# Response to ‘Burden of proof: A comprehensive review of the feasibility of
100% renewable-electricity systems’

T. W. Brown<EMAIL_ADDRESS>T. Bischof-Niemz  K. Blok  C. Breyer  H. Lund
B.V. Mathiesen  Institute for Automation and Applied Informatics, Karlsruhe
Institute of Technology, 76344 Eggenstein-Leopoldshafen, Germany  Frankfurt
Institute for Advanced Studies, Ruth-Moufang-Straße 1, 60438 Frankfurt am
Main, Germany  Energy Centre, Council for Scientific and Industrial Research,
Meiring Naude Road, Pretoria, South Africa  Delft University of Technology,
Chair of Energy Systems Analysis, Faculty Technology, Policy and Management,
Jaffalaan 5, 2628 BX Delft, The Netherlands  Lappeenranta University of
Technology, School of Energy Systems, Skinnarilankatu 34, 53850 Lappeenranta,
Finland  Department of Development and Planning, Aalborg University,
Rendsburggade 14, 9000 Aalborg, Denmark  Department of Development and
Planning, Aalborg University, A.C. Meyers Vænge 15, 2450 Copenhagen SV,
Denmark

###### Abstract

A recent article ‘Burden of proof: A comprehensive review of the feasibility
of 100% renewable-electricity systems’ claims that many studies of 100%
renewable electricity systems do not demonstrate sufficient technical
feasibility, according to the criteria of the article’s authors (henceforth
‘the authors’). Here we analyse the authors’ methodology and find it
problematic. The feasibility criteria chosen by the authors are important, but
are also easily addressed at low economic cost, while not affecting the main
conclusions of the reviewed studies and certainly not affecting their
technical feasibility. A more thorough review reveals that all of the issues
have already been addressed in the engineering and modelling literature.
Nuclear power, which the authors have evaluated positively elsewhere, faces
other, genuine feasibility problems, such as the finiteness of uranium
resources and a reliance on unproven technologies in the medium- to long-term.
Energy systems based on renewables, on the other hand, are not only feasible,
but already economically viable and decreasing in cost every year.

###### keywords:

renewables , wind power , solar power , power transmission , ancillary
services , reliability

###### Contents

  1. 1 Introduction
  2. 2 Feasibility versus viability
  3. 3 Feasibility Criteria
    1. 3.1 Their Feasibility Criterion 1: Demand projections
    2. 3.2 Their Feasibility Criterion 2a: Simulation time resolution
    3. 3.3 Their Feasibility Criterion 2b: Extreme climatic events
    4. 3.4 Their Feasibility Criterion 3: Transmission and distribution grids
    5. 3.5 Their Feasibility Criterion 4: Ancillary services
    6. 3.6 Our Feasibility Criterion 5: Fuel source that lasts more than a few decades
    7. 3.7 Our Feasibility Criterion 6: Should not rely on unproven technologies
  4. 4 Other Issues
    1. 4.1 Feasibility of storage technologies
    2. 4.2 Feasibility of biomass
    3. 4.3 Feasibility of carbon capture
    4. 4.4 Viability of renewable energy systems
    5. 4.5 Viability of nuclear power
    6. 4.6 Other studies of 100% renewable systems
    7. 4.7 Places already at or close to 100% renewables
    8. 4.8 South Australian blackout in September 2016
  5. 5 Conclusions

##  1 Introduction

There is a broad scientific consensus that anthropogenic greenhouse gas
emissions should be rapidly reduced in the coming decades in order to avoid
catastrophic global warming [1]. To reach this goal, many scientific studies
([2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22,
23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36, 37, 38, 39, 40, 41,
42, 43, 44, 45, 46, 47, 48, 49, 50, 51, 52, 53, 54, 55, 56, 57, 58, 59, 60,
61] are discussed in this article) have examined the potential to replace
fossil fuel energy sources with renewable energy. Since wind and solar power
dominate the expandable potentials of renewable energy [3], a primary focus
for studies with high shares of renewables is the need to balance the
variability of these energy sources in time and space against the demand for
energy services.

The studies that examine scenarios with very high shares of renewable energy
have attracted a critical response from some quarters, particularly given that
high targets for renewable energy are now part of government policy in many
countries [62, 63]. Critics have challenged studies for purportedly not taking
sufficient account of: the variability of wind and solar [64, 65], the
scaleability of some storage technologies [66], all aspects of system costs
[64, 65], resource constraints [67, 68], social acceptance constraints [68],
energy consumption beyond the electricity sector [68], limits to the rate of
change of the energy intensity of the economy [68] and limits on capacity
deployment rates [69, 68]. Many of these criticisms have been rebutted either
directly [70, 71, 72] or are addressed elsewhere in the literature, as we
shall see in the following sections.

In the recent article ‘Burden of proof: A comprehensive review of the
feasibility of 100% renewable-electricity systems’ [73] the authors of the
article (henceforth ‘the authors’) analysed 24 published studies (including
[3, 4, 5, 6, 7, 8, 9, 12, 13, 10, 11]) of scenarios for highly renewable
electricity systems, some regional and some global in scope. Drawing on the
criticisms outlined above, the authors chose feasibility criteria to assess
the studies, according to which they concluded that many of the studies do not
rate well.

In this response article we argue that the authors’ chosen feasibility
criteria may in some cases be important, but that they are all easily
addressed both at a technical level and economically at low cost. We therefore
conclude that their feasibility criteria are not useful and do not affect the
conclusions of the reviewed studies. Furthermore, we introduce additional,
more relevant feasibility criteria, which renewable energy scenarios fulfil,
but according to which nuclear power, which the authors have evaluated
positively elsewhere [74, 75, 76], fails to demonstrate adequate feasibility.

In Section 2 we address the definition and relevance of feasibility versus
viability; in Section 3 we review the authors’ feasibility criteria and
introduce our own additional criteria; in Section 4 we address other issues
raised by [73]; finally in Section 5 conclusions are drawn.

##  2 Feasibility versus viability

Early in their methods section, the authors define _feasibility_ to mean that
something is technically possible in the world of physics ‘with current or
near-current technology’. They distinguish feasibility from socio-economic
_viability_ , which they define to mean whether it is possible within
environmental and social constraints and at a reasonable cost. While there is
no widely-accepted definition of feasibility [77], other studies typically
include economic feasibility in their definition [78, 79, 80, 81, 82], while
others also consider social and political constraints [83, 68]. For the
purposes of this response article, we will keep to the authors’ definitions of
feasibility and viability.

