

-10
(-24 %)

-14
(-33 %)

-6
(-22 %)

-4
(-18 %)

Scenario 3e

-209
(-19 %)

0
(0 %)

-4
(-11 %)

-12
(-28 %)

-14
(-34 %)

-6
(-22 %)

-3
(-12 %)

Scenario 3f

-63
(-6 %)

0
(0 %)

-4
(-10 %)

-4
(-9 %)

-5
(-12 %)

0
(0 %)

0
(0 %)

Source: Frontier
Note:

frontier economics

Reduction of emission compared to the Reference Case
Scenarios 1a and b assume implementation of additional abatement measures in 2025. Earlier
implementation, e.g. in 2020, would yield earlier emission reductions.

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Increase in emissions abroad partially offsets domestic emission reduction
National measures that affect the operation of power plants in one country can
have an impact on the operation of plants in interconnected countries. The
Netherlands can be described as a relatively small power system with a high
level of interconnections. Therefore, interactions with other countries have to be
taken into account when assessing the CO2 reduction effects of national
measures in The Netherlands.29 Again, it has to be noted that the second order
effect in the EU ETS due to national climate policy measures in The Netherlands
is not taken into account in this analysis.
 Scenario 1: Domestic emission reduction is partially offset by increased
emissions abroad – The implementation of the additional abatement
measures in The Netherlands affects power generation in other countries only
if the abatement costs are included in the firm’s cost base (Scenario 1a). Due
to lower utilisation and earlier decommissioning of coal-fired plants in The
Netherlands, power generation and CO2 emissions in neighbouring countries
increase. The net emission reduction in all modelled countries amounts to 121
mn. tCO2 from 2018 to 2049 (aggregated over the period), i.e. ca. 60 mn.
tCO2 emissions are “exported” to neighbouring countries.
If additional abatement costs are compensated by the state, the operation of
the coal plants is only affected to a limited extent. Therefore, emissions in
neighbouring countries do not change significantly. The net-reduction of CO2
emissions from 2018 until 2049 in all modelled countries amounts to 151 mn.t
CO2 as compared to 162 mn. tCO2 of domestic reduction (aggregated). This
means 11 mn.tCO2 are “exported” to other countries over the period from
2018 until 2049.
 Scenario 2: Carbon Price Floor leads to significant additional CO2
emission reduction in other European countries – The Carbon Price Floor
leads to a significant increase of the CO2 price, not only in The Netherlands,
but also in all other countries of the Pentalateral Forum. The biggest impact in
the short-term, however, is on Germany due to the high share of carbonintensive lignite and coal-fired power generation. The CPF leads to a ca. 50%
decrease of coal- and lignite-fired generation in Germany in 2018 compared
to the Reference Case. In comparison, due to the comparatively low emission
intensity of the Dutch power plant park, generation in The Netherlands
increases in 2018 to substitute omitted generation in neighbouring countries.
In total, from 2018 until 2048, the Carbon Price Floor reduces CO2 emissions
by 401 mn. tCO2 (-37%) with the majority of emission reductions taking place
in the early years from 2018-2025.
 Scenario 3: Closure of Dutch coal plants significantly increases
emissions abroad – Closing the Dutch coal plants reduces net emissions in
The Netherlands by up to 31% (Scenario 3a): Lower emissions from closing
coal plants are partly offset by more emissions from other power plants in the
Netherlands: Around 30% of omitted power generation from Dutch coal plants
29

It has to be noted that the optimisation of interconnector flows in the model is subject to simplifying
assumptions. In reality, interconnector flows are also influenced for example by transit or loop flows that
could limit the extent to which other countries are affected by national measures.

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RESEARCH OF SCENARIOS FOR COAL-FIRED POWER
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is substituted by domestic electricity supply, especially gas-fired power
generation.30 The larger share is substituted by higher net-imports of power
and, consequently, CO2 emissions in neighbouring countries increase. :
□ Scenario 3a/b: The domestic emission reduction of 322 mn t.CO2 in
Scenario 3a (closure until 2020) corresponds to net-reduction in the
modelled countries of only 87 mn. tCO2 in the period 2018 until 2049
(aggregated). 70% of the emission reduction achieved in The Netherlands
is offset by higher emissions in other EU-countries. For example, German
power generation from hard coal increases by 5 TWh, lignite-fired
generation increases by 1 TWh and gas-fired generation increases by 1
TWh in 2020.31
In Scenario 3b, with closure until 2025, 65% of domestic emission
reduction is compensated by higher emissions abroad (net-reduction
amounts to 82 mn. tCO2).
□ Scenario 3c/d: If power plants have to cease operation at a later point in
time (e.g. until 2030 in Scenario 3c) and if additional abatement measures
are implemented at the coal plants as of 2025, net-reduction increases
compared to an early closure of coal plants (-114 mn.tCO2 in Scenario 3c).
The difference between the scenarios with early closure and with later
closure arises due to the smaller amount of omitted generation of closed
coal plants. With closure in 2040, less generation needs to be substituted
abroad. Consequently, the net emission reduction is slightly higher with
132 mn. tCO2 (-12%).
□ Scenario 3e/f: If the two oldest coal-fired plants were to close before
2020, net emission reduction would amount to 113 mn.t CO2 aggregated
from 2018 to 2049 (-11%) in the case that additional abatement measures
are implemented at the remaining plants. If no additional abatement takes
place at the newer plants, net-reduction amounts to only 11 mn. tCO2 (1%) due to the fact that more than 80% of the foregone emissions from
the oldest plants is offset by higher emissions in neighbouring countries.
The substitution effects described above are partially driven by the fact
that the average emission intensity in The Netherlands is lower compared
to e.g. Germany, today. Therefore, if power generation from The
Netherlands is moved to e.g. Germany, overall emissions in the region
can increase at least in the short term.32
Table 5 summarise the net-reduction of CO2 emissions in all modelled countries
compared to the Reference Case.

30

%-share of domestic substitution varies from 43% in 2020 to 13% in 2035 and 60% in 2040 (see Annexe
C.4)

31

See Annexe C.4.

32

In the short-term, one MWh of electricity generation in Germany instead of in The Netherlands leads to
increase in emission of 0.03 tCO2 (Reference Case 2018-2025).

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Figure 10.

Domestic and net-reduction of CO2 emissions
Domestic reduction NL
1a

1b

2

3a

3b

Net-reduction
3c

3d

3e

3f

0

0%

-50

-5%

-5%

-6%
-0.6%

-100

-0.6%

mn. tCO2 (2018-2049)

-15%

-15%

-200

-10%

-1.0%

-1.1%

-150

-0.8%

-0.8%

-0.9%

-17%
-18%
-19%

-250

-20%

-23%
-24%

-25%

-300
-350
-400
-450

-30%

-2.9%

-30%
-35%

% difference compared to Reference Case

-0.1%

-40%

Source: Frontier
Note:

frontier economics

Domestic emission reduction in The Netherlands and net-reduction in all modelled countries

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Table 5.

Net emission reduction (model region)

mn.t CO2

Sum 20182049

2018

2020

2025

2030

2035

2040

Scenario 1a

-121
(-0.9 %)

0.0
(0%)

-0.1
(0%)

-5.2
(-1%)

-8.4
(-2%)

-5.5
(-1%)

-2.5
(-1%)

Scenario 1b

-152
(-1.1 %)

0.0
(0%)

-0.1
(0%)

-8.0
(-2%)

-11.2
(-3%)

-6.1
(-2%)

-2.5
(-1%)

Scenario 2

-401
(-2.9 %)

-58.0
(-9%)

-33.3
(-6%)

-17.5
(-3%)

-3.7
(-1%)

-2.3
(-1%)

-0.1
(0%)

Scenario 3a

-87
(-0.6 %)

0.8
(0%)

-0.2
(0%)

-2.3
(0%)

-6.0
(-1%)

-3.0
(-1%)

-3.1
(-1%)

Scenario 3b

-82
(-0.6 %)

0.8
(0%)

0.8
(0%)

-2.3
(0%)

-6.0
(-1%)

-3.0
(-1%)

-3.1
(-1%)

Scenario 3c

-114
(-0.8 %)

0.0
(0%)

-0.1
(0%)

-5.2
(-1%)

-6.7
(-2%)

-3.6
(-1%)

-3.5
(-1%)

Scenario 3d

-132
(-1.0 %)

0.0
(0%)

-0.1
(0%)

-5.2
(-1%)

-8.4
(-2%)

-5.5
(-1%)

-3.5
(-1%)

Scenario 3e

-113
(-0.8 %)

0.0
(0%)

0.1
(0%)

-4.2
(-1%)

-8.0
(-2%)

-5.5
(-1%)

-2.5
(-1%)

Scenario 3f

-11
(-0.1 %)

0.0
(0%)

0.1
(0%)

-0.3
(0%)

-2.1
(0%)

0.0
(0%)

0.0
(0%)

Source: Frontier
Note:

Reduction of emission compared to the Reference Case

Reduction of annual CO2 emission in The Netherlands (2040)
The impact on the long-term CO2 emission reduction path depends on the longterm structural change induced by the policy measure.
Table 6 shows the absolute impact of power-related CO2 emissions in The
Netherlands in 2040 and the relative change compared to 2040 emission in the
Reference Case:
 Scenario 1: Additional abatement measures induce 12% reduction of
CO2 emissions in 2040 – If additional abatement measures are implemented
at the Dutch coal-fired plants after 2025, domestic power-related CO2
emissions in 2040 are 12% lower than in the Reference Case.
 Scenario 2: No long-term impact of Carbon Price Floor on domestic
emissions – As described above, the Carbon Price Floor leads to an
increase of CO2 emissions in the Netherlands in 2018 and only a limited effect
on CO2-reduction in the medium-term. In the long-run, from 2040 onwards,
the Carbon Price Floor is assumed to phase out since carbon prices are
assumed to increase significantly anyway. Therefore, there is no additional
CO2 abatement compared to the Reference Case in The Netherlands in 2040.

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 Scenario 3: Early closure of coal plants reduces long-term emissions by
up to 20% – By closing the remaining coal-fired power plants before 2030,
long-term emissions in 2040 drop additionally by ca. 5 mn. tCO2, which is
equal to ca. 20% of power related emissions in the Reference Case in 2040. If
the two oldest plants are closed in 2020, there is only a long-term effect if
additional abatement measures are implemented at the remaining plants
(Scenario 3e). This is due to the fact that these plants reach the end of their
assumed technical lifetime until 2035.
Figure 11 and Table 6 illustrate the impact of the policy scenarios on the level of
CO2 emissions in 2040.
Figure 11.

CO2 emissions (NL) in 2040

0

5

10

mn. tCO2
15

20

25

Reference Case

30

24

Scenario 1a

21

Scenario 1b

21

Scenario 2

24

Scenario 3a

20

Scenario 3b

20

Scenario 3c

20

Scenario 3d

20

Scenario 3e

21

Scenario 3f

24

Source: Frontier

Table 6.

Differences of annual CO2 emissions in 2040 (NL)

mn.t CO2

Scen.
1a

Scen.
1b

Scen.
2

Scen.
3a

Scen.
3b

Scen.
3c

Scen.
3d

Scen.
3e

Scen.
3f

Difference in
CO2
emissions in
2040

-2.9

-2.9

0.1

-4.4

-4.4

-4.7

-4.4

-2.9

0

%-reduction
compared to
Reference
Case

-12%

-12%

0%

-18%

-18%

-19%

-18%

-12%

0%

Source: Frontier
Note:

frontier economics

Reduction of annual emission compared to the Reference Case

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4.3 System costs and specific abatement costs
In this section, we analyse the impact of the different policy measures / scenarios
on the affordability of the electricity system. For each of the policy scenarios, we
calculate two indicators that inform about the cost impact:
 Impact on the system costs of electricity supply in The Netherlands; and
 Specific abatement costs.

4.3.1 Impact on system costs of electricity supply
The calculation of the impact on system costs of The Netherlands is based on the
methodology described in Frontier (2015).33

Definition of system costs
The system costs include the following cost elements:
 Variable costs of generation include all costs directly incurred by the
production of electricity in the short term, i.e. fuel costs, costs of CO2
certificates and other variable costs of power generation; both for generation
capacities and demand side response;
 Fixed costs of operation of power plants include the costs for investment34,
mothballing, reactivation and fixed operation and maintenance costs of power
generation capacities and demand side response.
 In addition, the system cost includes cost of the assumed RES-E capacity
additions, i.e. investment costs and fixed operation and maintenance costs of
intermittent energy sources, i.e. wind-onshore/offshore and solar PV.
 Credits/debits of power exchange with neighbouring countries have to
be taken into account since otherwise costs of power supply are not assigned
to the countries in which the power is consumed. Credits/debits of power
exchange with neighbouring countries include
□ the costs of electricity imports to the Netherland valued at the wholesale
power price in the country exporting to the Netherlands;
□ as well as the value of exports valued at the wholesale power price in The
Netherlands;
 Grid costs that are associated with the increased deployment of RES-E in
the Dutch electricity system are also taken into account.
System costs are reported as net-present value over the time horizon analysed
(2018-2049)35 and represent an estimate for the efficiency of different policy
measures as compared to the Reference Case. Potential compensation of plant
33

Frontier (2015): Scenarios for the Dutch electricity supply system.

34

It has to be noted that not all cost of the electricity system are included in our estimation: For instance,
capital expenditure / investment costs of existing power plants are not included, as they are regarded as
“sunk costs” in the model. Furthermore, investment costs for replacement investment in de-central CHPgeneration are not included.

35

Assumed social discount rate of 5%.

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RESEARCH OF SCENARIOS FOR COAL-FIRED POWER
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operators for foregone profits in the case of early closure of the coal plants
(Scenario 3) are not part of the system costs since it is irrelevant for the system
costs to which stakeholder costs are allocated or if profits are redistributed.
Furthermore, it is irrelevant for the definition of the system costs, if the the costs
incurred by the additional abatement measures implemented at the plants
(Scenario 1, 3 c-e) are compensated by the state or not – only additional capacity
and fuel costs are taken into account independent of allocation of costs to
stakeholders.
Potential costs for alternative heat sources are not included in the system costs
as calculated below.

System costs in the Netherlands
The policy measures analysed have the following impact on the costs of the
Dutch electricity supply:
 Scenario 1: Additional abatement measures at the plants increase
system costs by 1.4 – 2.1 bn. EUR (real, 2015) – If additional abatement
measures are implemented at the Dutch coal plants, system costs in The
Netherlands (NPV, 2018-2049) increase by 1.4 to 2.1 bn. EUR compared to
the Reference Case. This increase is driven by two effects:
□ Higher variable and fixed costs of power plants due to the abatement
measures that have been implemented ; and
□ The impact of higher costs on the operation of the power plants (if costs
are borne by the companies): Average utilisation decreases by ca. 20% in
2025 compared to the Reference Case and one of the coal plants built in
the 1990s ceases operation earlier than in the Reference Case (Scenario
1a).
In the case of Scenario 1a, power generation from the Dutch coal plants
decreases slightly since the abatement costs are borne by the plant
operators. Therefore, total variable cost of power generation in The
Netherlands decreases moderately (less domestic generation) while costs for
imports from other countries and fixed costs for earlier reactivation of power
plants increase.
In Scenario 1b absolute generation from biomass increases slightly compared
to Scenario 1a since power companies face no additional costs from higher
co-firing of biomass. However, economically additional costs from co-firing
have to be taken into account even if these costs are assumed to be
compensated by the state. Total system costs in The Netherlands increase in
this case by 2.1 bn. EUR (real 2015, NPV 2018-2049).36
 Scenario 2: System costs of Carbon Price Floor depend on accounting
for increase in CO2 price – The introduction of a Carbon Price Floor directly
influences the variable costs of power generation through higher (variable)
costs for CO2 allowances. In addition, there is an indirect effect of changing
36

If companies would be compensated for the full additional fuel and investment costs the compensation
would amount to 2.1 bn. EUR (NPV 2018-2049) in total. However, companies also benefit from (slightly)
higher wholesale power prices which might be taken into account when calculating the compensation.

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the supply structure in The Netherlands, because the Carbon Price Floor
leads to additional domestic power generation in The Netherlands and earlier
reactivation of mothballed gas plants. Both factors increase system costs. The
increase of costs is partially offset by higher credits for power exchange,
reflecting an increase of power exports to neighbouring countries. Overall
system costs increase by 4.2 bn. EUR (real, 2015).
The increase of variable costs, however, can be interpreted as a financial
transfer from households and other consumers to the state (and to a lesser
extent to producers) and does not reflect a “real” increase in costs in a narrow
sense. If the system cost is corrected for additional state income generated by
the Carbon Price Floor (taking into account CO2 emissions incurred by higher
exports to neighbouring countries), additional system costs of the Carbon
Price Floor in the Netherlands amounts to 0.3 bn. EUR from 2018-2049
(NPV). The additional state income amounts to ca. 3.9 bn. EUR.
 Scenario 3: Largest impact on system cost if plants close before 2020 –
Closing the Dutch coal plants before 2020 or 2025 influences the supply
structure of the Dutch power system. Domestic generation decreases in total
and more electricity needs to be imported from neighbouring countries in
hours when the price is high. Therefore, debits for higher imports more than
offset the decrease in variable generation costs. Saved fixed costs by closing
the coal plants are almost completely offset by higher fixed costs incurred
from earlier reactivation and investment in gas-plants. Further, additional
RES-E investment in the long-run increase the cost incurred by the gridintegration of these additional investments.
□ If all plants close until 2020, system costs increase by 7 bn. EUR (real,
2015, NPV 2018-2049) or 8.8% compared to the Reference Case.
□ If closure of all plants is postponed to 2030 and additional abatement
measures are implemented after 2025, costs increase by 4.5 bn. EUR
(5.6%) compared to the Reference Case.
□ Closure of the two oldest plants increases system costs by 1.1 bn. EUR
(1.3%) (Scenario 3f). If additional abatement measures are implemented
at the plants, costs increase by 2.1 bn. EUR (2.7%) (Scenario 3e).

