The Costs ofDecarbonisation:
System Costs with High
Shares of Nuclear andRenewables

Executive Summary

Nuclear Technology Development and Economics

The Costs of Decarbonisation: System Costs withHigh Shares of Nuclear and Renewables
Executive Summary© OECD 2019
NEA No. 7335
NUCLEAR ENERGY AGENCY
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NUCLEAR ENERGY AGENCYThe OECD Nuclear Energy Agency (NEA) was established on 1 February 1958. Current NEA membershipconsists of 33 countries: Argentina, Australia, Austria, Belgium, Canada, the Czech Republic, Denmark,Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Japan, Korea, Luxembourg, Mexico, theNetherlands, Norway, Poland, Portugal, Romania, Russia, the Slovak Republic, Slovenia, Spain, Sweden,
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Cover photos: Hydroelectric power station (Shutterstock/Gary Saxe); Brokdorf nuclear power plant, Germany (Alois Staudacher); Electricity pylon;
Wind turbines (Shutterstock/Carlos Castilla).

Executive summary

This study sets out to assess the costs of alternative low-carbon electricity systems capable ofachieving strict carbon emission reductions consistent with the aims of the Paris Agreement.
It thus compares the total costs of six different scenarios of the electric power sector of arepresentative OECD country, all of which are consistent with a low-carbon constraint of only
50 gCO2 per kW, but which contain different shares of nuclear energy and renewable energies,
in particular wind and solar photovoltaic (PV). These shares vary between 0% and 75% of total
electricity consumption. A low variable renewable energy (VRE) investment cost scenario
completes this analysis by assuming significant future cost reductions for VRE. Two sensitivity
analyses built around different levels of available flexibility resources (availability ofinterconnection or flexible hydroelectric resources) complete a suite of altogether eightscenarios allowing a good understanding of the principal drivers of the costs ofdecarbonisation (see Figure ES1 below). In particular, the study highlights the impacts thevariability of wind and solar PV production have on electricity system costs, which appears as
costly adjustments to the residual system.

Sensitivity scenarios

Main scenarios

Figure ES1. Eight scenarios to study the cost of low-carbon
electricity systems with 50 gCO2 per kWh(I to V)

Base case

10% VRE

50% VRE

75% VRE

Low VRE cost

Low-cost VRE (VI)
No interconnections (VIi)

No interconnections
and no flexible hydro30% VRE(VIiI)No IC

No IC, No
hydro
VRE penetration level (net)

The present study not only highlights the costs of achieving ambitious carbon targets but
also sets out a policy framework for achieving them in a least-cost manner. The five principal
pillars of this framework are 1) setting a robust price for carbon emissions, 2) short-term
markets for efficient dispatch and revealing the system value of electricity, 3) regulation for
the adequate provision of capacity, flexibility and infrastructures for transmission anddistribution, 4) mechanisms to enable long-term investment in low-carbon technologies,
including the reform of existing mechanisms and 5) the internalisation of system costs
wherever practical and necessary. Achieving radical carbon emission reductions does notcome for free. However this study shows that defining the right overall mix of the shares ofnuclear energy and renewables as well as setting the right policy framework will allow theachievement of radical climate targets while respecting high standards of the security ofelectricity supply and overall reasonable costs to electricity consumers.
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EXECUTIVE SUMMARY

The context
Under the Paris Agreement, which was concluded in December 2015 and entered into force inNovember 2016, many OECD countries agreed to aim for a reduction of their greenhouse gas
emissions sufficient to hold the increase in the global average temperature to well below 2°C
above pre-industrial levels. This implies a major effort to decarbonise their electric power
sectors. Holding the increase of global temperatures to 2°C requires limiting greenhouse gas
concentrations in the earth’s atmosphere to roughly 450 ppm of CO2-equivalent emissions.
This requires a massive effort to decarbonise electricity generation, as the electricity sector is
expected to bear the brunt of the effort to reduce emissions during the next three decades.
Projections indicate that in order to achieve reductions commensurate with the 2° objective,
CO2 emission from the electric power sectors of OECD countries would need to be reduced byalmost 90% by mid-century. The average carbon intensity of the electricity produced in OECD
countries of 430 gCO2 per kWh today would need to be reduced to roughly 50 gCO2 per kWhby 2050.
This decarbonisation will require a radical restructuring of the electric power sectors ofeach OECD countries and a truly massive deployment of low-carbon technologies, in particular
nuclear energy and renewable energies such as wind and solar PV. Other generation options,
including hydropower, are limited in a window of only 25-35 years, which is short given the
intrinsic inertia of electricity systems, where power plants and transmission infrastructure
frequently have lifetimes of 60 years and more.
Renewable energies have enjoyed in recent years both popular and political support. While
average costs per MWh of wind and solar PV are still somewhat higher than those of nuclear
energy, the cost gap at the level of plant-level generation costs (as calculated with thelevelised cost of electricity (LCOE) methodology as set out in the 2015 OECD study on the
Projected Costs of Generating Electricity) no longer seems insurmountable. However, as spelled
out in the first OECD Nuclear Energy Agency (NEA) study on system costs, Nuclear Energy and
Renewables: System Costs in Decarbonising Electricity Systems (2012), VRE technologies such as
wind and solar PV cause a number of additional costs to the system, which are referred to assystem costs.
The most important categories of the system costs of VREs are increased outlays for
distribution and transmission due to their small unit size and distance from load centres,balancing costs to prepare for unpredictable changes in wind speed and solar radiation and,perhaps, most importantly, the costs for organising reliable supplies through the residual
system during the hours when wind and sun are not fully available or not available at all.
Variability also induces significant changes in the composition of the remainder of dispatchable
technologies that ensure round-the-clock security of supply in the power system. When
deploying VREs, one observes, in particular, a shift from technologies with high fixed cost, suchas nuclear power to more flexible technologies with low fixed cost such as gas-fired power
generation. While the latter will be able to better absorb the loss of operating hours due to VRE
infeed, the overall costs of the residual system will increase, an effect known as “profile costs”.
In addition, deploying VREs does not automatically translate into carbon emission reductions.
For instance, when nuclear power is substituted by a mix of VREs and gas-fired generation that
produces electricity when VREs are not available, overall carbon emissions will increase.
All technologies have system costs. Nuclear, for instance, requires particularly strong
network connections and access to reliable cooling sources. However, these costs turn out tobe an order of magnitude lower than those imposed by the variability of renewable energies.
The key advantage of nuclear power in the economic competition with wind and solar PV isthe fact that nuclear power plants are dispatchable, i.e. they can produce large amounts ofcarbon free baseload power in a reliable and predictable fashion. In the context of thedecarbonisation of electricity systems, this poses three important questions:

4•

What is the optimal mix of nuclear baseload and variable renewables from an
economic point of view and what is the added cost of reaching a CO2 emission target
with exogenously imposed shares of renewable generation?

•

Are electricity systems that are trying to reach these objectives primarily with large
shares of variable renewables technically and, in particular, economically viable?
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EXECUTIVE SUMMARY•

What are the key policy instruments for creating frameworks that enable the level ofinvestment in low-carbon generation technologies required to ensure a transition
towards deeply decarbonised electricity systems?

The precise answers to these questions depend on a number of qualifying conditions, forinstance the amount of flexibility resources available in an electricity system that are spelled
out throughout the study using a “greenfield approach”, where the system is optimised andcosts are minimised without making any assumptions about the existing power generation
mix other than the availability of hydroelectric resources. This improves the transparency andreadability of the modelling results, and thus their pertinence for policy making in a timeframe that spans all the way to 2050.

The defining features of this study and the nature of system costs
Today, system costs are no longer part of an unfamiliar concept but a universally accepted
part of electricity system analysis. The first NEA study on system costs, published in 2012,
was part of an early wave of studies that were instrumental in introducing andconceptualising the notion of system costs. While the initially developed concepts, as well as
the basic methodology of working with residual load curves to assess profile cost, have
proven robust, much has changed during the past five years. Among the changes that need tobe accounted for are:•the significant decline in the LCOE costs of renewable energies, in particular for solar
PV, as documented in the changes in investment costs reported in the IEA/NEA reportson the Projected Costs of Generating Electricity for 2010 and 2015;•

the emergence of a broad and lively literature on the system costs of electricity systems,
which includes the emergence of a widely shared methodological framework forassessing profile costs;•

a greater awareness and better understanding by policy makers of the importance ofsystem costs•

a clearer idea of the policy-relevant questions that can be usefully asked and answeredby the available conceptual and modelling tools given the present state of knowledge.

From the outset, it was clear that any new study should not simply provide an update of
the well-regarded 2012 study. In the present study, great care has been expended to constructa representation of the electricity sector in a manner as complete as possible. In this process,the NEA worked with a team of experienced power system modellers at the Massachusetts
Institute of Technology (MIT). NEA modelling of the eight scenarios is thus built on the
Optimal Electricity Generation Expansion (GenX) model developed at MIT, which provides thedetailed, comprehensive and flexible representation of an integrated electricity system thatwas required.
The electricity sector model that underlies this study thus includes not only hourly
dispatch but also ramping constraints and reserve requirements that preserve both systemstability and economic equilibrium. In addition, a carefully selected set of credible flexibility
options has been added to the model. They include interconnections with neighbouring
countries, a relatively high share of flexible hydroelectric resources, demand-side management(DSM) and several storage options. Both technological and flexibility options are importantdrivers of total system costs. This holds, in particular, if electricity generation includes a large
share of wind and solar PV, since their variability challenges the workings of the system byincreasing ramp costs and reserve requirements, and it also increases the demand for different
flexibility options.
The defining feature of this modelling effort is the fact that all scenarios include the same
stringent carbon constraint of 50 gCO2 per kWh, which is consistent with a level that theelectricity systems of OECD countries must achieve to contribute their share to limit theincrease in global mean temperatures to 2°C. In order to allow for economic results that are as
general, relevant and transparent as possible (and thus independent of the power generation
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EXECUTIVE SUMMARY

mix of a particular country), this study has taken a “greenfield approach”. This means thatstarting with a clean slate the electricity system evolves only as a function of electricity
demand throughout the year and the specific costs of different technologies in an optimal
fashion as if all plants were built from scratch on a green field. This approach is limited onlyby the exogenously imposed constraints, i.e. carbon emissions of 50 gCO2 per kWh anddifferent shares of VRE generation that are specified ex ante. Only the share of hydroelectric
resources has been set exogenously.
The alternative – using a brownfield approach – would have yielded different results. In
function of the existing mix, the results in this volume might help individual countries tobetter assess the cost of their transitions. However, the results of brownfield modelling would
not allow drawing comparable general conclusions about the respective costs of electricity
systems with different shares of nuclear and renewables. In particular, for variable renewables
such as wind and solar PV, the total system costs are highly dependent on local conditions
and the structure of the residual system.
VREs, more specifically wind and solar PV, share some specific characteristics that maketheir integration into the electricity system particularly challenging. The IEA has identified six
technical and economic characteristics that are specific to VRE and are a key element to
explain and understand the system costs associated with their integration. The output of VRE
is thus:•