One reason that few studies focus on such a narrow technical definition of
feasibility is that, as we will show in the sections below, there are
solutions using today’s technology for all the feasibility issues raised by
the authors. The more interesting question, which is where most studies
rightly focus, is how to reach a high share of renewables in the most cost-
effective manner, while respecting environmental, social and political
constraints. In other words, viability is where the real debate should take
place. For this reason, in this paper we will assess both the feasibility and
the viability of renewables-based energy systems.

Furthermore, despite their declared focus on feasibility, the authors
frequently mistake viability for feasibility. Examples related to their
feasibility criteria are examined in more detail below, but even in the
discussion of specific model results there is confusion. The authors
frequently quote from cost-optimisation studies that ‘require’ certain
investments. For example they state that [84] ‘required 100 GWe of nuclear
generation and 461 GWe of gas’ and [85] ‘require long-distance interconnector
capacities that are 5.7 times larger than current capacities’. Optimisation
models find the most cost-effective (i.e. viable) solutions within technical
constraints (i.e. the feasible space). An optimisation result is not
necessarily the only feasible one; there may be many other solutions that
simply cost more. More analysis is needed to find out whether an investment
decision is ‘required’ for feasibility or simply the most cost-effective
solution of many. For example, the 100 GWe of nuclear in [84] is fixed even
before the optimisation, based on existing nuclear facilities, and is
therefore not the result of a feasibility study. However, the authors do
acknowledge that their transmission feasibility criteria ‘could arguably be
regarded as more a matter of viability than feasibility’.

Finally, when assessing economic viability, it is important to keep a sense of
perspective on costs. If Europe is taken as an example, Europe pays around
300-400 billion € for its electricity annually.111Own calculation based on
price and (incomplete) consumption data from Eurostat [86] for 2015. It
includes energy supply (around 50%), network costs (around 20%), taxes and
surcharges (around 30%); it excludes indirect costs, such as those caused by
environmental pollution [87] and climate change [88]. EU GDP in 2016 was 14.8
trillion € [86]. Expected electricity network expansion costs in Europe of 80
billion € until 2030 [89] may sound high, but once these costs are annualised
(e.g. to 8 billion €/a), it amounts to only 2% of total spending on
electricity, or 0.003 €/kWh.

##  3 Feasibility Criteria

The authors define feasibility criteria and rate 24 different studies of 100%
renewable scenarios against these criteria. According to the chosen criteria,
many of the studies do not rate highly.

In the sections below we address each feasibility criterion mentioned by the
authors, and some additional ones which we believe are more pertinent. In
addition, we discuss the socio-economic viability of the feasible solutions.

We observe that the authors’ choice of criteria, the weighting given to them
and some of the scoring against the criteria are somewhat arbitrary. As argued
below, there are other criteria that the authors did not use in their rating
that have a stronger impact on feasibility (such as resource constraints and
technological maturity); based on the literature review below, the authors’
criteria would receive a much lower weighting than these other, more important
criteria; and the scoring of some of the criteria, particularly for primary
energy, transmission and ancillary services, seems coarse and subjective.
Regarding the scoring, for demand projections the studies are compared with a
spectrum from the mainstream literature, but no uncertainty bound is given,
just a binary score; for transmission there is no nuance between studies that
use blanket costs for transmission, or only consider cross-border capacity, or
distribution as well as transmission networks; and no weighting is given to
the importance of the different ancillary services.

Finally, note that while some of the studies chosen by the authors consider
the electricity sector only, other studies include energy demand from other
sectors such as transport, heating and industry, thereby hindering
comparability between the studies.

###  3.1 Their Feasibility Criterion 1: Demand projections

The authors criticise some of the studies for not using plausible projections
for future electricity and total energy demand. In particular, they claim that
reducing global primary energy consumption demand is not consistent with
projected population growth and development goals in countries where energy
demand is currently low.

Nobody would disagree with the authors that any future energy scenario should
be compatible with the energy needs of every citizen of the planet. A
reduction in electricity demand, particularly if heating, transport and
industrial demand is electrified, is also unlikely to be credible. For
example, both the Greenpeace Energy [R]evolution [6, 90] and WWF [5]
scenarios, criticised in the paper, see a significant increase in global
electricity consumption; another recent study [35] of 100% renewable
electricity for the globe foresees a doubling of electricity demand between
2015 and 2050, in line with IEA estimates for electricity [91].

However, the authors chose to focus on primary energy, for which the situation
is more complicated, and it is certainly plausible to decouple primary energy
consumption growth from meeting the planet’s energy needs. Many countries have
already decoupled primary energy supply from economic growth; Denmark has 30
years of proven history in reducing the energy intensity of its economy [92].

There are at least three points here: i) primary energy consumption
automatically goes down when switching from fossil fuels to wind, solar and
hydroelectricity, because they have no conversion losses according to the
usual definition of primary energy; ii) living standards can be maintained
while increasing energy efficiency; iii) renewables-based systems avoid the
significant energy usage of mining, transporting and refining fossil fuels and
uranium.

Figure 1:  Primary energy consumption (grey and green) versus useful energy
services (blue) in today’s versus tomorrow’s energy system. (Reproduced with
permission from [93], page 86; based on [94])

Figure 1 illustrates how primary energy consumption can decrease by switching
to renewable energy sources, with no change in the energy services (blue)
delivered. Using the ‘physical energy accounting method’ used by the IEA,
OECD, Eurostat and others, or the ‘direct equivalent method’ used by the IPCC,
the primary energy consumption of fossil fuel power plants corresponds to the
heating value, while for wind, solar and hydro the electricity output is
counted. This automatically leads to a reduction in the primary energy
consumption of the electricity sector when switching to wind, solar and hydro,
because they have no conversion losses (by this definition).

In the heating sector, fossil-fuelled boilers dominate today’s heating
provision; here, primary energy again corresponds to the heating value of the
fuels. For heat pumps, the heat taken from the environment is sometimes
counted as primary energy [95, 96], sometimes not [5]; in the latter case the
reduction in primary energy consumption is 60-75% [97], depending on the
location and technology, if wind, solar and hydro power are used. Cogeneration
of heat and power will also reduce primary energy consumption. In addition,
district heating can be used to recycle low-temperature heat that would
otherwise be lost, such as surplus heat from industrial processes [98, 99,
100]. For biomass, solar thermal heating and resistive electric heating from
renewables there is no significant reduction in primary energy compared to
fossil-fuelled boilers.