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Figure 12.

Impact on system costs (NL)

14

RES-E related grid
costs

12

Net present value ( bn. EUR)

10
8

Credits/debits for
power exchange

7.1
6
4.2

4

4.2

4.5

3.1
2

1.4

0

Fixed costs of
generation

2.1

2.1

1.1

0.3

-2

Variable costs of
generation

-4
-6

Total system costs

Source: Frontier
Note:

Difference of system costs to the Reference Case (NPV, 2018-2049)
* Additional “CO2 costs” (state income) of ca. 3.9 bn. EUR .
Subsidies for co-firing that are saved due to early closure are assumed not to be spent elsewhere

Table 7.

Impact on system costs in The Netherlands

bn. EUR
(NPV 20182049)

Total system
costs

Variable
costs of
generation

Fixed costs
of
generation

RES-E
related grid
costs

Credits/debits
for power
exchange

Scenario 1a

1.4
(1.7 %)

-0.2

0.2

0.0

1.4

Scenario 1b

2.1
(2.6 %)

2.15

0.47

-0.04

-0.50

Scenario 2

0.3
(0.4 %)

1.2

0.5

0.0

-1.4

Scenario 2*

4.2
(5.2 %)

5.1

0.5

0.0

-1.4

Scenario 3a

7.1
(8.8 %)

-4.2

0.0

0.3

10.9

Scenario 3b

4.2
(5.2 %)

-3.6

0.7

0.3

6.7

Scenario 3c

4.5
(5.6 %)

-3.2

0.7

0.3

6.8

Scenario 3d

3.1
(3.9 %)

-0.3

1.1

0.3

2.1

Scenario 3e

2.1
(2.7 %)

-0.9

-0.1

0.0

3.1

Scenario 3f

1.1
(1.3 %)

-0.9

-0.3

0.0

2.3

Source: Frontier
Note:

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* Additional “CO2 costs” (state income) of ca. 3.9 bn. EUR are included

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Policy measures in The Netherlands also affect system costs in
neighbouring countries
Political interventions and policy measures in one country have an impact on
neighbouring and interconnected power markets. Therefore, additional climate
policy measures in The Netherlands affect the costs of the electricity supply in all
modelled countries.37 In addition, the Carbon Price Floor in Scenario 2 does not
only affect the costs for CO2 allowances in The Netherlands but also in all other
countries of the Pentalateral Forum.
The effects on system costs in the modelled region can be summarised as
follows (Table 8).
 Scenario 1: Small increase of system costs in neighbouring countries –
The structure and the operation of interconnected power markets is only
affected if the costs of additional abatement measures are included in the
firm’s decisions to dispatch the power plant (see Section 4.2.2). In that case
(Scenario 1a), system costs in all modelled countries, incl. The Netherlands,
increase by 2.3 bn. EUR (real 2015, NPV 2018-2049) or 0.3%. If costs are not
borne by the companies (Scenario 1b), total system costs increase slightly by
2.8 bn. EUR (real 2015, NPV 2018-2049).
 Scenario 2: Carbon Price Floor increases variable costs significantly –
The introduction of a Carbon Price Floor significantly affects the variable costs
of power generation of a majority of the power plants in the Central-Western
Europe. Consequently, the total increase in system costs in all modelled
countries is high at about 36 bn. EUR (real 2015) (NPV 2018-2049). As
described above, the increase in variable costs can be interpreted as a
financial transfer to the state and does not reflect a “real” increase in costs in
a narrow sense. If the system cost is corrected for additional state income
generated by the CPF, additional system costs of the CPF amounts to 9 bn.
EUR from 2018-2049 (NPV). The additional state income amounts to ca. 27
bn. EUR.
 Scenario 3: Coal phase-out increases overall European system costs –
In addition to the costs incurred in The Netherlands, phasing-out coal-fired
generation before 2020 leads to higher power generation in neighbouring
countries and therefore higher costs in these countries as well (Scenario 3a: +
1%). If closure is postponed to later years and combined with additional CO2
abatement measures at the coal-fired power plants in the Netherlands
(Scenarios 3c, 3d), the impact on overall system costs in the EU is lower.
If no additional abatement measures are implemented, the closure of the two
oldest plants leads to an overall increase of system costs in the modelled
countries (incl. The Netherlands) of 1.4 bn. EUR. With additional measures,
the overall increase of system costs is 3.1 bn. EUR (NPV 2018-2049).

37

EU system costs include fixed and variable costs of operation, CAPEX for new investment and costs of
power exchange with other modelled regions. Grid costs are not part of the definition. NL, DE, BE, FR, AT,
CH, DK, CZ, PL, IT

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Table 8.

Impact of policy measures on EU system costs*
Scen.
1a

Scen.
1b

Scen.
2

Scen.
3a

Scen.
3b

Scen.
3c

Scen.
3d

Scen.
3e

Scen.
3f

Difference in
system costs
(NPV 20182049)

2.3

2.8

9.4

7.9

6.0

5.1

3.6

3.1

1.4

%-difference
compared to
Reference Case

0.3%

0.4%

1.2%

1.0%

0.8%

0.7%

0.5%

0.4%

0.2%

Source: Frontier
Note:

* EU system costs include fixed and variable costs of generation (incl. Capex for investment) as well
as costs of power exchange with satellite regions.

4.3.2 Specific abatement costs
Specific CO2 abatement costs can be calculated by relating the difference in
system costs to the achieved additional CO2 emission reduction. In effect, the
specific abatement costs thereby provide a measure for the average costs
incurred for the abatement of one ton ofCO2, and thereby provide insight into the
cost-effectiveness of a specific policy scenario. In the following, we differentiate
between:
□ Domestic abatement costs – Additional system costs in The Netherlands
(NPV) are divided by the domestic additional CO2 reduction (aggregated
from 2018 to 2049). The increase of emissions from other Dutch plants is
included in this calculation.
□ Net EU abatement costs in the region – Additional system costs in
modelled regions (NPV) are divided by the additional CO2 reduction in all
modelled countries (aggregated from 2018 to 2049).
The specific CO2 abatement costs calculated cannot be compared to actual CO2
prices in the EU ETS. In our calculation discounted system cost are divided by
accumulated emissions (from 2018-2049). Furthermore, the calculated specific
abatement costs are average costs per abated tonne of CO2, while prices in the
EU ETS can be interpreted as marginal abatement costs.
The policy measures result in specific abatement costs as shown in Figure 13:
 Scenario 1: Additional abatement measures at the plants amount to 8 –
19 EUR/tCO2 – In Scenario 1a, the domestic abatement costs amount to 8
EUR/tCO2. If costs and the impact on emissions in neighbouring countries
are taken into account the net EU abatement costs increase to 18.6
EUR/tCO2, especially due to the “export” of emissions abroad. If the costs of
emission abatement measures are not included in the firm’s cost base
(Scenario 1b), the domestic abatement costs are 13 EUR/tCO2, while net EU
abatement costs increase moderately to 18.7 EUR/tCO2, as less emissions
are “exported” abroad.
 Scenario 2: Specific abatement costs of the Carbon Price Floor depend
strongly on system cost definition – The introduction of the Carbon Price

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Floor reduces emissions in The Netherlands at a cost of 73 EUR/tCO2 if the
increase of the CO2 price is interpreted as a cost. The net EU abatement
costs amount to 90 EUR/tCO2 in this case.
However, if the transfers to the state are not taken into account as a cost,
specific abatement costs decrease to 5 EUR/tCO2 in The Netherlands and to
23 EUR/tCO2 from a European perspective. In this case, the large difference
between the specific abatement costs in the Netherlands and costs on
European level results from the relatively low emission intensity of Dutch
electricity supply compared to e.g. Germany. Therefore, the increase of CO2
prices influences the costs of electricity supply in The Netherlands to a lesser
extent.
 Scenario 3: Closure of coal plants with higher net abatement costs –
Closing the Dutch coal plants in 2020 reduces domestic emissions at the
costs of ca. 22 EUR/tCO2. From a European perspective, the specific
abatement costs increase significantly to 90 EUR/tCO2 due to the lower netreduction achieved as compared to the domestic emission reduction in The
Netherlands. If closure is postponed to 2025, the costs decrease to 16
EUR/tCO2 from a Dutch perspective and to 73 EUR/tCO2 from a European
perspective.
Closure of the plants until 2030 and the implementation of additional
abatement measures incur costs of 19 EUR/tCO2 in The Netherlands and 45
EUR/tCO2 in all modelled countries. With closure of the plants until 2040, the
specific abatement costs in The Netherlands and the EU decrease to 16 and
28 EUR/tCO2 respectively.
Closing the two oldest plants until 2020 and implementing additional
abatement measures at the newer plants incurs costs of 10 EUR per tCO2
abated in The Netherlands. If higher emissions in neighbouring countries due
to substitution from the closure of the two coal plants are taken into account,
net EU abatement costs increase to 28 EUR/tCO2. If no additional abatement
measures are implemented at the remaining plants, costs in The Netherlands
increase to 27 EUR/tCO2 and to 119 EUR/tCO2 from a European perspective.
The reason for the relatively high specific net EU abatement costs in Scenario
3f , is that around 80% of emission reduction in The Netherlands is offset by
higher emissions elsewhere in the modelled region.

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Figure 13.

Specific emission abatement costs EUR(real, 2015)/tCO2
Domestic abatement costs (EUR/tCO2)
Scenario 1a

8

19
13

Scenario 1b
Scenario 2

19
5
23
73

Scenario 2*

90
22

Scenario 3a

91

Scenario 3b

16

Scenario 3c

19

Scenario 3d

16

Scenario 3e

Scenario 3f

Net EU abatement costs (EUR/tCO2)

73
45
28

10
28
27
119

Source: Frontier
Note:

Specific abatement costs have been calculated based on NPV of system costs differences and the
accumulated sum of emission reduction (2018-2049).
* Including cost increase related to the Carbon Price Floor (additional state income generated by
CPF)

4.4 Impact on power prices
In this sub-section, we analyse the changes in power prices in the different policy
scenarios compared to the Reference Case. In the following, we describe the
impact of the policy measures on:
□ Wholesale prices for electricity in The Netherlands; and
□ Electricity prices in Central-Western Europe.

Impact on wholesale price of electricity in The Netherlands
The impact of the modelled policy measures on the power prices in The
Netherlands can be summarised as follows:
 Scenario 1: Limited influence of abatement measures on power prices –
Implementing additional abatement measures at the Dutch coal plants affect
the power prices in The Netherlands only to a limited extent. The maximum
increase amounts to 0.8 EUR (real, 2015)/MWh in 2030 (Scenario 1a). If the
costs of the emission reduction are not taken into account in the plants
operation (Scenario 1 b), there is almost no impact on power prices.
 Scenario 2: Carbon Price Floor with significant impact on short-term
power price development – The introduction of a Carbon Price Floor in the
countries of the Pentalateral Forum influences the short-run marginal costs of
almost all conventional power plants in Central-Western Europe since CO2
certificates are variable costs from a power generator perspective.
Consequently, the impact on power prices is relatively high and amounts to
12 EUR(real, 2015)/MWh in 2018 and decreases with the phasing-out of the
price support in 2040.

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 Scenario 3: Early closure of coal plants increases wholesale power
prices by up to 4 EUR(real, 2015)/MWh – The decommissioning of all Dutch
coal plants before 2020 leads to an increase of power prices by 4 EUR(real,
2015)/MWh in 2020. If plants close at a later stage and if additional
abatement measures are implemented at the plants, prices increase at a later
date and to a lesser extent. If the two oldest power plants are closed until
2020, the short-term price effect amounts to 0.9 EUR(real, 2015)/MWh in
2020.
Figure 14 and Table 9 summarise the impact of the different policy scenarios on
Dutch electricity prices.
Figure 14.

Impact on power prices (NL)

14
Scenario 1a
12
Scenario 1b

EUR(real, 2015)/MWh

10

Scenario 2

8

Scenario 3a

6

Scenario 3b
Scenario 3c

4

Scenario 3d
2
Scenario 3e

0
2015

2018

2020

2025

2030

2035

2040

Scenario 3f

-2
Source: Frontier
Note:

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Table 9.

Wholesale prices of electricity in The Netherlands

EUR(real,
2015)/MWh

2018

2020

2025

2030

2035

2040

Reference Case

35.3

39.3

54.6

61.3

70.0

66.7

Scenario 1a

35.3

39.4

54.9

62.1

70.2

66.9

Scenario 1b

35.3

39.4

54.6

61.2

70.1

66.9

Scenario 2

47.4

49.8

62.3

64.8

71.8

66.7

Scenario 3a

35.2

43.4

57.0

64.9

71.1

67.3

Scenario 3b

35.2

39.3

57.0

64.9

71.1

67.3

Scenario 3c

35.2

39.4

54.8

64.9

71.1

67.3

Scenario 3d

35.3

39.4

54.9

62.1

70.2

67.2

Scenario 3e

35.3

40.2

55.3

62.4

70.2

66.9

Scenario 3f

35.3

40.2

55.1

61.9

70.0

66.7

Source: Frontier

Impact on wholesale price of electricity in neighbouring countries
(example: Germany)
The policy scenarios examined in this study influence the dispatch of power
plants not only in The Netherlands, but also in other countries either directly
(through the Carbon Price Floor) or indirectly through interconnections and power
exchange with The Netherlands. Therefore, power prices in neighbouring
countries are also affected by the introduction of national climate policy measures
in The Netherlands or coordinated measures in the Pentalateral forum. As an
example, Table 10 shows the impact of the different policy measures on power
prices in Germany.
 Scenario 1: Small increase of power prices in Germany – Power prices in
Germany increase moderately due to the implementation of abatement
measures at Dutch coal plants. The maximum increase of wholesale prices
amounts to 0.7 EUR(real, 2015)/MWh as compared to 0.8 EUR(real,
2015)/MWh in The Netherlands in 2030. Prices in Germany increase due to
lower utilisation of Dutch coal plants and consequently lower net-imports from
The Netherlands.
 Scenario 2: Germany affected to a greater extent by Carbon Price Floor
– Due to the higher emission intensity of the German power plants, the price
increase following the introduction of the Carbon Price Floor if higher than in
The Netherlands (14.9 EUR(real, 2015/MWh in 2018; which is 2.9 EUR higher
than in The Netherlands). The Carbon Price Floor also leads to an earlier
converging of wholesale power price levels in Germany and The Netherlands
(average price difference in 2018 decreases from 3 to 0.1 EUR/MWh).

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 Scenario 3: Dutch coal phase-out increases German power prices by up
to 3 EUR/MWh – The closure of coal-fired power plants has the most
significant impact on German power prices in the period from 2030 when the
supply demand balance is becoming tighter. The German power prices
increase by 3.2 EUR(real, 2015)/MWh in 2030 following the closure of the
Dutch coal plants (in 2020, 2025 or 2030, Scenarios 3a – 3c).
□ If the coal-fired plants are closed in 2020 (Scenario 3a), there is only a
very limited impact on German power prices as compared to the 4 Euro
increase of Dutch power prices in 2020 as additional plants in the
Netherlands are reactivated and less generation needs to substituted
abroad. Consequently, the price difference between Germany and The
Netherlands in 2020 grows from 0.6 EUR(real, 2015)/MWh in the
Reference Case to 3.8 EUR (real, 2015)/ MWh in Scenario 3a.
□ If the two oldest power plants close until 2020 (without implementation of
additional measures at the remaining plants), prices in Germany increase
by up to 0.5 EUR(real, 2015)/MWh. The impact is relatively low due to the
limited amount of power generation shut down in the European context.
Table 10.

Impact on wholesale power prices in Germany

EUR(real,
2015)/MWh

2018

2020

2025

2030

2035

2040

Scenario 1a

0.0

0.0

0.3

0.7

0.2

0.1

Scenario 1b

0.0

0.0

0.0

0.0

0.1

0.1

Scenario 2

14.9

11.0

7.8

3.5

1.7

0.0

Scenario 3a

0.0

0.8

2.2

3.2

1.0

0.4

Scenario 3b

0.0

0.0

2.2

3.2

1.0

0.4

Scenario 3c

0.0

0.0

0.2

3.2

1.0

0.4

Scenario 3d

0.0

0.0

0.3

0.7

0.1

0.4

Scenario 3e

0.0

0.4

0.7

0.9

0.2

0.1

Scenario 3f

0.0

0.4

0.5

0.5

0.0

0.0

Source: Frontier
Note:

Increase of the yearly average (base price) in Germany compared to the Reference Case

4.5 Impact on consumers
The increase of power prices in The Netherlands described in Section 4.4
increases costs for final consumers. In the following section, we describe the
impact of the policy scenarios on consumer payments for households and
business customers.

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4.5.1 Methodology
The analysis focusses on the consumer payments arising from the consumption
of electricity and additional costs incurred by the expansion of renewable
electricity. We include the following cost elements in the calculations:
 Costs for electricity – The costs of electricity supply that have to be paid by
consumers are calculated based on the hourly electricity consumption and
hourly power prices. We assume that changes in the wholesale power prices
are passed on without distortions or mark-ups through retail-services onto
final consumers.
 Costs of renewable electricity – The costs of renewable electricity (windonshore, wind-offshore and solar PV) are included as the difference between
total costs of renewables and the market revenues, i.e. the additional financial
support needed to obtain the targeted capacity levels. We assume that all
additional RES-E costs are passed onto final consumers, i.e. caps on RES-E
subsidies (cap by RES-E budgets) are not taken into account in the analysis.
Furthermore, RES-E related grid costs are included as additional cost
element.38
In our analysis, we differentiate between households and other (business/public
service or industrial) consumers. The calculation of costs for both customer
groups is based on the following assumptions:
□ Changes in the wholesale electricity prices are passed-on to customers
without distortions from retailers, i.e. retailers set tariffs on a cost basis;
□ The policy scenarios do not affect other taxes / levies apart from VAT for
households and the potential impact of wholesale price movements on
RES-E support;
□ The analysis does not include costs arising from enforcement or
replacement investment in the power transmission and distribution grids
that are not directly related to the connection of RES-E; and
□ Costs for renewable support are passed on to both consumer groups,
based on their share of total consumption.
 The consumer payments for electricity are derived from two different
consumption profiles for hourly consumption:
□ Household consumption varies over the course of the day according to
a typical consumption profile. Consumption on weekends is lower than on
weekdays as well as higher in the winter/autumn than in the summer; and
□ Consumption from the public sector, businesses and industrial
customers varies to a lower extent than consumption from households.
While it is apparent that this is quite a diverse group, we have tested a flat
consumption pattern for other consumers (which is more appropriate e.g.
for industrial consumers), and results do not vary significantly in that case.