Variable: the power output fluctuates with the availability of the resource (wind andsolar) and not in function of demand or system needs.

•

Uncertain: the amount of power produced cannot be predicted with precision. However,
the accuracy of generation forecast increases with approaching the time of delivery.

•

Location-constrained: the available renewable resources are not equally good in all
locations and cannot be transported. Favourable sites are often far away from load
centres.

•Non-synchronous: VRE plants must be connected to the grid via power electronics andare not directly synchronised with the grid.

•

Modular: the scale of an individual VRE unit is much smaller than other conventional
generators.

•

With low variable costs: once built, VRE generate power at little operational cost. The
short-run marginal costs of wind and solar PV units are zero.

The concept of system effects, which are heavily driven by these six attributes of VRE, hasbeen conceptualised and explored extensively by the NEA and the IEA, and has benefitted
from a significant amount of new research from academia, industry and governments. Systemeffects are often divided into the following four broadly defined categories of profile costs (alsoreferred to as utilisation costs or backup costs by some researchers), balancing costs, grid costs
and connection costs.
Profile costs (or utilisation costs) refer to the increase in the generation cost of the overall
electricity system in response to the variability of VRE output. They are thus at the heart of thenotion of system effects. They capture, in particular, the fact that in most of the cases it ismore expensive to provide the residual load in a system with VRE than in an equivalentsystem where VRE are replaced by dispatchable plants. A different way of looking at the
profile costs of VRE is to consider that the electricity generation of wind or solar PV isconcentrated during a limited number of hours with favourable meteorological conditions.
This decreases value for the system of each additional VRE unit and corresponds to an
equivalent increase in profile costs. In addition, the presence of VRE generation generally
increases the variability of the residual load, which exhibits steeper and more frequent ramps.
This causes an additional burden, also called the flexibility effect, to other dispatchable plants
in terms of more start-ups and shutdowns, more frequent cycling and steeper ramping
requirements, leading to lower levels of efficiency, an increase in the wear and tear of
equipment and higher generation costs.

6

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EXECUTIVE SUMMARY

Balancing costs refer to the increasing requirements for ensuring the system stability due
to the uncertainty in the power generation (unforeseen plant outages or forecasting errors ofgeneration). In the case of dispatchable plants, the amount and thus the cost of operating
reserves are generally given by the largest contingency in terms of the largest unit (or the twolargest units) connected to the grid. In case of VRE, balancing costs are essentially related tothe uncertainty of their output, which may become important when aggregated over a large
capacity. Forecasting errors may require carrying on a higher amount of spinning reserves inthe system.
Grid costs reflect the increase in the costs for transmission and distribution due to the
distributed nature and locational constraint of VRE generation plants. However, nuclear plants
also impose grid costs due to siting requirements for cooling and transmission. Grid costs
include the building of new infrastructures (grid extension) as well as increasing the capacityof existing infrastructure (grid reinforcement). In addition, transmission losses tend toincrease when electricity is moved over long distances. Distributed solar PV resources may, inparticular, require investing in distribution networks to cope with more frequent reverse
power flows occurring when local demand is insufficient to consume the electricity generated.
Connection costs consist of the costs of connecting a power plant to the nearest
connecting point of the transmission grid. They can be significant especially if distantresources (or resources with a low load factor) have to be connected, as can be the case foroffshore wind, or if the technology has more stringent connection requirements as is the casefor nuclear power. Connection costs are sometimes integrated within system costs (see NEA,
2012), but are sometimes also included in the LCOE plant-level costs. This reflects commercial
realities as different legislative regimes require connection costs either to be borne by plantdevelopers or by the transmission grid operator. In the former case, they are part of the plantlevel costs and thus fully internalised, while in the latter case they are externalities to beaccounted for in the system costs.
The above list of four cost categories of system costs is not fully exhaustive. The provisionof physical inertia, which is implicitly provided by dispatchable plants but not by VRE, is thus
emerging as a topic of research. Together, the four categories nonetheless make up the bulk ofsystem costs. Figure ES2 below summarises them.

Figure ES2. Illustration of system cost

Integration
costs

EUR/MWh

Short-term
integration
costs

Generation
costs

LCOE

Profile Balancing
costs
costs

Grid
costs

Short- Flexibility Systemterm
options LCOE
system
LCOE

Source: OECD, 2015.