In transport, the energy losses in an internal combustion engine mean that
switching to more efficient electric vehicles running on electricity from
wind, solar and hydro will reduce primary energy consumption by 70% or more
[46] for the same service.

If statistics from the European Union in 2015 [101] are taken as an example,
taking the steps outlined in Figure 1 would reduce total primary energy
consumption by 49%222This would involve switching from thermal power plants
(average efficiency 35% [101]) to wind and solar generators for all
electricity, using heat pumps (average coefficient of performance of 3) for
space and water heating, and using electricity instead of internal combustion
in road vehicles (reducing final energy consumption here by a factor of 3.5
[46]). No reduction in primary energy is assumed for remaining energy sectors
(non-electric industrial demand, aviation and shipping). without any change in
the delivered energy services. (Final energy consumption would also drop by
33%.) A reduction of total primary energy of 49% would allow a near doubling
of energy service provision before primary energy consumption started to
increase. This is even before efficiency measures and the consumption from
fuel processing are taken into account.

The primary energy accounting of different energy sources presented in this
example is already enough to explain the discrepancies between the scenarios
plotted in Figure 1 of [73], where the median of non-NGO global primary energy
consumption increases by around 50% between 2015 and 2050, while the NGOs
Greenpeace and WWF see light reductions. As an example of a non-NGO projection
with high primary energy demand, many IPCC scenarios with reduced greenhouse
gas emissions rely on bioenergy, nuclear and carbon capture from combustion
[102], whereas the NGOs Greenpeace [6] and WWF [5] have high shares of wind
and solar. The IPCC scenarios see less investment in wind and solar because of
conservative cost assumptions, with some assumptions for solar PV that are 2-4
times below current projections [103, 34]; with improved assumptions, some
authors calculate that PV could dominate global electricity by 2050 with a
share of 30–50% [104]. Another study of 100% renewable energy across all
energy sectors in Europe [22] sees a 10% drop in primary energy supply
compared to a business-as-usual scenario for 2050, with bigger reductions if
synthetic fuels for industry are excluded.

The authors chose to concentrate on primary energy consumption, but for
renewables, as argued above, it can be a misleading metric (see also the
discussion in [96]). The definitions of both primary and final energy are
suited for a world based on fossil fuels. What really matters is meeting
people’s energy needs (the blue boxes in Figure 1) while also reducing
greenhouse gas emissions.

Next we address energy efficiency that goes beyond just switching fuel source.
There is plenty of scope to maintain living standards while reducing energy
consumption: improved building insulation and design to reduce heating and
cooling demand, more efficient electronic devices, efficient processes in
industry, better urban design to lower transport demand, more public transport
and reductions in the highest-emission behaviour. These efficiency measures
are feasible, but it is not clear that they will all be socio-economically
viable.

For example, in a study for a 100% renewable German energy system (including
heating and transport) [30] scenarios were considered where space heating
demand is reduced by between 30% and 60% using different retrofitting
measures. Another study for cost-optimal 100% renewables in Germany [105]
shows similar reductions in primary energy in the heating sector from
efficiency measures and the uptake of cogeneration and heat pumps.

The third point concerns the upstream costs of conventional fuels. It was
recently estimated that 12.6% of all end-use energy worldwide is used to mine,
transport and refine fossil fuels and uranium [36]; renewable scenarios avoid
this fuel-related consumption.

One final, critical point: even if future demand is higher than expected, this
does not mean that 100% renewable scenarios are infeasible. As discussed in
Section 3.6, the global potential for renewable generation is several factors
higher than any demand forecasts. There is plenty of room for error if
forecasts prove to underestimate demand growth: an investigation into the
United States Energy Information Administration’s Annual Outlook [106] showed
systematic underestimation of total energy demand by an average of 2% per year
after controlling for other sources of projection errors; over 35 years this
would lead to an underestimate of around factor 2 (assuming other sources of
growth are not excessive); reasonable global potentials for renewable energy
could generate on average around 620 TW [3], which is a factor 30 higher than
business-as-usual forecasts for average global end-use energy demand of 21 TW
in 2050 [36].

###  3.2 Their Feasibility Criterion 2a: Simulation time resolution

The authors stress that it is important to model in a high time resolution so
that all the variability of demand and renewables is accounted for. They give
one point to models with hourly resolution and three points to models that
simulate down to 5 minute intervals.

It is of course important that models have enough time resolution to capture
variations in energy demand (e.g. lower electricity consumption at 3am than at
3pm) and variations in wind and solar generation, so that balancing needs,
networks and other flexibility options can be dimensioned correctly. However,
the time resolution depends on the area under consideration, since short-term
weather fluctuations are not correlated over large distances and therefore
balance out. This criterion should rather read ‘the time resolution should be
appropriate to the size of the area being studied, the weather conditions
found there and the research question’. Models for whole countries typically
use hourly simulations, and we will argue that this is sufficient for long-
term energy system planning.

After all, why do the authors stop at 5 minute intervals? For a single wind
turbine, a gust of wind could change the feed-in within seconds (the inertia
of the rotor stops faster changes). Similarly, a cloud could cover a small
solar panel in under a second. Individuals can change their electricity
consumption at the flick of a switch.

The reason modelling in this temporal detail is not needed is the statistical
smoothing when aggregating over a large area containing many generators and
consumers. Many of the studies are looking at the national or sub-national
level. By modelling hourly, the majority of the variation of the demand and
variable renewables like wind and solar over these areas is captured; if there
is enough flexibility to deal with the largest hourly variations, there is
enough to deal with any intra-hour imbalance. Figure 2 shows correlations in
variations (i.e. the differences between consecutive production values) in
wind generation at different time and spatial scales.333Note that for time
series of production values (i.e. not the differences) the correlation does
not decrease as rapidly as shown here and can remain high for hundreds of
kilometres [107]. Changes within 5 minutes are uncorrelated above 25 km and
therefore smooth out in the aggregation. Further analysis of sub-hourly wind
variations over large areas can be found in [108, 109].