38

Methodology based on Frontier (2015).

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Total net-power demand is divided into these two consumer groups based on the
historical split between household electricity consumption39 (20%) and “business
and industrial consumers” (80%).
Figure 15.

Assumed consumption profiles

Households
Week-day Winter

Businesses and industrial customers
Week-day Winter

Week-end Summer

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
hour of the day

1

2

3

4

5

6

7

8

Week-end Summer

9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
hour of the day

Source: Frontier

39

CBS Stateline “Energy consumption households; energy commodities”, 84.43 PJ in 2013.

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SYSTEM COSTS VS. CONSUMER PAYMENTS
Two indicators, System Costs and Consumer Payments, are used in this analysis to
provide insight into the impact of the different policy measures on the affordability of the
electricity system.
The indicators provide different information:
 System costs inform about the efficiency of a power system, i.e. what are the costs
to society to serve demand in a given region, in this case in The Netherlands. The
distribution of benefits, rents and costs between stakeholders (consumers,
producers, the state) is not relevant for the total sum of system costs.
 Consumer payments inform about the costs of electricity supply for the consumer
(the consumer bill) and thereby show distributional effects of policy measures. That
means that due to higher system, an increase in consumer payments can incur
costs, as well as higher rents for producers, higher state income (taxes, levies) or a
mix of these factors.
Figure 16 illustrates the difference between both concepts based on a simplified
example of one hour of electricity supply (merit order). In the figure below, the system
costs to cover demand are given by the costs of all operating power plants (blue dashed
area “A”). These costs are inter alia included in the definition of System Costs. The costs
to final consumers in that case, however, are given by the area “A” and the area “B” due
to the principle of “uniform pricing”. Therefore, the consumer payments also include rents
for power suppliers in addition to their generation costs.

Figure 16.

System costs vs. consumer payments

System costs

Consumer payments

EUR

EUR

Demand

Market
clearing
price

Demand

Market
clearing
price

A

B
A

MW

MW

Source: Frontier

4.5.2 Results
In the following, we describe the impact of the different policy measures on the
payments of consumers for electricity supply in the Netherlands. As described in
Section 4.4, the policy measures affect the wholesale power prices in the
Netherlands to a varying extent. As a consequence, the costs to consumers are
affected differently in the individual scenarios:
 Scenario 1: Comparably low impact of additional abatement measures
on consumers – The implementation of additional abatement measures
increases costs for households by 0.1 bn. EUR (+ 0.3%) (NPV 2018-2049)
and for other customers by 0.2 bn. EUR (+0.2%), assuming that no
compensation for the implementation of additional measures is granted to the

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plant operators. The financing of state payments to the coal plant operators is
not taken into account in the calculation since it is unclear where the financing
would come from.
 Scenario 2: Carbon Price Floor increases consumer payments by 8-10%
- The Carbon Price Floor has the largest impact on power prices and
consequently also on the costs for electricity paid by final consumers.
Assuming that additional state income from the increase in CO2 prices40 is not
re-distributed to final consumers, costs for households increase by 2 bn. EUR
(10%) and for other consumers by 6.4 bn EUR (8%).
The power price related increase in consumer payments is in both cases
partially offset by lower support requirements for RES-E since the difference
between the levelised costs of RES-E on one hand and wholesale power
prices on the other hand is lower than in the Reference Case.
 Scenario 3: Early closure of coal plants increases consumer payments
by 3-4% - Closing all 5 coal plants until 2020 increases prices by up to 4
€/MWh and consequently the costs for households in The Netherlands
increase by ca. 0.9 bn EUR (4%). Costs for other consumers increase by 2.6
bn EUR (3%). Closure in 2025 lowers the cost increases for households and
other consumers to 0.5 bn. EUR (2.4%) and 1.5 bn. EUR (1.9%), respectively
(Scenario 3b).
If, in addition to the decommissioning of plants until 2030, supplementary
abatement measures are implemented at the plants in 2025, costs for
households increase by 0.3 bn. EUR (1.6%) and for other consumers by 1 bn.
EUR (1.3%) compared to the Reference Case (Scenario 3c).
Closing the two oldest coal-fired plants until 2020 (no additional abatement
measures) increases costs to households by 0.16 bn. EUR (0.7%) and for
other consumers by 0.45 bn. EUR (0.6%) (Scenario 3f). If additional
abatement measures at the remaining plants are implemented, costs increase
by 0.2 bn. EUR (0.9%) for households and by 0.6 bn. EUR (0.7%) for other
consumers (Scenario 3e).
Figure 17 and Figure 18 show the impact of the different policy scenarios on the
electricity costs of “households” and “business and industrial consumers”. 41

40

According to our calculations, the additional state income could amount to ca. 4 bn. EUR.

41

Higher prices for CO2 prices also affect the surplus of power generators (defined as operating profit): Rents
of producers with low carbon intensity increase (e.g. RES-E, nuclear) by ca. 110 bn. EUR (NPV 2018-2049,
all modelled countries) as these producers profit from higher average power prices without having to pay
additional costs for CO2. Surplus of conventional fossil-fuelled generation in all modelled countries increases
by 9 bn. EUR (NPV 2018-2049) while surplus of fossil fuelled generation in the PLEF region (affected by
Carbon Price Floor) decreases by 5 bn. EUR (NPV 2018-2049). Therefore, there is a redistribution of rents
from fossil fuelled power generation in the PLEF region to low-carbon power supply and to producers
outside of the PLEF (not affected by higher costs).

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Figure 17.

Impact on electricity
(households)

payments

of

final

consumers

4
RES-related
payments
(incl. RES-E
related grid
costs)

3

bn. EUR (real, 2015)

3
2.1

2
2
1
1

Energy
payments

0.9
0.5
0.4
0.1

0.0

0.2

0.2

0.2

0
Total
consumer
payments

-1

-1

Source: Frontier
Note:

Difference to the Reference Case (NPV, 2018-2049)

Figure 18.

Impact on electricity payments of final consumers (“business
and industrial consumers”)

10

RES-related
payments (incl.
RES-E related
grid costs)

bn. EUR (real, 2015)

8
6.4

6
4

Energy
payments

2.6
1.5

2
0.2

1.0

0.0

0.6

0.6

0.5

0

Total consumer
payments

-2
-4

Source: Frontier
Note:

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Difference to the Reference Case (NPV, 2018-2049)

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Table 11 and Table 12 show the impact on yearly costs in the photo years in
absolute cost figures and percentage increase compared to the Reference Case.
Table 11.
mn. EUR
(%)

Impact on yearly costs to consumers (households)
2018

2020

2025

2030

2035

2040

Scenario 1a

0
(0 %)

1
(0 %)

3
(0 %)

17
(1 %)

2
(0 %)

1
(0 %)

Scenario 1b

0
(0 %)

1
(0 %)

0
(0 %)

0
(0 %)

1
(0 %)

1
(0 %)

Scenario 2

230
(19 %)

188
(14 %)

127
(8 %)

41
(2 %)

20
(1 %)

0
(0 %)

Scenario 3a

-4
(0 %)

78
(6 %)

47
(3 %)

82
(5 %)

12
(1 %)

7
(0 %)

Scenario 3b

-4
(0 %)

0
(0 %)

47
(3 %)

82
(5 %)

12
(1 %)

7
(0 %)

Scenario 3c

-4
(0 %)

1
(0 %)

-1
(0 %)

82
(5 %)

12
(1 %)

7
(0 %)

Scenario 3d

0
(0 %)

2
(0 %)

13
(1 %)

19
(1 %)

2
(0 %)

7
(0 %)

Scenario 3e

-2
(0 %)

19
(1 %)

10
(1 %)

24
(1 %)

2
(0 %)

1
(0 %)

Scenario 3f

-1
(0 %)

18
(1 %)

8
(0 %)

16
(1 %)

0
(0 %)

0
(0 %)

Source: Frontier
Note:

Difference to the Reference Case

Table 12.
mn. EUR
(%)

Impact on yearly costs to consumers (other consumers)
2018

2020

2025

2030

2035

2040

Scenario 1a

0
(0 %)

4
(0 %)

12
(0 %)

54
(1 %)

7
(0 %)

4
(0 %)

Scenario 1b

0
(0 %)

4
(0 %)

-1
(0 %)

-1
(0 %)

2
(0 %)

4
(0 %)

Scenario 2

871
(19 %)

707
(14 %)

472
(8 %)

168
(2 %)

77
(1 %)

0
(0 %)

Scenario 3a

-11
(0 %)

283
(6 %)

162
(3 %)

277
(4 %)

48
(1 %)

24
(0 %)

Scenario 3b

-11
(0 %)

0
(0 %)

162
(3 %)

277
(4 %)

48
(1 %)

24
(0 %)

Scenario 3c

-11
(0 %)

4
(0 %)

3
(0 %)

277
(4 %)

48
(1 %)

24
(0 %)

Scenario 3d

0
(0 %)

9
(0 %)

51
(1 %)

63
(1 %)

7
(0 %)

21
(0 %)

Scenario 3e

-6
(0 %)

70
(1 %)

39
(1 %)

76
(1 %)

7
(0 %)

4
(0 %)

Scenario 3f

-5
(0 %)

66
(1 %)

27
(0 %)

49
(1 %)

0
(0 %)

0
(0 %)

Source: Frontier
Note:

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4.6 Security of Supply and import dependency
In the following, we analyse the impact of the policy measures on Security of
Supply in The Netherlands by analysing reserve margins of power generation
and the import dependency of The Netherlands.
It has to be noted that we do not expect major challenges to Security of Supply of
The Netherlands in the Reference Case. There is sufficient power generation
capacity available in the Netherlands (including mothballed power plants) as well
as in surrounding countries. In the medium term, mothballed power plants can be
re-activated if required. However, reactivation of mothballed power plants will
depend on the view owners of these plants have on the future of the energy
market. Further, the power system is getting more flexible due to increased
demand side response. A more detailed analysis and assessment of Security of
Supply in the electricity system in The Netherlands can be found in Frontier
(2015).42

4.6.1 Methodology
We analyse the impact of the policy measure on Security of Supply using the
indicators of power generation adequacy, and import dependency:
 Reserve Margins (RM) inform about the level of de-rated43 generation
capacity compared to peak load. It has to be noted that this indicator only
provides a national perspective and does not directly take into account
contributions from interconnected countries.44
 Import dependency – The import dependency from foreign countries is
assessed by the development of net-imports from other countries to The
Netherlands.

4.6.2 Results
The policy measures have the following impact on Dutch Reserve Margins and
import dependency.

Impact on Reserve Margins in The Netherlands
The policy measures have the following impact on the Reserve Margins in The
Netherlands:
 Scenario 1: Only very moderate impact on Reserve Margin by additional
abatement measure at the power plants – Implementing additional
abatement measures at the Dutch coal-fired power plants after 2025 does not
affect the adequacy of domestic generation sources to a large extent. In
Scenario 1a, the RM decreases by 0.6 GW in 2030 due to the earlier
42

Frontier (2015): Scenarios for the Dutch electricity supply system.

43

Used de-rating factors can be found in ANNEX A.

44

An alternative approach to evaluating Security of Supply is represented by the “Loss-of-Load-Expectation”
(LOLE), a stochastic indicator that is for example used in the “Generation Adequacy Assessment” of the
TSOs in the PLEF: Pentalateral Energy Forum Support Group 2 (2015): Generation Adequacy Assessment.

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decommissioning of one coal plant. In the case of Scenario 1b, in which
additional abatement costs are not allocated to the plant operators, there is no
negative impact on the RM.
 Scenario 2: Carbon Price Floor increases Reserve Margins in The
Netherlands – As compared to the scenarios in which coal plants in The
Netherlands are decommissioned, the Carbon Price Floor leads to an
increase of operational capacity in The Netherlands in the short-term: gasplants that are mothballed in the Reference Case stay operational in this
scenario due to cost-advantages compared to carbon-intensive power plants
in other countries of the Pentalateral Forum. The RM increases by 4.8 GW in
2018 and by 3 GW in 2020. In the long-run, with the phasing out of the
Carbon Price Floor in 2040, the RM converges to the levels achieved in the
Reference Case.
Scenario 3: Earlier decommissioning of coal plants temporarily
decreases the RM in The Netherlands – Closing the Dutch coal plant
reduces the RM temporarily by 3.6 GW in 2030 (Scenario 3 a/b/c). However,
since the RM is strongly positive in 2030, we expect no threats to Security of
Supply. Early closure until 2020 (Scenario 3a) reduces the RM in the shortterm (2020) by 1.2 GW. The RM inside the Netherlands is tightened in this
period. However, since there is vast power generation capacity available in
the European power market in the short and medium term, we don’t expect a
threat for Security of Supply in the Netherlands despite the tighter RM.
Furthermore, reactivation of mothballed power plants occurs earlier than in
the Reference Case. However, a short term closure of a high share of power
plants under short notice should be avoided from a Security of Supply
perspective in order to provide sufficient time for the market participants to
react.
Overall, the closure of all or only two (Scenario 3e/f) coal-fired power plants in
The Netherlands is partially compensated by earlier reactivation of mothballed
gas-fired plants or increase investment in the long-run. Taking into account
the available import capacities, the RM remains positive in all sub-scenarios
of Scenario 3.
Figure 19 compares the level of operational capacities (de-rated45) in The
Netherlands in the policy scenarios and the Reference Case.

45

De-rating factors are included in Annexe A.3.

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Figure 19.

Comparison of operational capacities (NL, de-rated*)
Reference Case

30

Scenario 1a

derated-capacity (GW)

25

Scenario 1b
Scenario 2

20
Scenario 3a
Scenario 3b

15

Scenario 3c
10

Scenario 3d
Scenario 3e

5

Scenario 3f
0

Peak Load
2018

2020

2025

2030

2035

2040

Source: Frontier
Note:

* de-rating factors in Annex A.3

Impact on electricity imports and exports
In the Reference Case, The Netherlands will remain a net-importer of power in
the short-term. In the medium- to long-term, however, this picture changes to a
net-exporting position (see ANNEX B). The impact of the different policy
scenarios on the import dependency is determined by the changing supply
structure of the Dutch power system: if domestic power generation increases,
dependency on imports decreases compared to the Reference Case and vice
versa:
Scenario 1: Additional emission reduction at the Dutch coal plants has
limited impact on import dependency – Implementing additional abatement
measures at the Dutch coal plants only has a limited impact on the overall
supply structure of the Dutch power system. If no compensation for additional
costs is granted (Scenario 1a), utilisation of Dutch coal plants decreases
slightly and one of the older units is decommissioned earlier than in the
Reference Case. Net-imports increase by 7 TWh in 2030. On average, netimports increase by 2.6 TWh/a. If the majority of costs are not borne by the
operators (Scenario 1b), there is only a very small increase of net-imports by
2.2 TWh at most in 2025, on average by 1 TWh/a.
 Scenario 2: Carbon Price Floor increases exports to neighbouring
countries –The implementation of a Carbon Price Floor in 2018 in the
countries of the Pentalateral Forum increases Dutch power generation and
exports to neighbouring countries in the short- and medium-term.
Consequently, the dependency on imports decreases compared to the
Reference Case.

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 Scenario 3: Early closure of coal plants increases import dependency in
the short term – The Reference Case is characterised by a medium-term
net-exporting position of The Netherlands. This trend is postponed if the coal
plants cease operation earlier than in the Reference Case and The
Netherlands remain net-importer of power until 2040 (Scenario 3 a/b). On
average, net-imports increase by 14 TWh/a (Scenario 3a). In the case of a
later closure of the plants and if additional abatement measures are
implemented at the Dutch plants, the average dependency on imports
decreases.
Figure 20 shows the level of net-imports in the Reference Case and the different
policy scenarios.
Figure 20.

Net-imports (NL)

25
20

15
10
5

TWh

0
-5
-10
-15
-20
-25

-30
2015

2018

Reference Case
Scenario 3a
Scenario 3e

2020
Scenario 1a
Scenario 3b
Scenario 3f

2025

2030
Scenario 1b
Scenario 3c

2035

2040

Scenario 2
Scenario 3d

Source: Frontier
Note:

Positive values represent net-imports to The Netherlands, negative values net-exports

Table 13 indicates the change of the net-position (net-imports/exports) in The
Netherlands compared to the Reference Case.

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Table 13.

Net-imports (NL) – difference to the Reference Case

GW

2018

2020

2025

2030

2035

2040

Scenario 1a

0.0

0.1

6.4

7.3

1.6

0.6

Scenario 1b

0.0

0.1

3.0

2.3

0.9

0.6

Scenario 2

-10.5

-3.1

5.6

8.2

1.6

-0.3

Scenario 3a

0.0

17.7

26.2

21.7

15.9

4.9

Scenario 3b

0.0

0.0

26.2

21.7

15.9

5.0

Scenario 3c

0.0

0.1

6.4

21.7

15.9

4.9

Scenario 3d

0.0

0.1

6.4

7.3

1.6

4.1

Scenario 3e

-0.3

5.8

11.8

9.4

1.6

0.6

Scenario 3f

-0.2

5.6

7.0

5.6

0.0

0.0

Source: Frontier
Note:

Positive values indicate higher imports / lower exports and vice versa.