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EXECUTIVE SUMMARY

Modelling results from the NEA system cost study
The NEA study shows that combining explicit targets for VRE technologies and a stringent limit
on carbon emissions has important impacts on the composition of the generation mix and its
cost. In particular, total generation capacity increases significantly with the deployment of VRE
resources. Since the load factor and the capacity credit of VRE is significantly lower than that ofconventional thermal power plants, a significantly higher capacity is needed to produce thesame amount of electricity. While about 98 GW are installed in the base case scenario without
VRE, the deployment of VRE up to penetration levels of 10% and 30% increases the total
capacity of the system to 118 and 167 GW, respectively. The total installed capacity would morethan double to 220 GW if a VRE penetration level of 50% must be reached. More than 325 GW,
i.e. more than three times the peak demand, are needed if VRE generate 75% of the total
electricity demand. In other words, as the VRE penetration increases vast excess capacity, thus
investment, is needed to meet the same demand. The capacity mix of different generation
technologies in the five main scenarios is illustrated in Figure ES3, while their respective
electricity generation share is shown in Figure ES4 below.
Figure ES3. The capacity mix with different shares of VRE
350
300

Battery storage
OCGT

Installed capacity (GW)

250

CCGT

200

Solar
Onshore wind

150

NuclearHydro pump storage

100

Hydro reservoir

50

Hydro run-of-the-river0
Base case

10% VRE

30% VRE

50% VRE

75% VRE

Decarbonisation scenario

Figure ES4. Electricity generation share in the main region (main scenarios)
600
Interconnections
DSM
Battery storage
Battery storage - charge
OCGT
CCGT
Solar
Onshore wind
NuclearHydro pump storage
Hydro pump storage - charge
Hydro reservoir
Hydro run-of-the-river

Electricity generation (TWh)

500
400
300
200
100
0
-100
Base case8

10% VRE

30% VRE

50% VRE

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EXECUTIVE SUMMARY

The integration of VRE changes the long-term structure of the thermal generation mix.
The share of fossil-fuelled generation (open cycle gas turbine [OCGT] and combined cycle gas
turbines [CCGT]) remains almost constant in all scenarios, as it is limited by the carbon cap.
However, the structure of the capacity installed of gas plants and the relative share ofgeneration from OCGT and CCGT changes significantly with the presence of VRE. While thecapacity of CCGT power plants is almost constant in all scenarios considered, they areoperated at lower load factor in the scenarios with more variable generation. Anotherimportant finding is that, under the stringent carbon constraint adopted for this study, coal isnever deployed in any of the scenarios considered, despite being cheaper than the othertechnologies on a pure LCOE basis. In terms of generation, VRE displaces nuclear power almost
on a one-to-one basis, which results from the fixed carbon constraint in combination with afixed amount of hydroelectric resources.
The way in which thermal plants operate also changes significantly, with a reduction of
the average load factors and an increase of ramping and load-following requirements.
Figure ES5 shows the projected hourly generation pattern of the nuclear fleet for four of thefive main scenarios considered (there is no nuclear generation under the 75% VRE). This
allows a visualisation of the increased flexibility requirements from nuclear plants, as well as
the reduction in nuclear capacity associated with VRE deployment.
Figure ES5. Projected generation pattern from nuclear power plants
Base case

Generation from nuclear PPs (GW)50

10% VRE

30% VRE

50% VRE

40

30

20

10

0
0

1 000

2 000

3 000

4 000

5 000

6 000

7 000

8 000

Year (hours)

Nuclear capacity progressively decreases with the share of renewables. In the base casescenario with the lowest cost and no VRE, nuclear power is the major source of low-carbon
electricity and produces about 75% of the total electricity demand with minimal demand on
flexibility. At higher rates of VRE, the demand for nuclear flexibility increases progressively. In
the 50% VRE case, nuclear units must ramp up and down by a maximal 30-35% of theirinstalled capacity in one hour.
The changes in the capacity mix, the generation mix and load factors of the different
technologies can be captured in the system costs of the different scenarios. Additional gridcosts, balancing and connection costs are thus added to the profile costs already implicitly
calculated in the different optimised scenarios. As already mentioned, profile costs result fromthe de-optimisation of the residual system due to the variability of VRE. Total system costs,
expressed in USD per unit of net electricity delivered by VRE to the grid are shown in
Figure ES6 for the four scenarios of 10%, 30%, 50% and 75% VRE as well as for the twosensitivity scenarios. These system costs must be understood as the increase of the total costs
to provide the same service of electricity supply above the costs of the least-cost scenario
without any VRE. System costs in the reference system are zero since the issue of variability
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EXECUTIVE SUMMARY

does not arise because all the electricity is generated by dispatchable technologies. The figure
also provides a breakdown of the total system costs into the four main components. Also, anerror bar provides an indication of the uncertainty range deriving from a range of possible
assumptions on grid, connection and balancing costs.
Figure ES6. System costs per MWh of VRE
60

Profile costs

Connection costs

Balancing costs

Grid costs

System costs (USD/MWh VRE)

50
40
30
20
10
0
Main scenario
10% VRE

30% VRENo IC

No IC, noflexible hydro50% VRE

75% VRE

System costs vary between less than USD 10 per MWh of VRE for a share of 10% of windand solar PV to more than USD 50 per MWh of VRE for a share of 75% of wind and solar PV.
Almost as important is the increase of USD 28 per MWh of VRE to almost USD 50 per MWh of
VRE, both at a share of 50% of wind and solar PV, as a function of the availability of flexibility
in the system in the form of interconnections with neighbouring countries and flexiblehydroelectric resources. While such estimates come with some degree of uncertainty, theorder of magnitude provides clear indications for policy choices.
Figure ES7. Total cost of electricity provision including all system costs(USD billion per year)