Figure 2: Correlation of variations in wind for different time scales in
Germany. (Reproduced with permission and data from [110, 111])

For solar photovoltaics (PV) the picture is similar at shorter time scales:
changes at the 5-minute level due to cloud movements are not correlated over
large areas. However, at 30 minutes to 1 hour there are correlated changes due
to the position of the sun in the sky or the passage of large-scale weather
fronts. The decrease of PV output in the evening can be captured at one-hour
resolution and there are plenty of feasible technologies available for
matching that ramping profile: flexible open-cycle gas turbines can ramp up
within 5-10 minutes, hydroelectric plants can ramp within minutes or less,
while battery storage and demand management can act within milliseconds. For
ramping down, solar and wind units can curtail their output within seconds.

The engineering literature on sub-hourly modelling confirms these
considerations. Several studies consider the island of Ireland, which is
particularly challenging since it is an isolated synchronous area, is only 275
km wide and has a high penetration of wind. One power system study for Ireland
with high share of wind power [112] varied temporal resolution between 60
minute and 5 minute intervals, and found that the 5 minute simulation results
gave system costs just 1% higher than hourly simulation results; however, unit
commitment constraints and higher ramping and cycling rates could be
problematic for older thermal units (but not for the modern, flexible
equipment outlined above). Similarly, [113, 114] see not feasibility problems
at sub-hourly time resolutions, but a higher value for flexible generation and
storage, which can act to avoid cycling stress on older thermal plants. In
[115] the difference between hourly and 15-minute simulations in small
district heating networks with high levels of wind power penetration was
considered and it was found that ‘the differences in power generation are
small’ and ‘there is [no] need for higher resolution modeling’.

To summarise, since at large spatial scales the variations in aggregated load,
wind and solar time series are statistically smoothed out, none of the large-
scale model results change significantly when going from hourly resolution
down to 5-minute simulations. Hourly modelling will capture the biggest
variations and is therefore adequate to dimension flexibility requirements.
(Reserve power and the behaviour of the system in the seconds after faults are
discussed separately in Section 3.5.) Sub-hourly modelling may be necessary
for smaller areas with older, inflexible thermal power plants, but since
flexible peaking plant and storage are economically favoured in highly
renewable systems, sub-hourly modelling is less important in the long-term.

Simulations with intervals longer than one hour should be treated carefully,
depending on the research question [116].

###  3.3 Their Feasibility Criterion 2b: Extreme climatic events

The authors reserve a point for studies that include rare climatic events,
such as long periods of low sun and wind, or years when drought impacts the
production of hydroelectricity.

Periods of low sun and wind in the winter longer than a few days can be met,
where available, by hydroelectricity, dispatchable biomass, demand response,
imports, medium-term storage, synthetic gas from power-to-gas facilities (the
feasibility of each of these is discussed separately below) or, in the worst
case, by fossil fuels.

From a feasibility point of view, even in the worst possible case that enough
dispatchable capacity were maintained to cover the peak load, this does not
invalidate these scenarios. The authors write "ensuring stable supply and
reliability against all plausible outcomes…will raise costs and complexity".
Yet again, a feasibility criterion has become a viability criterion.

So what would it cost to maintain an open-cycle gas turbine (OCGT) fleet to
cover, for example, Germany’s peak demand of 80 GW? For the OCGT we take the
cost assumptions from [117]: overnight investment cost of 400 €/kW, fixed
operation and maintenance cost of 15 €/kW/a, lifetime of 30 years and discount
rate of 10%. The latter two figures given an annuity of 10.6% of the overnight
investment cost, so the annual cost per kW is 57.4 €/kW/a. For a peak load of
80 GW, assuming 90% availability of the OCGT, the total annual cost is
therefore 5.1 billion €/a. Germany consumes more than 500 TWh/a, so this
guaranteed capacity costs less than 0.01 €/kWh. This is just 7.3% of total
spending on electricity in Germany (69.4 billion € in 2015 [118]).

We are not suggesting that Germany builds an OCGT fleet to cover its peak
demand. This is a worst-case rhetorical thought experiment, assuming that no
biomass, hydroelectricity, demand response, imports or medium-term storage can
be activated, yet it is still low cost. Solutions that use storage that is
already in the system are likely to be even lower cost. However, some OCGT
capacity could also be attractive for other reasons: it is a flexible source
of upward reserve power and it can be used for other ancillary services such
as inertia provision, fault current, voltage regulation and black-starting the
system. A clutch can even be put on the shaft to decouple the generator from
the turbine and allow the generator to operate in synchronous compensator
mode, which means it can also provide many ancillary services without burning
gas (see the discussion on ancillary services in Section 3.5).

Running the OCGT for a two-week-long low-sun-and-wind period would add fuel
costs and possibly also net CO2 emissions (which would be zero if synthetic
methane is produced with renewable energy or low if the carbon dioxide
produced is captured and stored or used). Any emissions must be accounted for
in simulations, but given that extreme climatic events are by definition rare
(two weeks every decade is 0.4% of the time; the authors even speak of once-
in-100-year events), their impact will be small.

A recent study of seven different weather years (2006 to 2012), including
extreme weather events, in Europe for a scenario with a 95% CO2 reduction
compared to 1990 in electricity, heating and transport [119] came to similar
conclusions. The extreme events do not affect all countries simultaneously so,
for example, Germany can cover extreme events by importing power from other
countries. If for political reasons each country is required to cover its peak
load on a national basis, the extra costs for capacity are at most 3% of the
total system costs.

For systems that rely on hydroelectricity, the authors are right to point out
that studies should be careful to include drier years in their simulations.
Beyond the examples they cite, Brazil’s hydroelectric production has been
restricted over the last couple of years due to drought, and there are
periodic drier years in Ethiopia, Kenya and Scandinavia, where in the latter
inflow can drop to 30% below the average [108].

However, in most countries, the scenarios rely on wind and solar energy, and
here the dispatchable power capacity of the hydro is arguably just as
important in balancing wind and solar as the total yearly energy contribution,
particularly if pumping can be used to stock up the hydro reservoirs in times
of wind and solar abundance [7, 54].

Note that nuclear also suffers from planned and unplanned outages, which are
exacerbated during droughts and heatwaves, when the water supplies for river-
cooled plants are either absent or too warm to provide sufficient cooling
[120]. This problem is likely to intensify given rising demand for water
resources and climate change [120].