4.7 Impact on the development of RES-E
The different policy measures can have an impact on the development of
renewable energy sources in The Netherlands either directly through a changing
framework for biomass co-firing (e.g. further subsidies for co-firing) or indirectly
through a changing market environment (e.g. higher wholesale power prices
leading to earlier market driven investment in RES-E).

Impact on the share of renewable energy sources in The Netherlands
The share of RES-E (expressed in % of net electricity demand) informs about the
share of net-demand that is served by renewable energy sources:
 Scenario 1: Additional abatement measures increase RES-E – The
additional emission reduction achieved in Scenario 1 is largely based on
increased co-firing of biomass in the coal plants. This measure also increases
the absolute amount of RES-E in the system.46 The share of RES-E increases
by up to 7-11%-points in 2030 (+ 8-12 TWh). In the long-run, the amount of
additional co-firing decreases due to market based co-firing already taking
place in the Reference Case (+ 2%-points; + 3 TWh in 2040).
 Scenario 2: No major impact on RES-E in The Netherlands – There is only
a small impact of the Carbon Price Floor on the development of RES-E in The
Netherlands. Although profitability increases, the amount of additional
investment in RES-E is limited (+ 0.5 TWh in 2035).47
46

The 25 PJ/a limit on co-firing of biomass of the Reference Case does not apply to Scenario 1 and Scenario
3 (c,d,e).

47

Absolute investment potentials are limited and potentials already utilised in the Reference Case.

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 Scenario 3: Closure of coal plants reduces RES-E % due to less co-firing
– The closure of all coal plants in Scenario 3a and 3b results in a decrease of
the renewable energy sources of net-demand by up to 6%-points, as no cofiring of biomass takes place in the closed plants in these scenarios. For
Scenarios 3a (plant closures in 2020) and 3b (plant closures in 2025) this
holds also for the already decided subsidised co-firing of biomass in the coal
power plants of up to 25 PJ per year until 2028. Furthermore, if the two oldest
coal-fired plants are closed until 2020 (without implementing additional
measures at the remaining plants), the RES-E share decreases in the shortterm by 2%, also due to lower co-firing of biomass.
It has to be noted that closure of coal plants could free up funds from the
subsidy budget. These funds could be used to subsidise RES-E somewhere
else in the system. We don’t take this possible indirect effect on RES-E policy
into account since we assess decisions to be speculative. In our analysis, an
increase of other RES-E following lower co-firing is therefore not included.
The implementation of additional abatement measures at the plants in the
Scenarios 3c-e leads to a medium-term increase of RES-E (prior to plant
closure) due to higher co-firing of biomass as an element of the additional
measures.
Figure 21.

Renewable energy share of net-demand
Refence Case
Scen3a

Scen1a
Scen3b

Scen1b
Scen3c

Scen2
Scen3d

RES-E share (% of net-demand)

80%
70%
60%
50%
40%
30%
20%
10%
0%
2015

2018

2020

2025

2030

2035

2040

Source: Frontier

Table 14 shows the absolute levels of electricity supply from wind, solar PV and
biomass in the Reference Case as well as in the different policy scenarios.

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Table 14.

Development of net-electricity supply from RES-E

TWh

2018

2020

2025

2030

2035

Reference
Case

26.6

41.1

55.4

53.9

65.9

Scenario 1a

26.6

41.0

60.2

62.3

73.0

Scenario 1b

26.6

41.0

63.7

66.5

73.7

Scenario 2

27.5

41.9

55.8

54.0

69.6

Scenario 3a

26.6

35.2

48.7

53.9

65.6

Scenario 3b

26.6

41.1

48.7

53.9

65.6

Scenario 3c

26.6

41.0

60.2

53.9

65.6

Scenario 3d

26.6

41.0

60.2

62.3

73.0

Scenario 3e

26.6

38.7

56.4

60.8

73.0

Scenario 3f

26.6

38.7

52.7

53.9

65.9

Source: Frontier

4.8 Other indicators
In this section, we describe the impact of the different policy measures on other
indicators:
 Impact on other emissions (Section 4.8.1);
 Impact on heat networks (Section 4.8.2);
 Impact on innovation (Section 4.8.3);
 Effects on employment (Section 4.8.4).

4.8.1 Impact on other emissions
In the following, we assess the impact of the different policy measures on the
emission of
□ Sulphur-dioxide (SO2);
□ Nitrogen Oxides (NOx);
□ Particulate Matter (PM); as well as
□ Mercury (Hg).
The assessment is based on plant specific emission factors provided by the plant
operators. The decrease of emissions from coal-fired power generation at the five
power plants is netted against an increase of emissions from other domestic
generation (gas-fired power plants):

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 Other emissions from coal-fired power plants in The Netherlands – The
emissions of the above mentioned pollutants is determined by the specifics of
the individual plants. Figure 22 shows that there are significant differences
between the five coal plants under consideration. For example, new plants
emit significantly less SO2 than older ones due to additional desulphurization
of exhausts.
Figure 22.

Emission factors of coal plants in the Netherlands
NOx
300

250

250

200

200

g/MWh_el

g/MWh_el

SO2
300

150

150

100

100

50

50

0

0

Hg
8

14

7

12

6

10
8
6

kg/MWh_el

g/MWh_el

PM
16

5
4
3

4

2

2

1

0

0

Source: Frontier based on company information
Emission factors are ranked from the largest to the smallest value.

 Domestic substitution of emission from coal plants – If power generation
from the coal plants decreases due to either less utilisation or due to complete
decommissioning, the omitted power supply has to be substituted by
alternative production. The substitution takes partly place within The
Netherlands and pre-dominantly by gas-plants. Therefore, the amount of
additional emissions from gas-plants in The Netherlands needs to be taken
into account. Other emissions from gas-plants partially depend on the
technical capabilities of the specific plants. In our calculations, we assume a
uniform emission factor for gas plants: 48
□ 0 g SO2/MWhel;
□ 155 g NOx/MWhel;
□ 0.7 g PM/MWhel; and
□ 0.5 kg Hg/MWhel.
 Substitution of emission in other countries – A share of reduced power
generation from coal-fired power plants is served by higher imports / lower
exports. Consequently, power generation and emissions in other countries
increases. The specific emissions per unit of electricity produced depend on a
multitude of factors including for example, country specific legal limitations for
emissions and the age of the power plants affected. The exact specification of

48

Partly based on Ministerie van Economische Zaken (20.04.2016): Beantwoording over het onderzoek
'Sluiting kolencentrales' van SEO in opdracht van Natuur & Milieu.

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these emissions goes beyond the scope of this study and therefore we limit
ourselves to general qualitative statements about this effect.
 Other emissions from biomass co-firing – Further, the emission of the coal
plants depends on the assumed emission intensity of biomass co-firing. The
emissions are, among other things, substantially determined by the type of
biomass used for co-firing. Biomass, for example can lower the NOx or SO2
emission of a co-firing plant.49 Depending on the type of biomass used for cofiring up to 90% of particulate matter emission can be reduced. Co-firing of
wood-chips (the pre-dominant form of co-firing in coal plants), however, is
said to have a small impact on PM emissions, but reduces the emission of
metals like mercury (Hg).50
For the following calculations, we use indicative / exemplary values from
secondary sources: Specific SO2, NOx and PM emissions of biomass are
based on CE Delft (2015).51 Assumptions on mercury emissions of biomass
are taken from Coa et al. (2008).52
Table 15 summarises the emission factors assumed in this analysis.
Table 15.
Coal (range)
(g/MWhel)
Biomass cofiring (range)
(g/MWhel)
Gas plants
g/MWhel

Calculation of other emissions
SO2

NOx

PM

Hg

44 – 256

153 - 248

1 – 14

0.004 – 0.007

7 - 39

34-55

0.6 - 6

0.0005-0.0011

0

155

0.7

0.0005

Source: Frontier

Impact on other emissions
Figure 23 shows the development of other emissions in the different scenarios
for the different gases.
 Scenario 1: Additional abatement measures at the plants – Scenario 1 is
characterised by a significant increase in the share of biomass co-firing. The
implementation of the additional abatement measures at the plants therefore
influences the overall emission levels to the extent to which biomass co-firing
lowers the emissions of the plants. In addition, if costs of abatement
measures are borne by the companies, emissions decrease due to lower
utilisation (partially offset by higher emission from gas-plants):

49

Henderson (2015): Cofiring of biomass in coal-fired power plants – European perspective;
IEA Clean Coal Centre (2010): Profiles – Emission from co-firing coal, biomass and sewage sludge (PF 1016)

50

Al-Naiema et al. (2015): Impacts of co-firing biomass on emissions of particulate matter to the atmosphere,
Fuel, Vol. 162, p. 111-120.

51

CE Delft (2015): Kentallen voor grijze en ‘niet-geoormerkte stroom’ inclusief upstream-emissies, Delft,
January 2015).

52

Cao et al. (2008): Mercury Emissions during Cofiring of Sub-bituminous Coal and Biomass; Environmental
Science & Technology (2008), Vol. 42 (24), p. 9378-9384.

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□ High reduction of SO2, PM and Hg due to biomass co-firing and no or
limited additional emissions from gas plants;
□ NOx emissions affected to limited extent due to compensating increase of
gas-fired generation and emissions from these plants;
Due to the fact that scenarios 1a and 1b lead to limited additional generation
in other modelled countries, it can be assumed that the increase of other
emissions in these countries is also limited.
 Scenario 2: Carbon price floor - The carbon price floor increases gas-fired
generation in The Netherlands in the short- to medium-term while utilisation of
coal-plants decreases slightly. Consequently, emissions of all other pollutants
decrease in the short- to medium-term. Due to the fact that the Carbon Floor
Price leads to a significant reduction of CO2 intensive power generation in
other countries of the Pentalateral Forum, it can be assumed that other
emissions in these countries (especially Germany) will decrease as well.
 Scenario 3: Closure of coal plants – Phasing out coal-fired generation
reduces emission of SO2, PM and Hg emission while NOx emissions are less
affected, due to the relatively low emission factor of new coal plants
compared to substituting gas plants. If additional abatement measures are
implemented at the plants, the impact is determined by the assumed lowering
impact of biomass co-firing.
Due to the fact that early closure of coal plants in The Netherlands leads to
increases in power generation in other modelled countries, it can be assumed
that consequently emissions of the pollutants that are the subject of this
analysis increase in those countries, too.

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Figure 23.

Impact on other emissions
Ref Case
Scen 3b

Scen1a
Scen 3c

Scen1b
Scen 3d

Scen2
Scen 3f

Scen3a

Ref Case
Scen 3b

SO2

3,500

10,000

3,000

9,000

Scen1a
Scen 3c

Scen1b
Scen 3d

Scen2
Scen 3f

NOx

Scen3a

8,000
2,500

7,000

6,000

t/a

t/a

2,000
1,500

5,000
4,000

1,000

3,000

500

2,000

1,000
0
2020

Ref Case
Scen 3b

2030

Scen1a
Scen 3c

Scen1b
Scen 3d

0

2040

Scen2
Scen 3f

Scen3a

2020

Ref Case
Scen 3b

PM

200

2030

Scen1a
Scen 3c

Scen1b
Scen 3d

2040

Scen2
Scen 3f

Scen3a

Hg

160

180

140

160

120
140

100

kg/a

t/a

120
100
80

80
60

60

40
40

20

20
0

0
2020

2030

2040

2020

2030

2040

Source: Frontier

Taking into account the above mentioned limitation in the context of this study,
the resulting other emissions should be understood as an indicative estimation of
the impact. Further research should be pursued to assess the impact of these
factors further, in a national as well an international context.

4.8.2 Impact on heat networks
Some of the coal power plants currently provide heat to regional heat networks.
Furthermore, additional heat supply can constitute a policy measure to reduce
specific emissions of a power plant.
In all scenarios in which power plants close before the end of their lifetime, heat
supplied from those power plants to regional heat networks will have to be
replaced by other sources. This could be achieved by
 connecting the heat network to other heat networks with sufficient capacity to
replace the heat from coal/biomass fired power plants;
 investing in new facilities to provide heat to heat networks. These are likely to
be modern gas boilers;
 discontinue the provision of heat to industry and households by replacing it
with local heat production.
All options will lead to additional costs as investments have to be made into
expansion of heat network and new facilities to provide heat. We estimate that
coal-fired power plants which might be closed before the end of their lifetime
provide around ca. 2 TWh/a to heat networks. As an indicator for the cost of
replacing these heat supplies, we have estimated the specific production costs of

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a gas boiler. Depending on the development of the gas price we estimate that the
heat supply from gas boilers would cost between million 48.8 € and million 89.5 €
per year.53 These costs are not included in the system costs of the electricity
supply discussed in chapter 4.3.
It has to be noted that some plant operators that are currently producing heat are
planning to implement high shares of biomass-fired heat supply in the future. This
(almost) carbon-neutral heat supply would no longer be at disposal if coal plants
are closing before their assumed end-of lifetime. A replacement of biomass-fired
heat supply by gas-boilers therefore might be not seen as an adequate
replacement and more costly options might have to be considered, e.g.
connecting heat networks to other existing low-carbon heat sources.
In some scenarios the power plant operators plan to increase the provision of
heat to industry and households in order to reduce the specific emissions. In
such a case, additional investments might have to be undertaken in order to fully
utilise the additional heat provided by the power plant. This could include for
example the cost of expanding the heat network. On the other hand, an
increased heat supply from coal-fired power plants saves new investments into
alternative heating technologies.

4.8.3 Impact on innovation
The policy measures can have a positive impact on innovation if the development
of specific measures or technologies is fostered. At the same time, a negative
impact can result from hindering the development of certain technologies:
 Implementation of additional abatement measures can increase
innovation – The implementation of additional abatement measures can lead
to higher innovation with regard to the development of CCS and biomass
supply chains. The demonstration plant “ROAD” remains online longer than
assumed in the Reference Case. Due to this increased utilisation, learning
effects and cost savings might be realised with respect to the operation and
the development of CCS installation at coal plants. In addition, the innovation
potential related to the transportation and storage of carbon dioxide can be
transferred to the implementation of CCS at gas plants. Furthermore,
additional co-firing of sustainable biomass could lead to the development of
biomass supply chains that comply with Dutch sustainability criteria for
biomass (e.g. international implementation of Dutch sustainability criteria for
biomass).
 Closure of coal plants could lower innovation activities – If the newest
coal plants are closed earlier than expected, currently planned testing of CCS
might not be realised.
 Impact on innovation with respect to RES-E – Some scenarios result in
higher investment in wind-offshore and solar PV. In these scenarios,
additional operation of RES-E could lead to higher learning effects for these
53

This is based on specific investment costs between 70 and 130 €/kW, fixed operating and maintenance
costs of 2%-5% of the investment cost, a lifetime between 35 and 40 years, an interest rate of 5% and full
load hours between 2100 and 3200 hours. The efficiency of the gas boiler is assumed to be 95%. Costs for
CO2 and other emissions have not been included.

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technologies. These effects, however, are deemed to be rather small due to
the already achieved cost reductions and the relatively small impact of all
scenarios on investments in RES-E.

4.8.4 Effects on the employment
The closure of the five coal plants under investigation can have direct and
indirect effects on employment:
 Direct employment effects: Up to 1000 people54 are directly employed at the
five coal-fired plants. After closure of these plants, these employees would
have to be transferred into other workplaces.
 Multiplier effects: The closure of the plants can have indirect effects on
employment especially through multiplier effects:
□ The closure of the plants can have negative effects on suppliers of the
coal plants.
□ Furthermore, spending power of employees in the affected regions is
reduced after closure of the plants. This can have negative impacts on
local commercial and service enterprises.
 Compensating effects: On the other hand, the substitution of coal-fired
power generation with power supply from other sources can offset at least to
some extent the impacts on employment at the coal plants. For example,
employment can increase with reactivation of gas-fired power stations and the
extension of RES-E. However, since power generation from RES-E and gasfired power plants is in general less labour intense than power generation in
coal plants, and some parts of the power generation is substituted by higher
electricity imports/lower exports, these compensating effects cannot be
expected to totally balance out the loss of employment at the coal plants (at
least in the short term).
The quantification of the indirect effects is not subject of this study.

54

Based on full-time-equivalents (FTE)

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ANNEX A

REFERENCE CASE
ASSUMPTIONS

In this annexe, we provide detailed information on the assumptions of the
Reference Case. As described in section 2.2, the Reference Case is based on
the current and intended policy framework in The Netherlands and in NorthWestern Europe. It represents a scenario which is built upon a combination of
current market expectations, e.g. regarding fuel prices and CO2 prices, and
political targets for example for the development of RES-E. However, we only
take those policy decisions into account which are defined in an operational
manner and are officially decided.

A.1 Fuel and CO2 price assumptions
The fuel and CO2 prices affect the variable costs of generation and therefore the
power prices and profitability of generation units.

A.1.1 Fuel prices (coal and gas)
The coal and gas prices used in the context of this study are largely based on the
assumptions underlying the report “Frontier Economics (2015): Scenarios for the
Dutch electricity supply system”. The decrease of oil and other fuel prices of the
past two years is reflected in our assumptions. Based on current prices for power
futures traded on power exchanges and the long-term outlook of the World
Energy Outlook 2015, we assume that fuel prices will remain low in the shortterm and increase gradually after 2018:
 Short-term (until 2018) development according to current market
expectations – The short-term development is derived from future prices of
the trading day 28 April 201655.
 Medium- and long-term (2019-2050) based on Frontier Economics (2015)
and World Energy Outlook (2015, New Policies scenario).
□ The price development from 2019 until 2023 is modelled as linear
interpolation between the last future price (2018) and the first year of price
notation based on the WEO. Prices after 2023 are based on the oil price
projection from the WEO 2015 (New Policies) 56.
□ In the long-run (after 2040) prices are based on the methodology
described in Frontier 2015 .