Total costs of electricity provision(USD billion/year)

Plant-level costs

Profile costs

Connection costs

Grid costs

70
60
50
40
30
20
10
0
Main
scenario
Base case

10

Balancing costs

10% VRE

30% VRE

No IC

50% VRENo IC,
no flexible
hydro
75% VRE

Low-cost
VRE

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EXECUTIVE SUMMARY

These values need to be compared to the plant-level generation costs of VRE, whichrange, depending on the scenario, from USD 60 per MWh for onshore wind to up to USD 130
per MWh for solar PV. It should also be noted that the system costs are largely unaffected byany declines in plant-level costs as long as the share of VRE remains exogenously imposed.
Indeed, all four components of system costs (balancing, profile, connection and grid costs)
increase with the deployment of VRE resources, but at different rates. By adding systemcosts to the costs of plant-level generation as assessed in LCOE calculations, one cancalculate the total system costs of electricity provision for the eight scenarios analysed inthis study (see Figure ES7 above).
With 10% of VRE in the electricity mix, total costs increase only about 5% above the costs ofa reference system with only conventional dispatchable generators, which in a mid-sized
system such as the one modelled corresponds to additional costs of about USD 2 billion per
year. At 30% VRE penetration, costs increase by about USD 8 billion per year, i.e. by 21% withrespect to the base case. Reaching more ambitious VRE targets leads to considerably higher
costs. Total costs increase by more than USD 15 billion per year if 50% of electric energy
generation is provided by variable renewable resources, which corresponds to an additional
42% of costs compared to the base case. Reaching a 75% VRE target finally implies almost
doubling the costs for electricity provision to almost USD 70 billion per year, representing morethan USD 33 billion above the base case.
A striking effect of the deployment of low marginal cost variable resources on the electricity
market is the appearance of hours with zero prices, a substantial increase in the volatility ofelectricity prices and the commensurate increase in capital cost (not modelled here). Such zero
prices are not observed in the two scenarios with no or low VRE deployment but start appearing
for 60 hours per year when VRE reach a penetration level of 30%. The number of occurrences
increases dramatically with the VRE penetration level; at 50%, more than 1 200 hours in a year
feature zero-price levels, i.e. about 14% of the time. When VREs produce 75% of the demand,zero prices occur during 3 750 hours, i.e. more than 43% of the time (see Figure ES8). Since themodel works under a financing constraint, the higher frequency of hours with zero prices iscompensated by an increase in the number of hours with high electricity prices, which
increases volatility. At 75% VRE penetration, the number of hours with prices above USD 100
per MWh is more than double that at zero or low VRE penetration rate.

Figure ES8. Price duration curves of wholesale electricity prices in the five main scenarios

Hourly wholesale electricity price (USD/MWh)

Base case

10% VRE

30% VRE

50% VRE

75% VRE

200
175
150
125
100
75
50
25
0
0

1 000

2 000

3 000

4 000

5 000

6 000

7 000

8 000

Utilisation time (hours)

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EXECUTIVE SUMMARY

Last but not least, the generation by VRE as a function of the availability of natural
resources such as wind speed or solar radiation, is not only more variable than that fromdispatchable plants but also more concentrated during a limited number of hours. Periods withhigh generation are followed by periods with lower or zero output. Because they all respond to
the same meteorological conditions, wind turbines and solar PV plants tend to auto-correlate,i.e. produce disproportionally more electricity when other plants of the same type are
generating and to produce less when other wind and solar PV plants are also running at lower
utilisation rates. In combination with the zero short-run marginal costs of VRE resources, thiscauses a decrease in the average price received by the electricity generated by VRE as theirpenetration level increases, a phenomenon often referred to as self-cannibalisation. Figure 48
summarises this effect by showing the average market price received by wind and solar PV
generators in the wholesale electricity markets as a function of their share in the electricity mix.

Figure ES9. The market remuneration received by wind and solar PV
as a function of their share in the electricity mix

Value of electricity generated (USD/MWh)Wind - main region

Solar PV - main region

80

60

40
No interconnections
No interconnections, no flexible hydro

20

0
0%

10%

20%

30%

40%

50%

VRE penetration level (%)

The average price received by solar PV and wind resources in the electricity market
declines significantly and non-linearly as their penetration level increases, and this pricedecrease is much steeper for solar PV than for wind as its auto-correlation is higher. The valueof the solar PV generation is almost halved even when a penetration rate of only 12.5% isreached. Further deployment of solar PV capacity to a penetration level of 17.5% would further
halve its market value to below USD 20 per MWh. Thus, even if the generation costs of solar
PV were divided by five, its optimal penetration level would not exceed 17.5%. A similar trend,
although less pronounced, is observed for onshore wind, which has a higher load factor thansolar PV and whose generation spans over a larger time period. At a penetration level of 22.5%,
the value of a megawatt-hour of wind is reduced by 25%. For penetration levels above 30%, themarket value of wind electricity is below USD 50 per MWh compared to an average price of allelectricity of USD 80 per MWh. Offshore wind with its even higher load factor might show lesspronounced declines but was not included in the study as its overall LCOEs were significantly
higher than those of competing low-carbon technologies including nuclear.
Last but not least, achieving more ambitious renewable targets also implies that VRE mustbe curtailed more frequently. Curtailment of VRE generation thus appears at 30% penetrationlevel and increases sharply with their share. At 50% generation share, the curtailment rate of
the marginal VRE unit deployed is above 10%. In the scenario featuring a 75% share of VRE
generation, about 18% of the total VRE generation must be curtailed, and the curtailment rateof the last unit deployed is above 36%. Curtailment can be understood as an indicator that thesystem value of VRE is lower than its system costs, i.e. that reducing VRE output during certain
hours constitutes the least-cost flexibility option.