###  3.4 Their Feasibility Criterion 3: Transmission and distribution grids

The authors criticise many of the studies for not providing simulations of the
transmission (i.e. high voltage long-distance grid) and distribution (i.e.
lower voltage distribution from transmission substations to consumers) grids.
Again, this is important, but not as important as the authors assume.
Feasibility is not the issue (there are no technical restrictions on expanding
the grid), but there are socio-economic considerations. Many studies that do
not model the grid, do include blanket costs for grid expansion (e.g. from
surveys such as [121, 122, 123]).

On a cost basis, the grid is not decisive either: additional grid costs tend
to be a small fraction of total electricity system costs (examples to follow,
but typically around 10-15% of total system costs in Europe [124, 125, 126,
127, 21, 42, 123]), and optimal grid layouts tend to follow the cheapest
generation, so ignoring the grid is a reasonable first order approximation.
Where it can be a problem is if public acceptance problems prevent the
expansion of overhead transmission lines, in which case the power lines have
to be put underground (typically 3-8 times more expensive than overhead lines)
or electricity has to be generated more locally (which can drive up costs and
may require more storage to balance renewables). Public acceptance problems
affect cost, i.e. economic viability, not feasibility.

How much the distribution grid needs to be expanded also depends on how much
the scenario relies on decentralised, rooftop PV generation. If all wind and
utility-scale PV is connected to the transmission grid, then there is no need
to consider distribution grids at all. Regardless of supply-side changes,
distribution grids may have to be upgraded in the future as electricity demand
from heating and electric vehicles grows (although this is not obvious:
distribution grids are often over-dimensioned for the worst possible
simultaneous peak demand, and more intelligent network infrastructure, demand
management or storage could avoid distribution grid upgrades).

Now to some examples of transmission and distribution grid costing.

A study by Imperial College, NERA and DNV GL for the European electricity
system to 2030 [124] examined the consequences for both the transmission and
distribution grid of renewable energy penetration up to 68% (in their Scenario
1). For total annual system costs of 232 billion €/a in their Scenario 1, 4
billion €/a is assigned to the costs of additional transmission grid
investments and 18 billion €/a to the distribution grid. If there is a greater
reliance on decentralised generation (Scenario 1(a)-DG), additional
distribution grid costs could rise to 24 billion €/a.

This shows a typical rule of thumb: additional grid costs are around 10-15% of
total system costs. But this case considered only 68% renewables.

The distribution grid study of 100% renewables in the German federal state of
Rhineland-Palatinate (RLP) [125] also clearly demonstrates that the costs of
generation dwarf the grid costs. Additional grid investments vary between 10
and 15% of the total costs of new generation, depending on how smart the
system is. Again, distribution upgrade costs dominate transmission costs.

In its worst case the Germany Energy Agency (DENA) sees a total investment
need of 42.5 billion € in German distribution grids by 2030 for a renewables
share of 82% [128]. Annualised to 4.25 billion €/a, this is just 6.2% of total
spending on electricity in Germany (69.4 billion € in 2015 [118]).

Another study for Germany with 100% renewable electricity showed that grid
expansion at transmission and distribution level would cost around 4-6 billion
€/a (with a big uncertainty range reaching from 1 to 12 billion €/a) [123].

Many studies look at the transmission grid only. The 2016 Ten Year Network
Development Plan (TYNDP) [89] of the European Transmission System Operators
foresees 70-80 billion € investment needs in Europe for 60% renewables by
2030, which annualises to 2% of total electricity spending of 400 billion €/a
(the 0.001 to 0.002 €/kWh extra costs are compensated by a resulting reduction
in wholesale electricity prices of 0.0015 to 0.005 €/kWh [89]). The authors
criticise the Greenpeace Energy [R]evolution scenario [6, 90] for excluding
grid and reliability simulations, but in fact Greenpeace commissioned
transmission expansion studies for Europe using hourly simulations, one for
77% renewables by 2030 [126] (60 billion € investment by 2030, i.e. 1.5% of
spending) and one for 97% renewables by 2050 [127] (149-163 billion €
investment for 97% renewables by 2050, i.e. 4% of spending). Beyond Europe,
other studies with similar results look at the United States [84], South and
Central America [48], and Asia [39, 16].

The authors quote studies that look at optimal cross-border transmission
capacity in Europe at very high shares of renewables, which show an expansion
of 4-6 times today’s capacities [85, 129]. It is worth pointing out that these
studies look at the international interconnectors, not the full transmission
grid, which includes the transmission lines within each country. The
interconnectors are historically weak compared to national grids444The TYNDP
[89] will double cross-border capacities by 2030, but total circuit length
will only grow by around 25%. and restricted by poor market design and
operation [130]; if a similar methodology to [85, 129] is applied to a more
detailed grid model with nodal pricing, the expansion is only between 25% and
50% more than today’s capacity [42]. Furthermore, cost-optimal does not
necessarily mean socially viable; there are solutions with lower grid
expansion and hence higher public acceptance, but higher storage costs to
balance renewables locally [42].

###  3.5 Their Feasibility Criterion 4: Ancillary services

Finally, we come to ancillary services. Ancillary services are additional
services that network operators need to stabilise and secure the electricity
system. They are mostly provided by conventional dispatchable generators
today. Ancillary services include reserve power for balancing supply and
demand in the short term, rotating inertia to stabilise the frequency in the
very short term, synchronising torque to keep all generators rotating at the
same frequency, voltage support through reactive power provision, short
circuit current to trip protection devices during a fault, and the ability to
restart the system in the event of a total system blackout (known as ‘black-
starting’). The authors raise concerns that many studies do not consider the
provision of these ancillary services, particularly for voltage and frequency
control. Again, these concerns are overblown: ancillary services are
important, but they can be provided with established technologies (including
wind and solar plants), and the cost to provide them is second order compared
to the costs of energy generation.

We consider fault current, voltage support and inertia first. These services
are mostly provided today by synchronous generators, whereas most new wind,
solar PV and storage units are coupled to the grid with inverters, which have
no inherent inertia and low fault current, but can control voltage with both
active and reactive power.

From a feasibility point of view, synchronous compensators could be placed
throughout the network and the problem is solved, although this is not as cost
effective as other solutions. Synchronous compensators (SC), also called
synchronous condensers, are essentially synchronous generators without a prime
mover to provide active power. This means they can provide all the ancillary
services of conventional generators except those requiring active power, i.e.
they can provide fault current, inertia and voltage support just like a
synchronous generator. Active power is then provided by renewable generators
and storage devices.