55

Yearly futures; Coal: CIF ARA; Gas: TTF/NCG.

56

The long-term (after 2023) development of coal and gas prices is derived from oil prices based on expected
heat equivalence ratios (oil-to-gas and oil-to-coal). Heat equivalence ratios are defined as the price of fossil
fuels in relation to the heat content, expressed as EUR/MWhth. We assume a decreasing ratio for gas to oil
in the long-run (gas becomes relatively cheaper in the long run) because of the on-going decoupling of oil
and gas prices and higher availability of gas resources compared to oil resources (e.g. shale gas and LNG).
For the coal/oil and coal/gas relationships, we assume as well a decreasing trend because of the higher
availability of coal resources compared to gas or oil resources and a flatter marginal cost curve for coal
production than for the other primary energies.

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Figure 24.

Fuel price development (Reference Case)

40

natural gas / hard coal CIF ARA
(€2015/MWh, LHV)

35

30

25

20

15

10

5

natural gas (historical)

natural gas (projection)

coal (historical)

2050

2045

2040

2035

2030

2025

2020

2015

2010

0

coal (projection)

Source: Frontier
Note:

prices are noted in real values (2015) and low calorific value

A.1.2 Price for CO2 allowances
The European Emission Trading Scheme (EU ETS) has been characterised by
an “oversupply” of CO2 emission certificates in past years. This oversupply can
be attributed to a drop of demand due to the financial and economic crisis but
also due to certificates from flexibility mechanisms (JI/CDM) and higher shares of
RES-E in Europe that substitute conventional power generation and in return
decrease the demand for emission certificates.57 As the total supply of certificates
in a “cap & trade” system like the EU ETS is fixed by the emission cap, the price
has decreased substantially.
Several measures have been proposed or have been introduced that aim at
increasing the CO2 price and therefore the incentives for CO2 reduction in the EU
ETS:
 As a temporary measure, a 900 mn. certificates have been taken out of the
market (so-called “Backloading”) and will be (partially) fed back into the
system at the end of this trading period (2020).
 The “Market Stability Reserve” represents a possible medium term option
(from 2019) to stabilise pricing signals. This option has been backed by the
Environment Committee of the European Parliament end of February 2015.

57

European Commission (2012).

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 For the trading period IV (2021-2030, the current proposal foresees and
increase of the Linear Reduction Factor from 1.74%/a to 2.2 %/a58 as well as
an amendment of rules regarding free allocation and carbon leakage.
In total, we expect in the Reference Case that the EU ETS will maintain its role
as the central instrument for climate change on the European level. Therefore,
we expect the price to rise in the medium- to long-run after market reforms have
been implemented.
We derive our CO2 price assumptions according to the following logic:
 Short-term (until 2017) development according to current market
expectations – We use CO2 price futures (trading day 28 April 2016) to derive
our short-term price projection.
 Medium-term (2018-2035) price development based on the “Nationale
Energieverkenning” (National Energy Outlook) – We use the CO2 price
assumptions derived in the National Energy Outlook in 2016.59
 Long-term price development (after 2035) is calculated as a linear
extrapolation of the price projection of the NEO 2016 for the years 2030 and
2035.
Figure 25.

Assumed CO2 price development

90
80

70

€_2015/tCO2

60
50
40
30
20
10

0
2015

2020

2025

2030

2035

2040

2045

2050

Source: Frontier based on ECN/PBL (2016)
Note:

Prices are noted in real values (2015)

A.2 Power demand
Our assumption for the development of power demand is based on the demand
projection used in the National Energy Outlook (Nationale Energieverkenning,
58

Based on the emissions of 1990.

59

ECN/PBL (2016, forthcoming), scenario “Voorgenomen beleid”.

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NEV) published by ECN and PBL in 2015.60 The NEV assumes a moderate
growth of power consumption in the next years. Including network losses, net
electricity consumption is assumed to increase from 114 TWh in 2015 to 121
TWh in 2040. This growth reflects the moderate average demand increase in the
most recent years and takes two countervailing trends for the future into account:
□ Increased demand due to growth of GDP; and
□ Increased energy efficiency which leads to a decoupling of the formerly
strong relationship between power demand and the GDP.
We base our assumptions on the assumed demand growth of the NEV until 2030
and use linear extrapolation for the years after 2030 (Figure 26).
Figure 26.

Development of net-power demand

140
120
100

TWh

80
60
40
20
0
2015

2020

2025

2030

2035

2040

2045

2050

Source: Frontier based on ECN/PBL(2015)
Note:

Net-demand including transmission losses, excluding own-consumption of generation

Power demand in other modelled European countries is derived from national
forecasts, e.g. Transmission System Operators (TSO) forecasts (France: RTE,
German net-work development plant). Net-demand in all modelled regions61 is
assumed to increase by 8.3% from 2,281 TWh in 2015 to 2,470 TWh in 2040.

60

Net electricity consumption; ”implemented and planned policies” (excluding own-production including grid
losses)

61

Modelled regions include: The Netherlands, Germany, Belgium, France, Denmark, Poland, Czech Republic,
Austria, Switzerland, Italy and Great Britain.

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Table 16.

Net power demand (model-region)

TWh

2015

2018

2020

2025

2030

2035

2040

DE*

539

538

537

535

535

535

535

NL*

114

114

114

115

117

119

121

BE*

87

90

91

94

97

101

104

FR*

490

490

490

495

500

505

510

AT*

71

72

73

75

77

80

82

CH

65

66

67

68

69

70

69

CZ

66

68

70

73

75

78

81

PL

148

151

154

159

164

169

175

DK

35

35

35

36

36

36

37

GB

338

335

334

336

343

355

363

IT

328

333

337

350

364

379

394

Source: Frontier
Note:

“Core-region” with endogenous optimisation of power plant park marked with (*)

A.3 Generation capacities
A.3.1 Conventional thermal generation capacities in The
Netherlands
The Dutch power plant park is characterised by a large share of conventional
generation capacities. Based on economic reasoning, the power market model
optimises the existing power plant park through
□ Retirement of power plants (before end of lifetime if economic);
□ Mothballing of power plants;
□ Reactivation of mothballed capacity; and
□ Investment in new generation capacity.
In our modelling, mothballing and reactivation of power plants are associated with
costs. Investment costs for conventional power plants are indicated in Table 17.
Mothballing of power plants reduces the yearly fixed operation and maintenance
costs of the power plant by 75%. The reactivation of a power plant is followed by
a one-time payment of 25% of the yearly fixed operation and maintenance
costs.62
62

The costs of reactivation depend in practice on a multitude of factors including plant specifics, company
specific circumstances and the time period after which the plant is reactivated. However, alternative
assumptions of costs for reactivation have a very limited on the results of this study since the reactivation
costs are insignificant compared to the costs of the electricity system in total.

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Development of thermal generation capacity
The assumptions regarding the existing power plant park are derived from Platts
PowerVision database, a commercial database with information on retirements
and additions of power plants and other publically available information e.g. on
mothballing of specific units. Further adjustments of thermal capacity were
derived from the Energy Agreement (regarding closure of coal-fired power plants)
and the Monitoring Report published by the Dutch TSO, TenneT.63
In 2015, installed generation capacity amounts to ca. 35 GW, of which 29 GW
are fossil fuel fired power plants (Figure 27).
Figure 27.

Installed generation capacity (NL, 2015)

Source: Frontier
Note:

Graph includes 4.3 GW of mothballed gas-fired power plants.

Our modelling takes into account known market entries (investment) until 2020
as well as known mothballing decisions and retirements based on the end of the
technical lifetime of power plants as exogenous assumptions.64 In the short-term,
this includes
 Known retirement of 2.6 GW coal-fired power generation until June 2017
based on the Energy Agreement;
 Market entry of the coal-fired MPP3 power plant in 2016;and
 Known mothballing of 4.3 GW of gas-fired capacity;
In addition to those additions and retirements, the model simulates additional
investment, earlier retirement of plants or on additional mothballing and
reactivation of generation capacities.

63

TenneT (2015).

64

Our model does not include retrofitting to achieve a lifetime extension but allows for replacement
investments.

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Possible investment options in The Netherlands
The outlook of the future electricity system in The Netherlands is influenced by
the technological development and the availability of new generation
technologies, as for example carbon-capture and storage (CCS) for coal and gas
plants as well as new storage solutions.65 We include the following options in our
modelling for investments in The Netherlands (Table 17):
□ Hard coal - with and without CCS (as “integrated gasification combined
cycle” (IGCC) technology);
□ Natural gas – “combined cycle gas turbines” (CCGT) and “open cycle gas
turbines” (OCGT);
□ Nuclear power;
□ Power storages - “compressed air energy storage” (CAES), “advanced
adiabatic compressed air energy storage” (AACAES), and power-to-gas
(and back to power).
Table 17 provides the assumed investment costs per MW. Beside investment
costs, thermal efficiency, storage volume (if relevant) and other variable costs
determine which technologies are built in the power market model.
Table 17.

Investment options (conventional thermal and storage)

Technology / Fuel

Available in

Overnight
investment cost
(EUR/kW)

Fixed operation
and maintenance
(EUR/kW)

Hard coal

2018

1,750

26.25

Natural Gas (OCGT)

2018

450

6.75

Natural Gas (CCGT)

2018

750

11.25

Hard coal (IGCC) with
CCS

2025

2,750

54.95

Natural Gas (CCGT)
with CCS

2025

1,400

21

CAES

2025

806

16.12

AACAES

2030

1,300

26

Power-to-Gas (toPower)

2030

1,650

45

66

2035

4,600

69

Nuclear

Source: Frontier
65

Investment costs are derived from multiple source and previous project experience.

66

Nuclear investment as a potential replacement of the existing nuclear power station is included as an option.
However, building a new nuclear power station may be controversial in the political debate. Since the
replacement would take place only in the long term and the total capacity of the unit would be relatively
moderate compared to the size of the electricity system the impact of this assumption on the model results
is very limited.

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Combined-heat and power generation
A large share of electricity supply in The Netherlands is produced in combinedheat and power (CHP) facilities, i.e. power plants with the primary use of heat
generation either for
□ industrial processes;
□ district heating; or
□ agriculture and horticulture.
In 2014, around 12 GW electrical capacities are characterised as conventional
CHP capacities:
□ 5 GW central generation capacities (gas and coal) mainly for district
heating and industrial heat generation; and
□ 6.8 GW of decentralised generation capacities mainly for agriculture and
horticulture (green-houses) and industrial heat generation.
Electricity generation from conventional CHP amounted to ca. 43 TWh in 201467.
In our modelling of the electricity system, heat driven power generation from CHP
is treated as exogenous generation, power market driven generation as
dispatched generation:
□ Power generation as a bi-product of heat-decoupling is treated as “mustrun” generation that is fed into the system irrespective of power market
developments.
□ In addition to the electricity generation arising from heat production,
certain CHP plants have flexibility and are dispatched like a “power-only”
plant.
For the future development of conventional CHP generation, we apply the
following assumptions:
□ Long-term decrease of de-central generation: Electricity supply from
de-central CHP capacities, as for example greenhouses, is regarded as
bi-product of heat-generation. We assume that the underlying economics
of de-central CHP capacities will not change in the short-term. Therefore,
generation from these capacities will remain constant until 2025. After
that, replacement investment would become necessary. Due to a more
difficult economic framework and increased penetration from alternative
heat sources (e.g. geothermal), we assume that generation from decentral CHP units decreases in the long-run (2040) by more than 50%
compared to 2015.
□ Decreasing central generation: Central CHP capacities are influenced
by power market economics to a greater extent. We assume that central
conventional CHP installations can remain online until the end of their
technical lifetime, but may be mothballed or retired beforehand. It has to
be noted that we don’t model the new built of central conventional CHP
installations endogenously since the specific circumstances of heat
67

Based on CBS statline.

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demand etca. (which are not part of the model) drive the economics of
each single unit and therefore the decisions to renew or refrain from
renewal of old units. The assumption of absent replacement investments
is consistent with results of studies that have assessed the economic
situation of conventional CHP plants.68 Instead, we include the option of
new-built gas-plants (OCGT and CCGT).
In total, must-run power generation from conventional CHP will decrease in the
long-run from ca. 40 TWh in 2015 to ca. 15 TWh in 2050. This decrease is also in
line with the political goals a decarbonisation of the power sector. At the same
time, we expect CHP generation from renewable (biomass) plants to increase in
the long-run as additional financial support is granted under the SDE (+) support
scheme.69

TWh

Figure 28.

Assumed development of central and de-central CHP “mustrun” generation

45

40

35

30

25

20

15

10

5

0
2015

2018

2020

2025

2030

2035

2040

2050

Source: Frontier

De-rating factors for reserve margin calculation
We have used the following de-rating factors to calculate reserve margins as well
the supply for the modelled capacity mechanisms in foreign countries (e.g.
France).

68

E.g. CE Delft / DNV GL (2014).

69

ECN/PBL (2014), p. 100.

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Table 18.

De-rating factors

Power plant type

Capacity credit for CRM

Nuclear

93.1%

Lignite

89.6%

Hard Coal (with/without CCS)

89.6%

Gas (CCGT)

88.8%

Gas (OCGT)

82.1%

Oil

87.3%

Wind-offshore

11%

Wind-onshore

8%

Solar PV

2%

Biomass

65%

Run-of-river

48%

Pumped-Hydro-Storage

90%

Reservoir-Storage

85%

Power-to-Gas

85%

AACAES

85%

CAES

85%

DSR (load reduction)

90%

Source: Frontier

A.3.2 Renewable Energies
RES-E in The Netherlands
The current political targets expressed in the Energy Agreement foresee a
significant growth of renewable energy supply in electricity supply. As the
development of renewable energy sources in the electricity sector is very much
driven by political initiatives and support schemes, we assume an exogenous
growth path of RES-E capacities and generation based on:
□ Current political targets for RES-E capacity; or
□ Secondary sources on future RES-E development in The Netherlands.70

70

ENTSO-E Scenario Outlook and Adequacy Forecast (SO&AF) RES-E capacities in other modelled
countries are derived accordingly based on legal targets and / or secondary sources.

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In the Base Case, we assume a significant increase of renewable electricity
supply from around 14 TWh in 2015 to more than 60 TWh in 2035. This
corresponds to an increase of the share of renewable electricity of net demand
from 12% in 2015 to approx. 50% in 2035. The development of renewable
electricity supply is based on the following assumptions:
 Wind-onshore – According to the Energy Agreement, onshore wind power
installations are expected to increase to 6 GW in 2020. Thereafter, we
assume a yearly growth of wind-onshore installations by 200 MW/a, in line
with growth expectations from ENTSO-E SO&AF (2014, Scenario B / Vision
3).
 Wind-offshore – According to the Energy Agreement, the installed capacity
of wind-offshore turbines is planned to increase to 4450 MW in 2023.
Thereafter, we assume an on-going growth of wind-offshore capacities to 6
GW in 2030 based on ENTSO-E SO&AF (2014, Vision 3).71
 Solar PV – There are no explicit political targets regarding the development of
solar PV installations in The Netherlands. However, solar PV is eligible to the
support scheme SDE (+) and, in addition, small scale installations are
benefiting from net-metering.72 Therefore, we assume increasing solar PV
capacity based on the following information:
□ We use the National Energy Outlook for the period until 2023 (increase
from ca. 1.5 GW in 2015 to ca. 9.6 GW in 2023).
□ After 2023, we assume that changes to the current legal framework of netmetering will reduce the benefits of small-scale solar PV installations, and
growth will slow down to ca. 250 MW/a (based on ENTSO-E SO&AF
(2014, Vision 3).
 Other RES-E (biomass) – Biomass in The Netherlands is used in dedicated
biomass/-gas power plants as well as in co-firing of coal-fired power plants:
□ In the short-run (until 2028), co-firing of biomass is subject to subsidies
(SDE+) and a 25 PJ/a limit on total amount of biomass co-fired. In the
long-run, we assume that biomass co-firing in coal plants will take place if
it is economical based on the assumed prices of biomass, CO2 and coal.
□ Power generation from dedicated biomass/-gas generation units will
remain more or less constant (based on NEV 2015).
Figure 29 shows the assumed growth of renewable electricity supply in The
Netherlands.

71

Capacity development after 2030 is derived based on a linear trend of the previous years.

72

Net-metering applies to consumers that are connected to the distribution grid and reduces the burden of
energy taxes to the amount of net electricity consumption, i.e. no energy taxes have to be paid on the autoproduced electricity.

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Figure 29.

Development of RES-E in The Netherlands

Source: Frontier
Note:

RES-E share of net-demand / excluding biomass co-firing in coal plants.

In addition to the exogenous expansion of RES-E described above, we allow for
endogenous investment in RES-E after 2035. Based on the assumed levelised
costs of electricity73, the model can decide to invest in wind-onshore, offshore or
solar PV. We limit the additional investment potentials to yearly growth-rate
described above, i.e.:
□ 200 MW/a for wind-onshore;
□ 220 MW/a for wind-offshore; and
□ 250 MW/a for solar PV.
The cost-assumptions shown in Table 19 are used to calculate the costs of RESE investment and operation as well as modelling the endogenous investment in
RES-E (after 2035).
Table 19.

Levelised costs of electricity (RES-E)

EUR (real,
2015) / MWh

2015

2018

2020

2025

2030

2035

2040

2050

Windoffshore

83.5

77.0

70.5

66.7

59.2

59.2

57.5

52.7

Windonshore

64.0

63.1

62.2

61.3

59.7

59.7

59.4

58.5

Solar PV

120.9

113.2

105.5

97.2

80.6

80.6

78.0

69.9

Source: Frontier based on ECN (2014), WEO 2014

73

Levelised costs of electricity according to Frontier (2015).