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EXECUTIVE SUMMARY

Effective policy options to decarbonise the electricity sector
Decarbonising the energy system to achieve the climate goals set by the Paris Agreement
represents an enormous challenge for OECD countries. To reduce the carbon intensity of theelectric power sector to 50 gCO2 per kWh, an eighth of the current levels, requires a rapid andradical transformation of the power system with the deployment of low-carbon emitting
technologies such as nuclear, hydroelectricity and variable renewables (VRE). In the absence of
mechanisms to capture and store the CO2, this will mean phasing out coal and strictly limiting
the use of gas-fired power generation. Given the massive investments that the realisation ofthis transformation requires, it is of paramount importance to create long-term frameworks
that provide stability and confidence for investors in all power generation technologies. This
has important implications beyond the electricity sector. Decarbonising the energy sectors andthe economies of OECD countries will require an important effort of electrification (see also
the IEA World Energy Outlook 2018). This concerns, quite obviously, the transportation sector,
but also industry and housing. Effective action to reduce carbon emissions and to limit climatechange depends on the creation of a robust low-carbon electricity sector.
If OECD policy makers want to achieve such a deeply decarbonised electricity mix theymust foster vigorous investment in low-carbon technologies such as nuclear energy, VRE andhydroelectric power. Where hydroelectric power is constrained by natural resource
endowments, nuclear and VRE remain the principal options. This is why the modelling in
Chapter 3 took a brownfield approach to hydroelectricity, i.e. fixed the amount of available
resources ex ante, independent of market conditions or VRE deployment. This is a usefulstarting assumption at the level of generality of this study. It should, however, be mentionedthat the generating capacity of existing installations might also be increased under the righteconomic conditions. The generating capacity of hydroelectric resources might thus beincreased, for instance, through the repowering of dams that are currently only used for
irrigation (see Tester et al., 2012: p. 623). While the technical potential exists, there are, at thecurrent costs of alternatives, questions about the economic potential (ibid.: 637). The
economic costs of leveraging such additional existing hydroelectric resources are highly sitedependent and inversely related to the size of the plant. In particular, small-scale hydroprojects would thus need to be approached in a full cost-perspective that takes all local,
regional and global costs and benefits into account.
Whatever their share of hydroelectric resources, all electricity systems of OECD
countries relying on deregulated wholesale markets to ensure adequate investments are
currently experiencing great stress in advancing towards the twin objectives of rapid
decarbonisation and adequate investment in low-carbon technologies. The reasons are, inparticular, the relative disadvantages experienced by technologies with high fixed costs in aderegulated market with volatile prices, the lack of robust and reliable carbon prices, andthe out-of-market financing of large amounts of variable renewables with little thought on
the impacts on the remainder of the electricity system. These shortcomings have madeprogressive re-regulation a distinct option for the future evolution of the electricity sector ofOECD countries.
The risk is that such a return to regulated systems would do more harm than good bylosing the efficiency gains brought by liberalisation without a clear roadmap for the roadahead. The alternative is to move towards specific market designs for low-carbon generation
based on five distinct pillars: 1) the continuing working of short-term markets for efficientdispatch and the revelation of the true system value of the electricity produced; 2) carbon
pricing; 3) frameworks for the adequate provision of capacity, flexibility and infrastructures fortransmission and distribution; 4) appropriate mechanisms to foster long-term investment in
low-carbon technologies, including the reform of existing support mechanisms; and 5) theinternalisation of system costs wherever practical and necessary. While details of electricity
market reform will require substantive expert discussion, it is important that policy makers
understand the importance of these five pillars, which are required to maintain theappropriate equilibrium between short-term competitive pressures and long-term investment
incentives for low-carbon generation.

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EXECUTIVE SUMMARYFirst, maintain current short-term electricity markets for efficient dispatch. The
deregulation of electricity markets did not get everything wrong. Even if there is widespread
agreement that deregulated electricity markets have not provided on their own sufficientincentives for investment in low-carbon technologies, there is also recognition that they havebeen good at using existing assets efficiently. Marginal cost pricing based on short-term
variable costs is not ideal to incentivise the construction of technologies with high capital costs.
It is, however, the appropriate mechanism to ensure the optimal utilisation of existing
resources, i.e. to produce a MWh of electricity at the lowest possible costs at any given moment
and to expose generators to the discipline of market prices. Recognising this dichotomy implies
combining markets for short-term dispatch with explicit mechanisms to foster investment in
low-carbon technologies.
Second, whatever the institutional hurdles and lobbying efforts to prevent it, the mostimportant immediate measure is the introduction of carbon pricing, which would raiseelectricity prices, reduce greenhouse gases and enhance the competitiveness of low-carbon
technologies such as nuclear and VRE. A meaningful level for a carbon price in an emission
trading system would mean a price high enough to ensure the following outcomes:a)make gas competitive against coal and, where pertinent, lignite in the markets of all
OECD countries;b)

improve the competitiveness of nuclear power plants against gas-fired plants whereconstruction costs are sufficiently low without any out-of-market support;c)

improve renewable competitiveness against gas-fired generation where meteorologicalconditions are sufficiently favourable without any out-of-market support;d)provide the dynamic incentive to invest in the development of new even more costeffective low-carbon technologies.