In fact, existing generators can be retrofitted to be SC, as happened to the
nuclear power plant in Biblis, Germany [131], or to switch between generation
mode and SC mode; extra mass can be added with a clutch if more inertia is
needed (SC have an inertia time constant of 1-2 s [132, 133], compared to
typical conventional generators with around 6 s). SC are a tried-and-tested
technology and have been installed recently in Germany [134], Denmark, Norway,
Brazil, New Zealand and California [135]. They are also used in Tasmania
[136], where ‘Hydro Tasmania, TasNetworks and AEMO have implemented many
successful initiatives that help to manage and maintain the security of a
power system that has a high penetration of asynchronous energy sources…Some
solutions implemented in Tasmania have been relatively low cost and without
the need for significant capital investment’ [136]. In Denmark, newly-
installed synchronous compensators along with exchange capacity with its
neighbours allow the power system to operate without any large central power
stations at all [137]. In 2017 the system operated for 985 hours without
central power stations, the longest continuous period of which was a week
[138]. SC were also one of the options successfully shown to improve stability
during severe faults in a study of high renewable penetration in the United
States Western Interconnection [139, 140]. The study concluded ‘the Western
Interconnection can be made to work well in the first minute after a big
disturbance with both high wind and solar and substantial coal displacement,
using good, established planning and engineering practice and commercially
available technologies’. In a study for the British transmission system
operator National Grid [141] it was shown that 9 GVAr of SC would stabilise
the British grid during the worst fault even with 95% instantaneous
penetration of non-synchronous generation. (Britain is tricky because it is
not synchronous with the rest of Europe and can suffer small signal angular
instability between England and Scotland.)

So how cost-effective would synchronous compensators be? There is a range of
cost estimates in the literature [142, 143, 132, 144], the highest being an
investment cost of 100 €/kVAr with fixed operating and maintenance costs of
3.5 €/kVAr/a [144] (it would be around a third cheaper to retrofit existing
generators [132]). For Great Britain, the 9 GVAr of SC would cost 129 million
€ per year, assuming a lifetime of 30 years and a discount rate of 10%. That
annualises to just 0.0003 €/kWh. (SC also consume a small amount of active
power [145, 132], but given that they would run when marginal electricity
costs are very low thanks to high wind and solar feed-in, this cost would be
negligible.)

Synchronous condensers are an established, mature technology, which provide a
feasible upper bound on the costs of providing non-active-power-related
ancillary services. The inverters of wind, solar and batteries already provide
reactive power for voltage control and can provide the other ancillary
services, including virtual or synthetic inertia, by programming the
functionality into the inverter software [146]. Inverters are much more
flexible than mechanics-bound synchronous generators and can change their
output with high accuracy within milliseconds [147]. The reason that wind and
solar plants have only recently been providing these services is that before
(i.e. at lower renewable penetration) there was no need, and no system
operators required it. Now that more ancillary services are being written into
grid codes [148], manufacturers are providing such capabilities in their
equipment. Frequency control concepts for inverters that follow a stiff
external grid frequency and adjust their active power output to compensate for
any frequency deviations are already offered by manufacturers [149]. Next
generation ‘grid-forming’ inverters will also be able to work in weak grids
without a stiff frequency, albeit at the cost of increasing the inverter
current rating (e.g. by 20-50%). A survey of different frequency-response
technologies in the Irish context can be found in [150]. Recent work for
National Grid [151, 152] shows that with 25% of inverters operating as Virtual
Synchronous Machines (VSM), the system can survive the most severe faults even
when approaching 100% non-synchronous penetration. The literature in the
control theory community on the design and stability of grid-forming inverters
in power systems is substantial and growing, and includes both extensive
simulations and tests in the field [153, 154, 155, 156, 157, 158, 159].

Protection systems often rely on synchronous generators to supply fault
current to trip over-current relays. Inverters are not well-suited to
providing fault current, but this can be circumvented by replacing over-
current protection with differential protection and distance protection [160,
146], both of which are established technologies.

Next, we consider balancing reserves. Balancing power can be provided by
traditional providers, battery systems, fast-acting demand-side-management or
by wind and solar generators (upward reserves are provided by variable
renewable plants by operating them below their available power, called ‘delta’
control). There is a wide literature assessing requirements for balancing
power with high shares of renewables. In a study for Germany in 2030 with 65
GW PV and 81 GW wind (52% renewable energy share), no need is seen for
additional primary reserve, with at most a doubling of the need for other
types of reserves [161]. It is a similar story in the 100% renewable scenario
for Germany of Kombikraftwerk 2 [162]. (Maintaining reserves in Germany cost
315.9 million € in 2015 [163].) There is no feasibility problem here either.

Another ancillary service the authors mention is black-start capability. This
is the ability to restart the electricity system in the case of a total
blackout. Most thermal power stations consume electricity when starting up
(e.g. powering pumps, fans and other auxiliary equipment), so special
provisions are needed when black-starting the system, by making sure there are
generators which can start without an electricity supply. Typically system
operators use hydroelectric plants (which can generate as soon as the sluice
gate is opened), diesel generators or battery systems, which can then start a
gas turbine, which can then start other power plants (for example).
Maintaining conventional capacity for black-start is inexpensive compared to
system costs, as shown in Section 3.3; in a study for Germany in 2030 [161]
with 52% renewables, no additional measures for black-starting were deemed
necessary, contrary to the interpretation in [73]; finally, decentralised
renewable generators and storage could also participate in black-starting the
system in future [162]. The use of battery storage systems to black-start gas
turbines has recently been demonstrated in Germany [164] and in a commercial
project in California [165].

Nuclear, on the other hand, is a problem for black-starting, since most
designs need a power source at all times, regardless of blackout conditions,
to circulate coolant in the reactor and prevent meltdown conditions. This will
only exacerbate the need for backup generation in a total blackout. Nuclear is
sometimes not used to provide primary reserves either, particularly in older
designs, because fast changes in output present operational and safety
concerns.

###  3.6 Our Feasibility Criterion 5: Fuel source that lasts more than a few
decades

Here we suggest a feasibility criterion not included on the authors’ list: The
technology should have a fuel source that can both supply all the world’s
energy needs (not just electricity, but also transport, heating and industrial
demand) and also last more than a couple of decades.