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Renewable energy sources in foreign modelled countries
As in The Netherlands, the development of renewable energy sources in other
modelled countries has been derived from the current political framework (e.g.
EEG 2014) or for example TSO forecasts.
Figure 30.

RES-E in the model-region

2,000

80%

1,800

67.9%

70%

Solar PV

1,600
60%

RES-E generation (TWh)

56.4%
1,400

50.9%

1,200

50%

44.5%

Windoffshore

37.1%

1,000

Windonshore

40%
Hydro (RoR)

800

29.0%

30%

26.0%
600

Other RES

21.5%
20%

400

RES-E %
10%

200
0

0%
2015

2018

2020

2025

2030

2035

2040

2050

Source: Frontier
Note:

RES-E % share of net-demand; Other RES without biomass co-firing.

A.4 Interconnection capacities
Increasing interconnection capacity between countries in Europe is an important
cornerstone of the European internal electricity market. Therefore, the
development of cross-border connections is an important assumption and
influences the outcomes of the power market modelling significantly. It has to be
noted that the modelling of interconnectors does not take internal congestions
inside the modelled countries into account. Availability of interconnectors is
further not influenced by loop or transit flows and flow-based market coupling is
not incorporated in the model since the modelling of interconnections is based on
Net Transfer Capacities (NTC) due to restrictions regarding computational time of
the model.

Interconnection capacities of The Netherlands
The Netherlands is a country with high interconnection to its neighbouring
countries, notably Germany and Belgium. Additional interconnections are in place
to Great Britain (BritNed) and Norway (NorNed). In 2015, total cross-border
capacity from/to The Netherlands amounted to almost 6 GW, approximately one
third of peak load.

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Based on our assumptions, cross-border capacity will increase further in the next
years: Our assumptions regarding the development of interconnection capacity
are based on ENTSO-E’s Ten-Year-Network-Development-Plan.74 In addition, we
have confirmed the development of power interconnectors to and from The
Netherlands with TenneT’s monitoring report.75 Figure 31 shows the average of
import and export capacity to/from The Netherlands76:
 Interconnections to Germany will increase in 2018 and 2021 to a total of 4.5
GW in 2021. Additional interconnection to Germany is assumed to come
online after 2030 (+ 500 MW).
 Interconnections to Belgium will increase to 2.4 GW by 2018.
 Interconnection to Denmark (Cobra Cable) will be established by 2019.
Figure 31.

Assumed development of interconnection capacity (NL)
DE

BE

NORDPOOL

2020

2025

GB

DK

average of import and export capacity (MW)

12,000

10,000

8,000

6,000

4,000

2,000

0
2015

2018

2030

2035

2040

2050

Source: Frontier based on TYNDP 2014 and TenneT (2015)

74

We assume that projects that are in the earlier planning phases will come online with a certain delay:
“design and permitting” + 2 years; “planning” + 5 years; “under consideration” + 15 years.

75

TenneT (2015).

76

Assumptions regarding interconnectors across Europe are included in Annexe 2.

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ANNEX B

REFERENCE CASE RESULTS

In this annexe, we summarise the resulting market outcomes for the Reference
Case in detail:
 Electricity generation and capacities (Section B.1);
 Power exchange (Section B.2);
 Power sector carbon dioxide emission (Section B.3); and
 Development of power prices (Section B.4).
The modelling outcomes are based on the assumptions described in ANNEX A.

B.1 Electricity generation and capacities
B.1.1 The Netherlands
Electricity generation and the development of operational capacities in The
Netherlands in the Reference Case is characterised by the following key trends:
 Additional mothballing of gas-fired power plants in the short-term, investment
in new capacities in the long-run;
 Increasing share of RES-E in the medium- and long-run;
 Change of the importing positions from being a net-importer of power to
becoming a net-exporter to power.

Additional mothballing in the short-term, new investment in capacities in
the long-run
Operation capacities in The Netherlands are decreasing in the short-term due to
mothballing of gas-fired power plants but increase again in the medium to long
run based on the assumed growth of RES-E as well as the reactivation of
mothballed plants and new investments:
 Additional short-term mothballing of ca. 4 GW – In the period of 2015 to
2018, additional 4 GW of gas-fired power plants are mothballed in The
Netherlands. This result is driven by the existence of short-term
overcapacities in Central-Western Europe, a slow recovery of power demand
following the economic and financial crisis in Europe, as well as consistently
low fuel prices.77
Until 2025, scarcity of generation capacities in CWE increases significantly
with the completion of the German nuclear phase-out until 2023 and the
nuclear phase-out in Belgium until 2025. Additional tightening of the market is

77

Mothballing of plants may be lower if reactivation costs are assumed to be higher. Most capacities not
mothballed can be expected to stay operational instead in the relevant time period since new built of
capacities as a potential replacement after 2020 would be much more costly than keeping the plants
operational in the short and medium term.

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induced by the introduction of the capacity reserve in Germany78 which, in the
short-term, leads to decommissioning of lignite plants. Therefore, with
increasing tightening of the market, in the medium term from 2018 until 2025,
the majority of mothballed capacities is reactivated and re-enters the market.
 Investment in new capacities in the long-run – In addition to the assumed
growth of renewables, new generation capacities enter the Dutch power
market in the long-run:
□ The decommissioned Borssele nuclear power plant is replaced with a new
investment of 1 GW in 2035;79
□ With increasing CO2 prices, gas-fired generation becomes more
economical as compared to other fossil fuels. Consequently, required
replacement investments take place in 2035 (1 GW OCGT) and in 2040 (2
GW CCGT); and
□ The long-term market environment with high CO2 prices is favourable for
RES-E. Therefore, additional investment of 1 GW wind-offshore in 2035
and 2 GW wind-offshore in 2040 as well as 500 MW of solar PV in 2040
come online (on top of the assumed exogenous capacity additions which
are politically driven).
 Dutch coal plants stay online until the end of their assumed lifetime –
The five remaining Dutch coal plants (coal plants not closed before 2018) stay
online until the end of their assumed lifetime in the reference Case. Utilisation
of these plants decreases in the long-run. However, market-based co-firing,
which becomes profitable in the long-run (2040), keeps running-hours
sufficiently high.

78

Current plans forsee that ca. 5% of peak demand should be contracted as reserve. In the short-term, 2.7
GW of lignite-fired generation will cease operation and enter the reserve before being decommissioned after
2021.

79

If this replacement doesn’t take place due to political reasons we expect that additional gas-fired capacity
and/or some additional RES-E capacities would be built instead in the Netherlands. Furthermore, exports to
foreign countries might decrease to some extent.

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Figure 32.

Development of operational capacities NL (Reference Case)

80

IC-import capacity

de-rated DSR
70
other
solar

60

ROR

GW

50

hydro
wind_on

40

wind_off
other_RES

30

gas (decentral)
oil

20

gas
10

coal (incl. co-firing)
nuclear

0
2015

2018

2020

2025

2030

2035

2040

Peak Load

Source: Frontier
Note:

operational capacities excl. mothballed capacities, not de-rated

Increasing shares of renewable energy sources in the medium and longterm
The development of electricity generation in The Netherlands is mainly driven by
a significant increase in the share of RES-E power production:
 Significant increase of RES-E – According to the current political targets
and long-term vision of the European and Dutch power sector, renewable
energy sources play an increasingly important role in the power system. This
development is reflected in the assumptions of the Reference Case. The
renewable share of net demand increases from ca. 12% today to almost 50%
in 2025. After 2025, due to the assumed phase out of-subsidies for biomass
co-firing in the Dutch coal plants, the renewable share decreases slightly to
47% temporarily. With additional investments in RES-E, the share increases
to 71% of net-demand in 2040.
Electricity supply from wind-offshore installations records the largest increase
in power generation from ca. 1.3 TWh in 2015 to more than 40 TWh in 2040.
Wind-onshore power generation increases from ca. 6 TWh in 2015 to 23 TWh
in 2040 and solar PV generation from 1 TWh (2015) to 12 TWh (2040). Cofiring of biomass in coal plants ceases after the assumed phase-out of
subsidies in 2028 and increases again in 2035 and 2040 due to improved
economics.
 Changing import position in the medium-term – With increasing scarcity in
neighbouring countries and an increase of renewable energy sources, The
Netherlands move from being a net-importer of power in the short-term to
becoming a net-exporter of power after 2025.

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Figure 33.

Development of
(Reference Case)

electricity

160

supply

The

Netherlands

Net-imports

80%
71%

140

in

other
70%
solar

120
60%

56%

wind_on

100

TWh

60

47%

wind_off

50%
40%

36%

40

30%

RES-E (%)

48%
80

ROR
other_RES
(incl. co-firing)
gas (decentral)

23%
20

oil
20%

0

gas

12%
10%

-20

-40

0%
2015

2018

2020

2025

2030

2035

2040

coal
nuclear

RES-E (%)

Source: Frontier

B.1.2 CWE and neighbouring countries
In the following tables, we provide information on the development of operational
capacities and power generation in the most important countries of the CentralWestern European market (The Netherlands, France, Germany, Belgium,
Austria), Great Britain and Denmark.80

80

Great-Britain and Denmark are not part of the “core-regions” of the model, i.e. plant dispatch is modelled
with a lower level of detail and capacity development is assumed exogenously.

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Table 20.

Reference Case: Operational capacities and electricity supply by fuel type
(The Netherlands)
2015

2018

2020

2025

2030

2035

2040

Operational capacities (GW)
Nuclear

0

0

0

0

0

1

1

Coal

6

5

5

5

5

3

3

Gas

10

5

6

13

13

12

12

Gas (decentral)

7

7

7

6

6

5

3

Oil

1

0

0

0

0

0

0

Wind-offshore

0

2

3

5

6

8

12

Wind-onshore

3

5

6

7

8

9

10

Solar PV

2

4

6

10

11

13

14

Other RES (excl. cofiring)

1

1

1

1

1

1

1

Hydro (Run of river)

0

0

0

0

0

0

0

Net electricity supply (TWh)
Nuclear

4

3

3

3

3

7

6

Coal

40

31

25

24

26

18

13

Gas

23

18

19

35

29

28

29

Gas (decentral)

24

24

24

22

22

16

11

Oil

0

0

0

0

0

0

0

Wind-offshore

1

7

11

18

22

31

43

Wind-onshore

6

11

14

16

19

21

23

Solar PV

1

3

5

8

9

10

12

Other RES (incl. cofiring of biomass)

5

5

11

12

4

4

6

Hydro (Run of river)

0

0

0

0

1

1

1

Source: Frontier

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Table 21.

Reference Case: Operational capacities and electricity supply by fuel type
(Germany)
2015

2018

2020

2025

2030

2035

2040

Operational capacities (GW)
Nuclear

12

9

8

0

0

0

0

Lignite

20

19

13

10

9

9

5

Coal

26

22

21

16

10

7

6

Gas

23

14

15

15

15

16

18

Oil

3

0

0

0

0

0

0

Wind-offshore

2

4

6

10

14

20

28

Wind-onshore

35

43

48

60

73

80

88

Solar PV

38

46

51

55

56

58

61

Other RES

8

8

8

8

9

9

10

Hydro (Run of river)

4

4

4

4

4

4

4

Hydro (Storage)

10

10

10

11

11

11

12

Net electricity supply (TWh)
Nuclear

87

69

59

0

0

0

0

Lignite

139

129

91

67

56

53

29

Coal

110

111

108

92

55

36

25

Gas

61

65

67

71

71

67

68

Oil

0

0

0

0

0

0

0

Wind-offshore

7

16

21

37

53

74

105

Wind-onshore

67

81

91

115

139

153

168

Solar PV

35

42

46

50

52

53

56

Other RES

46

48

49

51

53

56

58

Hydro (Run of river)

17

18

18

19

19

20

21

Hydro (Storage)

9

10

10

11

12

13

15

Source: Frontier

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Table 22.

Reference Case: Operational capacities and electricity supply by fuel type
(Belgium)
2015

2018

2020

2025

2030

2035

2040

Operational capacities (GW)
Nuclear

6

6

6

4

0

0

0

Coal

0

0

0

0

0

0

1

Gas

4

2

2

3

3

3

7

Oil

1

0

0

0

0

0

0

Wind-offshore

1

1

2

2

4

5

6

Wind-onshore

1

2

3

4

5

5

6

Solar PV

3

4

4

5

6

6

7

Other RES

1

1

2

2

2

2

2

Hydro (Run of river)

0

0

0

0

0

0

0

Hydro (Storage)

1

1

1

2

2

2

2

Net electricity supply (TWh)
Nuclear

42

42

42

28

0

0

0

Coal

3

0

0

0

0

0

7

Gas

7

6

6

9

7

7

23

Oil

0

0

0

0

0

0

0

Wind-offshore

2

4

5

7

13

16

18

Wind-onshore

3

5

6

9

11

12

13

Solar PV

2

3

3

4

5

5

5

Other RES

3

8

10

14

14

14

14

Hydro (Run of river)

0

0

0

0

0

0

0

Hydro (Storage)

2

1

1

2

2

2

3

Source: Frontier

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Table 23.

Reference Case: Operational capacities and electricity supply by fuel type
(Austria)
2015

2018

2020

2025

2030

2035

2040

Operational capacities (GW)
Coal

1

1

1

1

0

0

0

Gas

3

0

0

3

3

3

3

Gas (decentral)

2

2

2

2

2

2

2

Oil

0

0

0

0

0

0

0

Wind-onshore

2

3

3

4

5

7

8

Solar PV

1

1

2

3

4

5

6

Other RES

1

1

1

1

1

1

2

Hydro (Run of river)

6

6

6

6

6

6

6

Hydro (Storage)

7

7

7

7

7

7

8

Net electricity supply (TWh)
Coal

3

3

3

4

0

0

0

Gas

1

0

1

8

7

7

7

Gas (decentral)

8

8

8

8

8

8

8

Oil

0

0

0

0

0

0

0

Wind-onshore

4

5

6

9

11

13

15

Solar PV

1

1

1

3

4

5

6

Other RES

4

5

5

6

7

8

10

Hydro (Run of river)

32

32

33

33

34

35

36

Hydro (Storage)

11

11

11

11

12

12

13

Source: Frontier

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Table 24.

Reference Case: Operational capacities and electricity supply by fuel type
(France)
2015

2018

2020

2025

2030

2035

2040

Operational capacities (GW)
Nuclear

63

63

63

63

60

49

17

Coal

4

2

2

2

2

2

1

Gas

6

11

11

11

11

11

41

Oil

7

4

3

1

0

1

1

Wind-offshore

0

2

3

4

9

15

20

Wind-onshore

9

12

15

20

28

37

45

Solar PV

5

7

9

13

30

47

64

Other RES

1

1

1

1

2

3

4

Hydro (Run of river)

10

10

10

11

12

13

13

Hydro (Storage)

13

13

13

14

16

17

19

Net electricity supply (TWh)
Nuclear

411

409

408

407

380

304

100

Coal

24

15

14

13

8

8

4

Gas

11

15

17

20

16

16

56

Oil

0

0

0

0

0

0

0

Wind-offshore

0

5

9

11

29

47

64

Wind-onshore

19

26

31

42

60

79

97

Solar PV

6

9

11

16

37

58

79

Other RES

7

7

7

7

14

20

27

Hydro (Run of river)

30

30

30

33

36

38

39

Hydro (Storage)

26

27

26

29

33

36

39

Source: Frontier

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Table 25.

Reference Case: Operational capacities and electricity supply by fuel type
(Great Britain)
2015

2018

2020

2025

2030

2035

2040

Operational capacities (GW)
Nuclear

10

9

9

6

11

14

14

Coal

19

17

16

6

2

5

5

Gas

31

31

31

38

40

41

42

Oil

1

0

0

0

0

0

0

Wind-offshore

5

8

10

25

29

30

31

Wind-onshore

7

11

13

18

19

19

20

Solar PV

5

7

14

19

23

26

27

Other RES

0

1

1

1

2

4

5

Hydro (Run of river)

1

1

1

1

1

1

1

Hydro (Storage)

3

3

3

3

3

3

3

Net electricity supply (TWh)
Nuclear

70

67

66

47

80

97

83

Coal

132

106

87

26

6

12

15

Gas

61

56

50

46

33

27

43

Oil

0

0

0

0

0

0

0

Wind-offshore

19

30

38

100

118

123

125

Wind-onshore

17

25

30

42

44

45

46

Solar PV

3

5

10

14

17

18

19

Other RES

3

4

5

7

9

24

32

Hydro (Run of river)

3

3

3

3

3

3

3

Hydro (Storage)

2

2

2

3

4

4

5

Source: Frontier

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Table 26.

Reference Case: Operational capacities and electricity supply by fuel type
(Denmark)
2015

2018

2020

2025

2030

2035

2040

Operational capacities (GW)
Coal

1

1

1

1

0

0

0

Gas

2

2

1

1

1

1

1

Oil

1

1

1

0

0

0

0

Wind-offshore

1

2

3

3

4

5

5

Wind-onshore

4

4

4

4

5

5

6

Solar PV

1

1

1

1

2

3

3

Other RES

2

2

2

3

3

3

3

Hydro (Run of river)

0

0

0

0

0

0

0

Hydro (Storage)

0

0

0

0

0

0

0

Net electricity supply (TWh)
Coal

6

6

5

3

0

0

0

Gas

0

1

1

2

1

1

1

Oil

0

0

0

0

0

0

0

Wind-offshore

5

9

11

13

16

18

20

Wind-onshore

9

9

9

9

11

13

14

Solar PV

0

1

1

1

2

2

2

Other RES

9

12

14

16

16

17

17

Hydro (Run of river)

0

0

0

0

0

0

0

Hydro (Storage)

0

0

0

0

0

0

0

Source: Frontier

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B.2 Power exchange
The power exchange between countries is on the one hand affected by changing
supply structures in the interconnected countries and on the other hand by the
expansion of interconnector capacities between regions. In the following, we
describe the development of power imports and exports from and into The
Netherlands and in CWE.