The precise level of carbon prices to achieve such outcomes would vary on the relative
costs of different technologies in different countries. As an order of magnitude, a carbon priceof USD 50 per tonne of CO2 can be considered sufficient to fulfil the criteria mentioned above.
The leverage of fossil fuel-based generators and their stakeholders over political decision
making has made effective carbon pricing the exception rather than the rule in OECD
countries. Where introduced, however, in countries such as Sweden or the United Kingdom, it
has been highly effective in driving decarbonisation. Independent of detailed efficiency
considerations, a credible carbon price is a powerful signal in order to shape the expectationsof producers, consumers and other stakeholders such as suppliers concerning the long-term
evolution of the electricity system. Carbon pricing will produce an overall gain for society.
However, it will also produce losses for some stakeholders, in particular, fossil fuel producers
and their customers. Appropriate compensation will thus need to be part of any politicallysustainable package.
Third, develop long-term frameworks for the adequate provision of capacity, flexibility andinfrastructures for transmission and distribution: generation is at the heart of any electricity
system, but it is ultimately only a part of it. Any electricity system requires frameworks for theprovision of capacity, flexibility, system services and adequate physical infrastructures. While
this was always the case, the variability of VREs and new technological developments makethese complementary services increasingly important. The importance of flexibility provision is
also underlined in the latest edition of the IEA’s World Energy Outlook 2018. Technological andbehavioural changes such as the digitalisation of network management, batteries and demandside management (DSM), as well as, in some cases, decentralising generation and consumption
makes for an ever more complex equation to be solved. Short-term markets for flexibility
provision, balancing, increased interconnections with neighbouring countries and capacity
remuneration mechanisms are all part of this. It is also important to recognise the positive
contribution to system stability and inertia of large centralised units such as nuclear power
plants or hydroelectric dams and to value them appropriately.
Fourth, create appropriate mechanisms for fostering long-term investment in low-carbon
technologies. In creating sustainable low-carbon electricity systems, all low-carbon
technologies will need to play a part. However, their high capital intensity requires specificfinancing solutions as they will not be deployed solely on the basis of marginal cost pricing in

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EXECUTIVE SUMMARY

competitive markets. This holds for all low-carbon technologies, but particularly for VREs,
which themselves suffer most heavily from the lower prices they induce. Due to different
lifetimes, risk profiles and financing structures, individual technologies will also continue torequire dedicated, individually designed instruments, even though they all are based on thesame principle that investment in high fixed cost technologies requires high levels of priceand revenue stability.
On their own, neither carbon pricing nor capacity remuneration for dispatchable lowcarbon providers will suffice, although they constitute, in principle, the appropriate
instruments for internalising the external effects relating to the public goods of climate
protection and security of supply. Capacity remuneration mechanisms (CRMs) designed toprovide electricity during the rare hours of extreme peak demand will favour technologies withlow fixed capacity costs, usually OCGTs, since they are the only ones willing to invest when
expected operating hours are in the double digits. This is why policy makers have to maketough calls on striking the appropriate balance between out-of-market support and exposure towholesale market prices for low-carbon technologies with high fixed costs such as nuclear and
VRE. One the one hand, feed-in tariffs (FITs), long-term power purchase agreements (PPAs),
contracts for difference (CFDs), regulated electricity tariffs, feed-in premiums (FIPs) or evendirect capital subsidies through, for instance, loan guarantees, are all appropriate instruments
to achieve long-term security of supply with low-carbon technologies. FIPs or direct capitalsubsidies even maintain a link with wholesale market prices, which is important for efficientdispatch and value discovery. Even employing FITs and other instruments that share thecentral characteristic of a long-term contract guaranteeing a price corresponding to average
cost need not mean abandoning competition altogether. Competitive auctions can substitutecompetition in the market with competition for the market.
Fifth, internalise system costs, where the previous four pillars have not already done so.
Carbon pricing will recognise the environmental attributes of low-carbon generation, while
capacity remuneration will recognise dispatchability. In principle, exposure to electricity
prices would internalise profile costs, and remunerate each unit of electricity generated at itstrue value for the system. This theoretically sound principle, however, finds its limitation in
the need for long-term price guarantees for low-carbon technologies mentioned above. The
important thing is not to add implicit subsidisation to explicit subsidisation.
Together, these five pillars form the basic structure of a design for low-carbon electricity
markets allowing for the optimised co-existence between VRE, hydroelectricity and nuclear
energy within an effective integrated electricity system that will yield deeply decarbonised
electricity systems at least cost and high levels of security of supply, independent of individual
cost assumptions or country-specific endowments. Even more importantly, these five pillars
allow for the construction of market designs that will be sustainable in the sense that they
enable the investments that are necessary for the large-scale deployment of low-carbon
technologies required for the rapid and radical transformation of the power system.
It should be emphasised that this framework does not depend on country preference fornuclear, hydro or VRE. All low-carbon technologies have a role to play. Based on the cost
assumptions used in the main scenarios, this study shows that a mix relying primarily on
nuclear energy is the most cost-effective option to achieve the decarbonisation target of
50 gCO2 per kWh. In addition, costs rise over-proportionally with the share of VRE forced upon
the system. However, these results reflect current best estimates. In particular, a further
decline in the costs of VRE generation technologies would lead to integrated systems withsizeable shares of both nuclear and VRE. This is the spirit of Scenario VI, “Cost minimisation
with low-cost renewables”. With overnight costs for wind and solar PV that are between one
third and two thirds lower than in the base case scenarios, it supports the vision of a future
electricity mix that is realistic for a broad range of OECD countries. Such a mix integrating
both VRE and dispatchable technologies would be composed of four main pillars:i. a share of 30-40% wind and solar PV;
ii. a larger share of 40%-60% provided by dispatchable low-carbon technologies such as
nuclear or, perhaps one day, fossil-fuelled plants with carbon capture, utilisation andstorage (CCUS);EXTRACT FROM THE COSTS OF DECARBONISATION: SYSTEM COSTS WITH HIGH SHARES OF NUCLEAR AND RENEWABLES, NEA No. 7335, © OECD 201915