Traditional nuclear plants that use thermal-neutron fission of uranium do not
satisfy this feasibility criterion. In 2015 there were 7.6 million tonnes of
identified uranium resources commercially recoverable at less than 260 US$/kgU
[166].555There are further speculative and unconventional uranium resources,
including in sea water, but the cost and energy required to extract them make
them unviable [167]. From one tonne of natural uranium, a light-water reactor
can generate around 40 GWh of electricity.

In 2015, world electricity consumption was around 24,000 TWh/a [168]. Assuming
no rise in electricity demand and ignoring non-electric energy consumption
such as transport and heating, uranium resources of 7.6 million tonnes will
last 13 years. Reprocessing, at higher cost, might extend this by a few more
years. Including non-electric energy consumption would more than halve this
time.

For renewables, exploitable energy potentials exceed yearly energy demand by
several orders of magnitude [169] and, by definition, are not depleted over
time. Even taking account of limitations of geography and material resources,
the potentials for the expansion of wind, solar and storage exceed demand
projections by several factors [3].

As for ‘following all paths’ and pursuing a mix of renewables and nuclear,
they do not mix well: because of their high capital costs, nuclear power
plants are most economically viable when operated at full power the whole
time, whereas the variability of renewables requires a flexible balancing
power fleet [170]. Network expansion can help the penetration of both
renewables and inflexible plant [171], but this would create further pressure
for grid expansion, which is already pushing against social limits in some
regions.

This feasibility criterion is not met by standard nuclear reactors, but could
be met in theory by breeder reactors and fusion power. This brings us to our
next feasibility criterion.

###  3.7 Our Feasibility Criterion 6: Should not rely on unproven technologies

Here is another feasibility criterion that is not included on the authors’
list: Scenarios should not rely on unproven technologies. We are not
suggesting that we should discontinue research into new technologies, rather
that when planning for the future, we should be cautious and assume that not
every new technology will reach technical and commercial maturity.

The technologies required for renewable scenarios are not just tried-and-
tested, but also proven at a large scale. Wind, solar, hydro and biomass all
have capacity in the hundreds of GWs worldwide [63]. The necessary expansion
of the grid and ancillary services can deploy existing technology (see
Sections 3.4 and 3.5). Heat pumps are used widely [172]. Battery storage,
contrary to the authors’ paper, is a proven technology already implemented in
billions of devices worldwide (including a utility-scale 100 MW plant in South
Australia [173] and 700 MW of utility-scale batteries in the United States at
the end of 2017 [174]). Compressed air energy storage, thermal storage, gas
storage, hydrogen electrolysis, methanation and fuel cells are all decades-old
technologies that are well understood. (See Section 4.1 for more on the
feasibility of storage technologies.)

On the nuclear side, for the coming decades when uranium for thermal-neutron
reactors would run out, we have breeder reactors, which can breed more fissile
material from natural uranium or thorium, or fusion power.

Breeder reactors are technically immature (with a technology readiness level
between 3 and 5 depending on the design [175]), more costly than light-water
reactors, unreliable, potentially unsafe and they pose serious proliferation
risks [176]. Most fast-neutron breeder reactors rely on sodium as a coolant,
and since sodium burns in air and water, it makes refueling and repair
difficult. This has led to serious accidents in fast breeder reactors, such as
the major sodium fire at the Monju plant in 1995. Some experts consider fast
breeders to have already failed as a technology option [176, 177]. The burden
of proof is on the nuclear industry to demonstrate that breeder reactors are a
safe and commercially competitive technology.

Fusion power is even further from demonstrating technical feasibility. No
fusion plant exists today that can generate more energy than it requires to
initiate and sustain fusion. Containment materials that can withstand the
neutron bombardment without generating long-lived nuclear waste are still
under development. Even advocates of fusion do not expect the first commercial
plant to go online before 2050 [178]. Even if it proves to be feasible and
cost-effective (which is not clear at this point), ramping up to a high
worldwide penetration will take decades more. That is too late to tackle
global warming [179].

##  4 Other Issues

In this section we address other issues raised by the authors of [73] during
their discussion of their feasibility criteria.

###  4.1 Feasibility of storage technologies

The authors write "widespread storage of energy using a range of technologies
(most of which - beyond pumped hydro - are unproven at large scales, either
technologically and/or economically)".

Regarding battery storage, it is clear that there is the potential to exploit
established lithium ion technology at scale and at low cost [180, 181, 182].
The technology is already widely established in electronic devices and
increasingly in battery electric vehicles, which will in future provide a
regular and cheap source of second-life stationary batteries. A utility-scale
100 MW plant was installed in the South Australian grid in 2017 [173] and
there was already 700 MW of utility-scale batteries in the United States at
the end of 2017 [174]. Further assessments of the potential for lithium ion
batteries can be found in [3]. Costs are falling so fast that hybrid PV-
battery systems are already or soon will be competitive with conventional
systems in areas with good solar resources [183, 184].

Many other electricity storage devices have been not just demonstrated but
already commercialised [185], including large-scale compressed air energy
storage. Technologies that convert electricity to gas, by electrolysing
hydrogen with the possibility of later methanation, are already being
demonstrated at megawatt scale [186, 187]. Hydrogen could either be fed into
the gas network to a certain fraction, used in fuel cell vehicles, converted
to other synthetic fuels, or converted back into electricity for the grid.
Fuel cells are already manufactured at gigawatt scale, with 480 MW installed
in 2016 [188]. By using the process heat from methanation to cover the heat
consumption of electrolysis, total efficiency for power-to-methane of 76% has
recently been demonstrated in a freight-container-sized pilot project, with
80% efficiency in sight [189].

Moreover, in a holistic, cross-sectoral energy systems approach that goes
beyond electricity to integrate all thermal, transport and industrial demand,
it is possible to identify renewable energy systems in which all storage is
based on low-cost well-proven technologies, such as thermal, gas and liquid
storage, all of which are cheaper than electricity storage [190]. These
sectors also provide significant deferrable demand, which further helps to
integrate variable renewable energy [191, 29, 46]. Storage capacity for
natural gas in the European Union is 1075 TWh as of mid 2017 [192].