B.2.1 The Netherlands
In recent years, The Netherlands have been importing more power than they
have exported due to the high share of gas-fired generation which is comparably
more expensive than low-cost but more carbon-intensive power generation for
example in Germany. The level of net-imports since 2010 ranged between ca. 3
TWh in 2010 to 18 TWh in 2013. In 2015, historical net-imports amounted to ca.
9 TWh.81
As described in Section B.1.1, the net-importing position of The Netherlands is
changing to a net-exporting position in the medium- to long-term:
 Net-imports of power in the short-term – Until 2020, The Netherlands
remain net-importer of power by 10 TWh in 2018 and by a marginal amount of
ca. 1 TWh in 2020.
 Increased tightening of the market in CWE leads to lower imports–In the
model, electricity imports from Germany amount to more than 20 TWh in
2018. After the nuclear phase-out in Germany, the introduction of the lignite
and capacity reserve as well as more RES-E production in NL, this position
changes significantly to only 5 TWh of imports from Germany and more than
10 TWh exports to Germany (2025). From 2025 until 2040 Dutch the netexports to Germany amount to between 15 and 25 TWh/a (Figure 34).

81

CBS Statline, Electricity balance sheet; supply and consumption 2010-2015.

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Figure 34.

Imports/Exports NL (Reference Case)

40

NORDPOOL > NL

30

NL > NORDPOOL
DK > NL

10

NL > DK

0

GB > NL

-10

NL > GB

TWh

20

BE > NL

-20

NL > BE

-30
DE > NL

-40
NL > DE

-50
2015

2018

2020

2025

2030

2035

2040

Net-Imports

Source: Frontier
Note:

Positive values represent imports to The Netherlands, negative values exports from The Netherlands
to other countries

B.2.2 CWE and neighbouring countries
Table 27 provides model results on the net-imports (positive values) and netexports (negative-values) of selected countries in the CWE region..
Table 27.

Net-imports in other countries (Reference Case)
2015

2018

2020

2025

2030

2035

2040

DE*

-40.4

-49.2

-22.1

23.3

23.7

9.3

-0.9

FR*

-46.9

-50.2

-58.9

-78.7

-106.6

-92.0

15.5

NL*

9.9

10.3

0.6

-25.5

-17.7

-15.4

-21.9

BE*

24.6

21.3

17.0

22.6

46.5

45.8

22.7

GB

25.8

34.2

42.8

49.4

30.5

3.3

-4.5

AT*

7.6

8.0

5.8

-5.2

-3.1

-6.1

-6.6

CH

-4.0

-3.0

-2.5

-3.1

-1.0

1.2

-5.7

DK

5.0

-1.3

-5.4

-8.1

-11.4

-14.7

-17.5

Source: Frontier
Note:

frontier economics

* core-region with endogenous investment/divestment

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B.3 Power sector related CO2 emissions
In this section, we describe the development of power sector related carbon
emissions in The Netherlands and in the other modelled countries. Emissions
from CHP-installations are taken into account based on the plant specific
emission-intensity.82

B.3.1 The Netherlands
The development of the Dutch electricity system in the Reference Case is
characterised by a strong increase of RES-E. Accordingly, the power related
carbon emissions decrease significantly from 51 mn. tCO2 in 2015 to 25 mn. tCO2
in 2040. The following developing of CO2 emissions can be taken from the model
results:
□ Short-term decrease of carbon dioxide emissions by ca. 27% to 37 mn.
tCO2 in 2020 after closure of the 1980’s coal-fired power stations in The
Netherlands until 2018.
□ Medium-term increase to 42 mn. tCO2 with higher exports of power to
neighbouring countries.
□ Long-term decrease by 51% from 2015 until 2040 to 25 mn. tCO2.
The specific CO2 emissions per unit of electricity produced in the Dutch electricity
system decreases (almost) steadily (Figure 35).
Figure 35.

Power sector CO2 emission NL
Total emissions in the Netherlands

Specific emissions (tCO2/MWh_el)

60

0.60
51
0.50
0.49
42

mntCO2

40

0.41

42

41
0.40

37
30

0.33

30

0.30
0.30

0.30

20

25

0.20

0.23
0.17

10

tCO2/MWh_el net generation

50

0.10

0

0.00
2015

2018

2020

2025

2030

2035

2040

Source: Frontier
Note:

82

Including emissions from CHP
Specific emissions calculated based on total net electricity generation

De-central CHP units are included based on an emission intensity of 483 gCO2/kWh_el

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B.3.2 CWE and neighbouring countries
As in The Netherlands, power supply in the European market (modelled
countries) is moving towards carbon-neutrality in the long-term. In the following,
we provide information on the development of carbon dioxide emissions in CWE
as well as in Great Britain and Denmark as interconnected country to The
Netherlands.83 Overall emissions from these countries decrease by ca. 67% from
2015 until 2040.84
Figure 36.

CO2 emissions in the Reference Case (CWE and neighbouring
countries)

mn. tCO2

NL

DE

FR

BE

GB

AT

CH

DK

800
700
600
500
400
300
200

100
0
1990*

2005*

2015

2018

2020

2025

2030

2035

2040

Source: Frontier
Note:

* 1990/2005 based on UNFCCC data (1.A.1.a - Public Electricity and Heat Production)

B.4 Development of power prices
In this section, we describe the development of wholesale power prices in The
Netherlands as well as in the neighbouring countries.

B.4.1 The Netherlands
In the past years, power prices in CWE and in The Netherlands have decreased
in line with low fuel and CO2 prices, shrinking power demand in some countries
and overcapacities in the generation sector. The development of Dutch power
prices is described by the following trends:

83

Great-Britain and Denmark are not part of the “core-region”, i.e. plant dispatch is modelled with a lower level
of detail and capacity development is assumed exogenously.

84

Historical emissions based on UNFCCC data (1.A.1.a - Public Electricity and Heat Production) are
comparable only to a limited extent (due to different definitions of included installations).

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Increasing price levels in the medium-to long-term
 Low price levels in the short-term (until 2020) – Due to low fuel prices and
remaining overcapacities, prices will remain below 40 EUR(real, 2015)/MWh
until 2020.
 Increase of price levels in the medium-term (2030) – Increasing tightening
of the market (e.g. DE/BE nuclear phase-out) on the one hand and increasing
CO2 and fuel prices on the other hand lead to a medium increase of power
prices in The Netherlands to 55 EUR(real, 2015)/MWh in 2025 and 61
EUR(real, 2015)/MWh in 2030.
Prices increase to 70 EUR(real, 2015)/MWh in 2035 with rising CO 2 and fuel
prices as well as a changing supply structure with lower shares of cheap
base-load generation (nuclear / lignite). After 2035, prices decrease slightly to
67 EUR(real, 2015)/MWh as renewable shares continue to rise and growing
interconnection capacities level out power production (including RES-E) and
power prices more equally across countries.
Figure 37.

Wholesale price development in The Netherlands (Reference
Case)
Historical prices (APX)

80

Reference Case

70
67

70
61

EUR(real, 2015)/MWh

60

55

50
42
40

39
35

30
20

10
0
2010

2015

2020

2025

2030

2035

2040

Source: Frontier

Increasing price volatility in the long-run
The share of electricity produced from intermittent renewable energy sources
increases significantly in the long-run compared to today. Consequently, the
share of hours with a tighter supply-demand balance in the electricity market and
corresponding high price levels is expected to increase. At the same time, the

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share of hours with an oversupply of renewable energy sources and
corresponding low (or even negative) price levels is also increasing (Figure 38).85
Figure 38.

Price duration curve NL (Reference Case)

200

150

maximum price

2015

2020

2030

2035

2040

EUR(real, 2015)/MWh

65

500

1500

2574

2346

2020

100

EUR/MWh

2015

50

2030

0

2035
-50
2040
-100

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

99%

Source: Frontier

B.4.2 CWE and neighbouring countries
As in the Netherlands, wholesale power prices are expected to increase in the
whole Central-Western European region in the medium and long term due to the
same underlying market drivers. In addition, prices in CWE are expected to
become increasingly integrated following an increase of interconnection capacity
and a converging supply structure across countries (increase in RES-E, lower
levels of cheap base-load generation).
 Price increase in Central-Western Europe – Wholesale power prices in
neighbouring countries to the Netherlands are increasing to levels of 60 – 76
EUR(real, 2015)/MWh for base-load (Figure 39). Belgium is the country in
CWE (excluding GB) with the highest price level in the short- and in the longrun.

85

We assume that negative prices occur in hours in which RES-E in-feed from RES-E exceeds demand
(curtailment costs).

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Comparison of base prices CWE (Reference Case) 2018 – 2040

Figure 39.

Base price 2018

Base price 2040

66.7 €/MWh

35.3 €/MWh

38.3 €/MWh

38.1€/MWh

32.3 €/MWh

38.2 €/MWh

76.4 €/MWh

72.2 €/MWh

67.2 €/MWh

72.9 €/MWh

Source: Frontier
Note:

Prices noted in real values (base year 2015)

 Integration of prices between Germany and The Netherlands in the
medium-term – Interconnection capacity between Germany and The
Netherlands is assumed to increase in the medium-term. In addition, the cost
structure of both electricity supply sectors converges. Therefore, the base
price difference between both countries decrease from 7 EUR(real,
2015)/MWh (modelled) in 2015 to 0.5 EUR(real, 2015)/MWh in 2020. After
2020, base price differences remain below 0.5 EUR(real, 2015)/MWh.86

86

It has to be noted that the price difference between countries/regions is to a high extend driven by the
assumptions on the availability of interconnection capacity. For example, if the assumed extension of IC
capacity between the Netherlands and Germany may not come in operation, price differences in 2020 will
be higher than displayed. Furthermore, the availability of IC capacity can be lower if the short term impact of
RES-E infeed in Germany on grid capacity is included. On the other hand, Flow Based Market Coupling can
increase available IC capacity. Therefore, the numbers provided should be interpreted as indications.

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Figure 40.

Development of base prices in selected countries

Base price
90
80

€(real,2015) /MWh

70
60

NL

50

DE

40

BE

30

FR

20

10
0
2015

2018

2020

2025

2030

2035

2040

Source: Frontier

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ANNEX C

DETAILED RESULTS OF THE
POLICY SCENARIOS

In this section, we provide more detailed information on the results of modelling
the impact of the different policy measures compared to the Reference Case. For
each policy scenario, we will report:
□ Impact on capacities and electricity supply in The Netherlands;
□ Impact on capacities and electricity supply in the model region; and
□ Impact on imports and exports of power from and to The Netherlands.

C.1 Scenario 1a
The figures below illustrate the impact of the implementation of additional
abatement measures at the coal plants without state compensation for
associated costs (Scenario 1a) on the electricity supply in The Netherlands and
in all modelled countries.

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Figure 41.

Impact on the Dutch electricity supply (Scenario 1a)
Difference of operational capacity
(Scenario 1a - Reference Case )
0.3

DSR
other

0.2

solar

0.1
wind_on
0.0
wind_off

GW

-0.1
-0.2

other_RES

-0.3

gas (decentral)

-0.4

oil

-0.5

gas

-0.6

coal

-0.7
2015

2018

2020

2025

2030

2035

2040

Difference of generation
(Scenario 1a - Reference Case )

nuclear

Net-imports
other

15

solar

10

wind_on

5

wind_off

TWh

20

other_RES

0

gas (decentral)

-5

oil

-10

gas

-15
coal

-20
2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

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Figure 42.

Impact on electricity supply (model-region) (Scenario 1a)
Difference of capacity (total system)
(Scenario 1a - Reference Case )

other

0.4

hydro
0.3

other_RES
0.2

gas
(decentral)
ROR

0.1
0.0

GW

solar
-0.1
wind_on
-0.2
wind_off
-0.3
oil
-0.4
gas
-0.5
coal

-0.6

lig

-0.7
2015

2018

2020

2025

2030

2035

2040

Difference of generation (total system)
(Scenario 1a - Reference Case )

nuclear

other

15

hydro
other_RES

10

gas
(decentral)
ROR

5

TWh

solar
wind_on

0

wind_off
oil

-5

gas
-10

coal
lig

-15
2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

Difference to the Reference Case

The figure below shows the level of imports and exports to and from The
Netherlands.

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Figure 43.

Imports/ Exports of power (NL) Scenario 1a
40

NORDPOOL > NL

30

NL > NORDPOOL
DK > NL

10

NL > DK

0

GB > NL

-10

NL > GB

TWh

20

BE > NL

-20

NL > BE

-30
DE > NL

-40
NL > DE

-50
2015

2018

2020

2025

2030

2035

2040

Net-Imports

Source: Frontier
Note:

Difference to the Reference Case

C.2 Scenario 1b
The figures below illustrate the impact of the implementation of additional
abatement measures at the coal plants with state compensation for associated
costs (Scenario 1b) on the electricity supply in The Netherlands and in all
modelled countries.

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Figure 44.

Impact on the Dutch electricity supply (Scenario 1b)
Difference of operational capacity
(Scenario 1b - Reference Case )

DSR

0.3

other

0.2

solar
wind_on

0.1

wind_off

GW

0.0
other_RES
-0.1

gas (decentral)

-0.2

oil
gas

-0.3

coal

-0.4
2015

2018

2020

2025

2030

2035

2040

Difference of generation
(Scenario 1b - Reference Case )

nuclear

Net-imports
other

20

solar
15

wind_on
wind_off

10

ROR

5

TWh

hydro
0

other_RES

-5

gas (decentral)
oil

-10

gas

-15

coal
lig

-20
2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

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Difference to the Reference Case

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Figure 45.

Impact on electricity supply (model-region) (Scenario 1b)
Difference of capacity (total system)
(Scenario 1b - Reference Case )

other

0.2

hydro

other_RES

0.0

gas
(decentral)
ROR

-0.1

solar

GW

0.1

wind_on
-0.2

wind_off
oil

-0.3

gas
-0.4

coal
lig

-0.5
2015

2018

2020

2025

2030

2035

2040

Difference of generation (total system)
(Scenario 1b - Reference Case )

nuclear

other

15

hydro
other_RES

5

gas
(decentral)
ROR

0

solar

TWh

10

wind_on
-5

wind_off
oil

-10

gas
-15

coal
lig

-20

2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

Difference to the Reference Case

The figure below shows the level of imports and exports to and from The
Netherlands.

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Figure 46.

Imports/ Exports of power (NL) Scenario 1b
40

NORDPOOL > NL

30

NL > NORDPOOL
DK > NL

10

NL > DK

0

GB > NL

-10

NL > GB

TWh

20

BE > NL

-20

NL > BE

-30
DE > NL

-40
NL > DE

-50
2015

2018

2020

2025

2030

2035

2040

Net-Imports

Source: Frontier
Note:

Difference to the Reference Case

C.3 Scenario 2
The figures below illustrate the impact of the implementation of a Carbon Floor
Price (Scenario 2) on the electricity supply in The Netherlands and in all modelled
countries.

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Figure 47.

Impact on the Dutch electricity supply (Scenario 2)
Difference of operational capacity
(Scenario 2 - Reference Case )
6.0

DSR
other
solar

5.0

wind_on

GW

4.0

wind_off
other_RES

3.0

gas (decentral)
2.0

oil
gas

1.0

coal

0.0
2015

2018

2020

2025

2030

2035

2040

Difference of generation
(Scenario 2 - Reference Case )

nuclear

Net-imports

15

other
solar

10

wind_on

TWh

5

wind_off
other_RES

0

gas (decentral)
-5

oil
-10

gas
coal

-15

2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

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Difference to the Reference Case

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Figure 48.

Impact on electricity supply (model-region) (Scenario 2)
Difference of capacity (total system)
(Scenario 2 - Reference Case )

other

10

hydro

other_RES

0

gas
(decentral)
ROR

-5

solar

GW

5

wind_on
-10

wind_off
oil

-15

gas
-20

coal
lig

-25
2015

2018

2020

2025

2030

2035

2040

Difference of generation (total system)
(Scenario 2 - Reference Case )

nuclear

other

100

hydro
80

other_RES

TWh

60
40

gas
(decentral)
ROR

20

solar

0

wind_on

-20

wind_off

-40

oil
gas

-60

coal

-80

lig
-100
2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

Difference to the Reference Case

The figure below shows the level of imports and exports to and from The
Netherlands.

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Figure 49.

Imports/ Exports of power (NL) Scenario 2
40

NORDPOOL > NL

30

NL > NORDPOOL
DK > NL

10

NL > DK

0

GB > NL

-10

NL > GB

TWh

20

BE > NL

-20

NL > BE

-30
DE > NL

-40
NL > DE

-50
2015

2018

2020

2025

2030

2035

2040

Net-Imports

Source: Frontier
Note:

Difference to the Reference Case

C.4 Scenario 3a
The figures below illustrate the impact closure of all coal-fired plants until 2020 on
the electricity supply in The Netherlands and in all modelled countries.

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Figure 50.

Impact on the Dutch electricity supply (Scenario 3a)
Difference of operational capacity
(Scenario 3a - Reference Case )

DSR

8.0

other

6.0

solar
wind_on

4.0

wind_off

GW

2.0
other_RES
0.0

gas (decentral)

-2.0

oil
gas

-4.0

coal
-6.0
2015

2018

2020

2025

2030

2035

2040

Difference of generation
(Scenario 3a - Reference Case )

nuclear

Net-imports
other

30

solar

20

wind_on

10

wind_off

0

other_RES

TWh

40

-10

gas (decentral)

-20

oil
gas

-30

coal

-40

2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

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Difference to the Reference Case

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Figure 51.