EXECUTIVE SUMMARY

iii. the maximum possible amount of low-carbon flexibility resources, including hydro,
demand response and grid interconnection;
iv. a progressively decreasing share of highly flexible unabated fossil-fuelled technologies
ensuring the availability of residual flexibility.
Between now and 2050, the implicit time horizon of this study, research and development
efforts are also likely to reduce the overall cost of power generation. Technologies are likely to
be both cheaper and more flexible. Further cost reductions for low-carbon technologies suchas nuclear, possibly in the form of small modular reactors (SMRs), VREs and batteries are likely.
Largely for intrinsic physical reasons CCUS, for instance, is less likely to be a competitive
option, even by 2050, but a decisive breakthrough cannot be excluded. The electricity sector isalso likely to be more closely intertwined with other economic sectors due to cogeneration,
power-to-gas and the convergence with information and communication technologies.
This study does not claim that the options modelled, their technical performances andtheir costs will be those eventually realised in 2050 and does not make any predictions about
future technology developments. Its objective is to inform policy makers and the wider public
about the intrinsic difficulties of achieving ambitious carbon emission reduction objectives
with variable generation technologies alone. In practice, the choice of electricity market design
generation mix and, in particular, the generation mix is a matter of political choices at thenational level. While there is a global effort under way to reduce greenhouse gas emissions
and prevent dangerous climate change, specific outcomes will be the result of a broader mix ofsocial and political criteria. Local and regional pollution, system costs, technical reliability andthe long-term security of supply will all play into the decision-making process.
A particular role in this process will be played by nuclear power. While it reliably provides
large amounts of dispatchable, low-carbon power, it faces questions of social acceptability in a
number of OECD countries. Nevertheless, this study shows how nuclear power still remains
the economically optimal choice to satisfy stringent carbon constraints despite the economic
challenges for nuclear during the changeover between different reactor generations. The
reason for nuclear power’s cost advantage is not in its plant-level costs. Instead, it resides in
its overall costs to the electricity system. Variable renewables have reduced quite impressively
their plant-level costs, but their overall costs to the system are not accounted for as their
output is clustered during a limited number of high-level hours. All of these factors will cometo play in the ultimate choices of each country.
Independent of their individual choices regarding the structure of their electricity mixes,
OECD countries should move together to implement the five pillars for the design of lowcarbon electricity systems. Technologies and consumer behaviour will continue to change
rapidly in coming years. There is, however, a high likelihood that the orientations provided by
the five pillars developed above – competitive markets for short-term dispatch, carbon pricing,
centralised mechanisms for infrastructure provision, long-term stability for investors in lowcarbon capacity and the internalisation of system costs – will remain the appropriate
reference for the design of low-carbon electricity systems in the decades to come.

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The Costs of Decarbonisation:
System Costs with High Shares of Nuclear and Renewables
Under the Paris Agreement, OECD countries agreed to aim for a reduction of their greenhouse gas emissions
sufficient to hold the increase in the global average temperature to well below 2°C above pre industrial
levels. This commitment requires a massive effort to decarbonise energy and electricity generation, a radical
restructuring of the electric power sector and the rapid deployment of large amounts of low-carbon generation
technologies, in particular nuclear energy and renewable energies such as wind and solar PV.
This study assesses the costs of alternative low-carbon electricity systems capable of achieving strict carbon
emission reductions consistent with the aims of the Paris Agreement. It analyses several deep decarbonisation
scenarios to reach the same stringent carbon emission target but characterised by different shares of variable
renewable technologies, hydroelectric power and nuclear energy.

Nuclear Energy Agency (NEA)
46, quai Alphonse Le Gallo
92100 Boulogne-Billancourt, France
Tel.: +33 (0)1 45 24 10 15
nea@oecd-nea.org www.oecd-nea.org

NEA No. 7335