Impact on electricity supply (model-region) (Scenario 3a)
Difference of capacity (total system)
(Scenario 3a - Reference Case )

other

6

hydro
other_RES

4

gas
(decentral)
ROR

2

GW

solar
0

wind_on
wind_off

-2

oil

gas
-4

coal
lig

-6
2015

2018

2020

2025

2030

2035

2040

Difference of generation (total system)
(Scenario 3a - Reference Case )
30

nuclear

other
hydro
other_RES

20

gas
(decentral)
ROR

10

TWh

solar
0

wind_on
wind_off

-10

oil

gas

-20

coal
-30

2015

2018

2020

2025

2030

2035

2040

lig

Source: Frontier
Note:

Difference to the Reference Case

The figure below shows the level of imports and exports to and from The
Netherlands.

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Figure 52.

Imports/ Exports of power (NL) Scenario 3a
50

NORDPOOL > NL

40

NL > NORDPOOL

30
DK > NL
20
NL > DK
10

TWh

GB > NL
0
NL > GB
-10
BE > NL
-20
NL > BE
-30
DE > NL
-40
NL > DE

-50
2015

2018

2020

2025

2030

2035

2040

Net-Imports

Source: Frontier
Note:

Difference to the Reference Case

C.5 Scenario 3b
The figures below illustrate the impact closure of all coal-fired plants until 2025 on
the electricity supply in The Netherlands and in all modelled countries.

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Figure 53.

Impact on the Dutch electricity supply (Scenario 3b)
Difference of operational capacity
(Scenario 3b - Reference Case )

DSR

8.0

other

6.0

solar
wind_on

4.0

wind_off

GW

2.0
other_RES
0.0

gas (decentral)

-2.0

oil
gas

-4.0

coal

-6.0
2015

2018

2020

2025

2030

2035

2040

Difference of generation
(Scenario 3b - Reference Case )

nuclear

Net-imports
other

30

solar

20

wind_on

10

wind_off

0

other_RES

TWh

40

-10

gas (decentral)

-20

oil
gas

-30

coal

-40

2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

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Difference to the Reference Case

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Figure 54.

Impact on electricity supply (model-region) (Scenario 3b)
Difference of capacity (total system)
(Scenario 3b - Reference Case )

other

6

hydro
other_RES

4

gas
(decentral)
ROR

2

GW

solar
0

wind_on
wind_off

-2

oil

gas
-4

coal
lig

-6
2015

2018

2020

2025

2030

2035

2040

Difference of generation (total system)
(Scenario 3b - Reference Case )

nuclear

other

25

hydro
20
other_RES
15
gas
(decentral)
ROR

10
5

TWh

solar
0
wind_on
-5
wind_off

-10
oil
-15

gas
-20
coal
-25
lig
-30
2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

Difference to the Reference Case

The figure below shows the level of imports and exports to and from The
Netherlands.

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Figure 55.

Imports/ Exports of power (NL) Scenario 3b
40

NORDPOOL > NL

30

NL > NORDPOOL
DK > NL

10

NL > DK

0

GB > NL

-10

NL > GB

TWh

20

BE > NL

-20

NL > BE

-30
DE > NL

-40
NL > DE

-50
2015

2018

2020

2025

2030

2035

2040

Net-Imports

Source: Frontier
Note:

Difference to the Reference Case

C.6 Scenario 3c
The figures below illustrate the impact closure of all coal-fired plants until 2030
and the implementation of additional measures on the electricity supply in The
Netherlands and in all modelled countries.

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Figure 56.

Impact on the Dutch electricity supply (Scenario 3c)
Difference of operational capacity
(Scenario 3c - Reference Case )

DSR

8.0

other

6.0

solar
wind_on

4.0

wind_off

GW

2.0
other_RES
0.0

gas (decentral)

-2.0

oil
gas

-4.0

coal
-6.0
2015

2018

2020

2025

2030

2035

2040

Difference of generation
(Scenario 3c - Reference Case )

nuclear

Net-imports

30

other
solar

20

wind_on

TWh

10

wind_off
other_RES

0

gas (decentral)

-10
oil
-20

gas
coal

-30
2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

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Difference to the Reference Case

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Figure 57.

Impact on electricity supply (model-region) (Scenario 3c)
Difference of capacity (total system)
(Scenario 3c - Reference Case )

other

6

hydro
other_RES

4

gas
(decentral)
ROR

2

GW

solar
wind_on

0

wind_off
oil

-2

gas
-4

coal
lig

-6
2015

2018

2020

2025

2030

2035

2040

Difference of generation (total system)
(Scenario 3c - Reference Case )

other

25

hydro

20

other_RES

15

gas
(decentral)
ROR

10

solar

5

TWh

nuclear

wind_on

0

wind_off

-5

oil

-10

gas
-15
coal
-20
lig
-25
2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

Difference to the Reference Case

The figure below shows the level of imports and exports to and from The
Netherlands.

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Figure 58.

Imports/ Exports of power (NL) Scenario 3c
40

NORDPOOL > NL

30

NL > NORDPOOL
DK > NL

10

NL > DK

0

GB > NL

-10

NL > GB

TWh

20

BE > NL

-20

NL > BE

-30
DE > NL

-40
NL > DE

-50
2015

2018

2020

2025

2030

2035

2040

Net-Imports

Source: Frontier
Note:

Difference to the Reference Case

C.7 Scenario 3d
The figures below illustrate the impact closure of all coal-fired plants until 2040
and the implementation of additional measures on the electricity supply in The
Netherlands and in all modelled countries.

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Figure 59.

Impact on the Dutch electricity supply (Scenario 3d)
Difference of operational capacity
(Scenario 3d - Reference Case)
6.0

DSR
other

5.0

solar

4.0
wind_on
3.0
wind_off

GW

2.0
1.0

other_RES

0.0

gas (decentral)

-1.0

oil

-2.0

gas

-3.0

coal

-4.0
2015

2018

2020

2025

2030

2035

2040

Difference of generation
(Scenario 3d - Reference Case)

nuclear

Net-imports
other

15

solar

10

wind_on

5

wind_off

0

other_RES

-5

gas (decentral)

-10

oil

TWh

20

gas

-15

coal

-20
2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

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Figure 60.

Impact on electricity supply (model-region) (Scenario 3d)
Difference of capacity (total system)
(Scenario 3d - Reference Case)

other

6

hydro
5

other_RES

GW

4
3

gas
(decentral)
ROR

2

solar

1

wind_on

0

wind_off

-1

oil

gas

-2

coal

-3

lig
-4
2015

2018

2020

2025

2030

2035

2040

Difference of generation (total system)
(Scenario 3d - Reference Case)

nuclear

other
hydro

15

other_RES
10

gas
(decentral)
ROR

5

TWh

solar
wind_on

0

wind_off
oil

-5

gas
-10

coal
lig

-15
2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

Difference to the Reference Case

The figure below shows the level of imports and exports to and from The
Netherlands.

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Figure 61.

Imports/ Exports of power (NL) Scenario 3d
40

NORDPOOL > NL

30

NL > NORDPOOL
DK > NL

10

NL > DK

0

GB > NL

-10

NL > GB

TWh

20

BE > NL

-20

NL > BE

-30
DE > NL

-40
NL > DE

-50
2015

2018

2020

2025

2030

2035

2040

Net-Imports

Source: Frontier
Note:

Difference to the Reference Case

C.8 Scenario 3e
The figures below illustrate the impact of a closure of the two oldest coal-fired
plants until 2020 and the implementation of additional measures at the remaining
plants (from 2025) on the electricity supply in The Netherlands and in all
modelled countries.

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Figure 62.

Impact on the Dutch electricity supply (Scenario 3e)
Difference of operational capacity
(Scenario 3e - Reference Case)
1.5

DSR
other
solar

1.0

wind_on

GW

0.5

wind_off
other_RES

0.0

gas (decentral)
-0.5

oil
gas

-1.0

coal
-1.5
2015

2018

2020

2025

2030

2035

2040

Difference of generation
(Scenario 3e - Reference Case)

nuclear

Net-imports
other

15

solar

10

wind_on

5

wind_off

0

other_RES

-5

gas (decentral)

-10

oil

TWh

20

gas

-15

coal

-20
2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

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Difference to the Reference Case

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Figure 63.

Impact on electricity supply (model-region) (Scenario 3e)
Difference of capacity (total system)
(Scenario 3e - Reference Case)

other

2

hydro
other_RES

1

gas
(decentral)
ROR

1

solar

GW

2

wind_on
0

wind_off
oil

-1

gas
-1

coal
lig

-2
2015

2018

2020

2025

2030

2035

2040

Difference of generation (total system)
(Scenario 3e - Reference Case)

other
hydro

20

other_RES

15

TWh

nuclear

10

gas
(decentral)
ROR

5

solar
wind_on

0

wind_off
-5

oil

-10

gas
coal

-15

lig
-20
2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

Difference to the Reference Case

The figure below shows the level of imports and exports to and from The
Netherlands.

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Figure 64.

Imports/ Exports of power (NL) Scenario 3e
40

NORDPOOL > NL

30

NL > NORDPOOL
DK > NL

10

NL > DK

0

GB > NL

-10

NL > GB

TWh

20

BE > NL

-20

NL > BE

-30
DE > NL

-40
NL > DE

-50
2015

2018

2020

2025

2030

2035

2040

Net-Imports

Source: Frontier
Note:

Difference to the Reference Case

C.9 Scenario 3f
The figures below illustrate the impact of a closure of the two oldest coal-fired
plants until 2020 on the electricity supply in The Netherlands and in all modelled
countries.

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Figure 65.

Impact on the Dutch electricity supply (Scenario 3f)
Difference of operational capacity
(Scenario 3e - Reference Case)
1.5

DSR
other
solar

1.0

wind_on

GW

0.5

wind_off
other_RES

0.0

gas (decentral)
-0.5

oil
gas

-1.0

coal
-1.5
2015

2018

2020

2025

2030

2035

2040

Difference of generation
(Scenario 3e - Reference Case)

nuclear

Net-imports

10

other

8

solar

6
wind_on

4

wind_off

TWh

2
0

other_RES

-2

gas (decentral)

-4

oil

-6

gas

-8
coal

-10
2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

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Difference to the Reference Case

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Figure 66.

Impact on electricity supply (model-region) (Scenario 3f)
Difference of capacity (total system)
(Scenario 3e - Reference Case)

other

2

hydro
other_RES

1

gas
(decentral)
ROR

1

solar

GW

2

wind_on
0

wind_off
oil

-1

gas
-1

coal
lig

-2
2015

2018

2020

2025

2030

2035

2040

Difference of generation (total system)
(Scenario 3e - Reference Case)

other
hydro

8

other_RES

6

TWh

nuclear

4

gas
(decentral)
ROR

2

solar
wind_on

0

wind_off
-2

oil

-4

gas
coal

-6

lig
-8
2015

2018

2020

2025

2030

2035

2040

nuclear

Source: Frontier
Note:

Difference to the Reference Case

The figure below shows the level of imports and exports to and from The
Netherlands.

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Figure 67.

Imports/ Exports of power (NL) Scenario 3f
40

NORDPOOL > NL

30

NL > NORDPOOL
DK > NL

10

NL > DK

0

GB > NL

-10

NL > GB

TWh

20

BE > NL

-20

NL > BE

-30
DE > NL

-40
NL > DE

-50
2015

2018

2020

2025

2030

2035

2040

Net-Imports

Source: Frontier
Note:

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ANNEX D

MODEL DESCRIPTION

This section provides a technical description of the European power market
model used in this study. The combined investment and dispatch model of the
European power market is based on a linear optimisation problem87. The model
optimises the hourly dispatch of the power plants as well as the development of
installed capacity based on representative hours and selected photo-years. It is
formulated in GAMS, and draws on extensive Excel databases for inputs and
outputs. The model has the following characteristics:
 Objective function – The objective function is to minimize total costs88 of the
electricity supply in Europe. The model minimizes total costs subject to the
following constraints:
□ Energy supply and consumption must be balanced in every hour in every
regions;
□ Power exchange between modelled regions is limited by interconnection
capacity;
□ Technical and economic constraints for power plants, storages, DemandSide Response (DSR) as well as renewable energy sources.
 Investment options – In order to meet future demand at the least cost, the
model optimises the power plant park in the so-called “core-regions”89 of our
model through either:
□ Investing in new capacities subject to technical and economic parameters
and availability of different technological options;
□ Closing of existing power plants in the case of overcapacity; or
□ Mothballing plants and reactivation at a later point in time in order to save
fixed operation and maintenance costs.
 Temporal resolution – The model is an integrated investment- and dispatch
model. Therefore, the time frame for optimisation follows the technical lifetime
of power plants. The time horizon for our analysis is from 2015 until 2049 with
an hourly resolution of 4032 representative hours per photo-year.90
 Geographical scope – Our model focusses on Central-Western Europe as
core-regions. Other neighbouring countries are included as non-core regions
or satellite regions. This differentiation allows to model the power plant park of
the core-region on a very detailed (unit-based) basis, but power exchange
with other regions that are modelled with lower granularity and level of detail
are at the same time included:

87

The optimisation problem is solved with the commercial Solver CPLEX.

88

Total costs are minimized as net present value (NPV) today. This includes a discounting of future costs, i.e.
comparable to an investment appraisal where short-term profits and costs are treated with higher time
preference. We use an interest rate of 5% for the discounting of future costs and profits as well as for the
calculation of investment costs of different power plants.

89

The core-regions of our model are the Netherlands, Belgium, Germany, Austria and France.

90

Analysed photo-years: 2018, 2020,2025, 2030, 2035, 2040

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□ Core-regions: The Netherlands, Belgium, Germany, Austria and France.
The power plant park is modelled on a very detailed (unit-based) level, the
dispatch of power plants and DSR as well as investment or divestment
decisions are endogenously optimised (countries coloured in red, Figure
68).
□ Other model regions: Great Britain, Denmark, Poland, Czech Republic,
Switzerland, Italy. The power plant park is modelled as aggregated blocks.
Capacity is set exogenously, i.e. investment and divestment decisions are
not optimised (countries coloured in dark blue, Figure 68).
□ Satellite regions: Other adjacent regions - for example South-Eastern
Europe, the Noordpool region and Spain - are modelled as satellite
regions. Power can be traded with those regions based on an exogenous
price (countries coloured in light blue, Figure 68).
Figure 68.

Geographical scope of the model

Core-region
(investment and dispatch)
Other model regions
(dispatch)
Satellite regions
(merit order price)

Source: Frontier

 Security of Supply and Loss-of-load – Demand has to be balanced in every
hour and in every region. Through system-cost-minimisation, the model
derives the efficient development of generation capacities and power plant
dispatch (subject to additional technical and economic constraints). In order to
fulfil the hourly energy balance, the model can also chose “involuntary load
curtailment”, i.e. not to meet demand in every hour. This involuntary load
curtailment or Loss-of-Load induces additional costs that are included in the
objective function, the “Value-of-lost-Load”. Hence, we indirectly model the
incentives for market participants to balance their supply obligations on then
one hand side with actual power deliveries on the other hand side. The level
of incentive to be balanced is given by the assumption on the Value of Lost

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Load, which can be interpreted as the penalty for suppliers for the nondelivery of electricity to consumers91

91

Assumed Value-of-lost-Load: 15.000 €/MWh. Our estimation is based on ENTSO-E (2013); Frontier
Economics/Format Services (2014).

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ANNEX E

LIST OF REFERENCES

 Al-Naiema et al. (2015): Impacts of co-firing biomass on emissions of
particulate matter to the atmosphere, Fuel, Vol. 162, p. 111-120.
 Department of Energy and Climate Change (DECC) (2011): Planning our
electric future: a White Paper for secure, affordable and low‑carbon
electricity.
 Cao et al. (2008): Mercury Emissions during Cofiring of Sub-bituminous Coal
and Biomass; Environmental Science & Technology (2008), Vol. 42 (24), p.
9378-9384.
 CE Delft (2015): Kentallen voor grijze en ‘niet-geoormerkte stroom’ inclusief
upstream-emissies, Delft, January 2015).
 CE Delft / DNV GL (2014): Toekomst WKK en warmtevoorziening industrie,
Delft.
 ECN (2014): Berekening basisbedragen SDE (+) 2015.
 ECN/PBL (forthcoming): Nationale Energieverkenning 2016.
 ECN/PBL (2015): Nationale Energieverkenning 2015.
 ECN/PBL (2014): Nationale Energieverkenning 2014.
 European Commission (2012): The state of the European carbon market in
2012, COM (212, 652), Brussels.
 European Network of Transmission System Operators for Electricity (ENTSOE) (2014): “Scenario Outlook & Adequacy Forecast 2014-2030”, Brussels.
 Frontier Economics (2015): Scenarios for the Dutch electricity supply system,
A report for the Ministry of Economic Affairs.
 IEA (2014): “World
(IEA/OECD), Paris.

Energy

Outlook”,

International

Energy

Agency

 IEA Clean Coal Centre (2010): Profiles – Emission from co-firing coal,
biomass and sewage sludge (PF 10-16)
 Henderson (2015): Cofiring of biomass in coal-fired power plants – European
perspective;
 HM Revenue & Customs (2014): Carbon Price Floor: Reform and other
technical amendments.
 Letter from the Minister of Economic Affairs to the Second Chamber of the
Dutch Parliament (18.12.2015): Kabinetsaanpak Klimaatbeleid op weg naar
2020; Tweede Kamer, vergaderjaar 2015–2016, 30 196, nr. 380
 Ministerie van Economische Zaken (20.04.2016): Beantwoording over het
onderzoek 'Sluiting kolencentrales' van SEO in opdracht van Natuur & Milieu.
 Pentalateral Energy Forum Support Group 2 (2015): Generation Adequacy
Assessment.

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 Reuters (17 May 2016): France will set Carbon Price Floor at about 30
euros/T;
http://af.reuters.com/article/commoditiesNews/idAFL5N18E1R3?sp=true
 TenneT TSO B.V. (2015): Rapport Monitoring Leveringszekerheid 2014-2030,
Arnhem.

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economics
www.frontier-economics.com

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