###  4.2 Feasibility of biomass

The authors criticise a few studies for their over-reliance on biomass, such
as one for Denmark [10] and one for Ireland [11]. There are legitimate
concerns about the availability of fuel crops, environmental damage,
biodiversity loss and competition with food crops [193]. More recent studies,
including some by the same researchers, conduct detailed potential assessments
for biomass and/or restrict biomass usage to agricultural residues and waste
[194, 98, 195, 22]. Other studies are even more conservative (or concerned
about air pollution from combustion products [87]) and exclude biomass
altogether [41, 3, 7, 36, 46], while still reaching feasible and cost-
effective energy systems.

###  4.3 Feasibility of carbon capture

Capturing carbon dioxide from industrial processes, power plants or directly
from the air could also contribute to mitigating net greenhouse gas emissions.
The captured carbon dioxide can then be used in industry (e.g. in greenhouses
or in the production of synthetic fuels) or sequestered (e.g. underground).
While some of the individual components have been demonstrated at commercial
scale, hurdles [196, 197, 198] include cost, technical feasibility of long-
term sequestration without leakage, viability for some concepts (such as
direct air capture (DAC), the lowest cost version of which is rated at
Technology Readiness Level (TRL) 3-5 [199]), other air pollutants from
combustion and imperfect capture when capturing from power plants, lower
energy efficiency, regulatory issues, public acceptance of sequestration
facilities [200] and systems integration.

Studies at high time resolution that have combined renewables and power plants
with carbon capture and sequestration (CCS) suggest that CCS is not cost
effective because of high capital costs and low utilisation [201]. However,
DAC may be promising for the production of synthetic fuels [29, 202, 203] and
is attractive because of its locational flexibility and minimal water
consumption [204, 205]. Negative emissions technologies (NET), which include
DAC, bioenergy with CCS, enhanced weathering, ocean fertilisation,
afforestation and reforestation, may also be necessary to meet the goals of
the Paris climate accord [206, 207, 208, 209]. Relying on NET presents risks
given their technical immaturity, so further research and development of these
technologies is required [206, 210, 211, 212].

###  4.4 Viability of renewable energy systems

In the sections above we have shown that energy systems with very high shares
of renewable energy are both feasible and economically viable with respect to
primary energy demand projections, matching short-term variability, extreme
events, transmission and distribution grids, ancillary services, resource
availability and technological maturity. We now turn to more general points of
social and economic viability.

With regard to social viability, there are high levels of public support for
renewable energy. In a survey of European Union citizens for the European
Commission in 2017, 89% thought it was important for their national government
to set targets to increase renewable energy use by 2030 [213]. A 2017 survey
of the citizens of 13 countries from across the globe found that 82% believe
it is important to create a world fully powered by renewable energy [214]. A
2016 compilation of surveys from leading industrialised countries showed
support for renewables in most cases to be well over 80% [215]. Concerns have
been raised primarily regarding the public acceptance of onshore wind turbines
and overhead transmission lines. Repeated studies have shown that public
acceptance of onshore wind can be increased if local communities are engaged
early in the planning process, if their concerns are addressed and if they are
given a stake in the project outcome [216, 217, 218]. Where onshore wind is
not socially viable, there are system solutions with higher shares of offshore
wind and solar energy, but they may cost fractionally more [219]. The picture
is similar with overhead transmission lines: more participatory governance
early in the planning stages and local involvement if the project is built can
increase public acceptance [220, 221]. Again, if overhead transmission is not
viable, there are system solutions with more storage and underground cables,
but they are more expensive [42]. The use of open data and open model software
can help to improve transparency [222, 223, 224].

Next we turn to the economic viability of bulk energy generation from
renewable sources. On the basis of levelised cost, onshore wind, offshore
wind, solar PV, hydroelectricity and biomass are already either in the range
of current fossil fuel generation or lower cost [225]. Levelised cost is only
a coarse measure [226], since it does not take account of variability, which
is why integration studies typically consider total system costs in models
with high spatial and temporal resolution. Despite often using conservative
cost assumptions, integration studies repeatedly show that renewables-based
systems are possible with costs that are comparable or lower than conventional
fossil-fuel-based systems [2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16,
17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35,
36, 37, 38, 39, 40, 41, 42, 43, 44, 45, 46, 47, 48, 49, 50, 51, 52, 53, 54,
55, 56, 57, 58, 59, 60, 61], even before aspects such as climate impact and
health outcomes are considered.

For example, focusing on results of our own research, a global switch to 100%
renewable electricity by 2050 would see a drop in average system cost from 70
€/MWh in 2015 to 52 €/MWh in 2050 [35]. This study modelled the electricity
system at hourly resolution for an entire year for 145 regions of the world.
Considering all energy sectors in Europe, costs in a 100% renewable energy
scenario would be only 10% higher than a business-as-usual scenario for 2050
[22].

The low cost of renewables is borne out in recent auctions, where, for
example, extremely low prices have been seen for systems that include storage
in the United States due to come online in 2023 (a median PV-plus-battery
price of 36 US$/MWh and a median wind-plus-storage price of 21 US$/MWh [184]).

###  4.5 Viability of nuclear power

Following the authors, we have focussed above on the technical feasibility of
nuclear. For discussions of the socio-economic viability of nuclear power,
i.e. the cost, safety, decomissioning, waste disposal, public acceptance,
terrorism and nuclear-weapons-proliferation issues resulting from current
designs, see for example [227, 3, 167, 228].

###  4.6 Other studies of 100% renewable systems

At the time the authors submitted their article there were many other studies
of 100% or near-100% renewable systems that the authors did not review. Most
studies were simulated with an hourly resolution and many modelled the
transmission grid, with examples covering the globe [14, 15], North-East Asia
[16], the Association of South-East Asian Nations (ASEAN) [17], Europe and its
neighbours [18], Europe [19, 20, 21, 22, 23], South-East Europe [24], the
Americas [25], China [26], the United States [27], Finland [28], Denmark [29],
Germany [30], Ireland [31], Portugal [32] and Berlin-Brandenburg in Germany
[33].

Since then other 100% studies have considered the globe [34, 35, 36, 37], Asia
[38], Southeast Asia and the Pacific Rim [39], Europe [40, 41, 42, 43, 44, 45,
46], South-East Europe [47], South and Central America [48], North America
[49], India and its neighbours [50, 51], Australia [52, 53], Brazil [54], Iran
[55], Pakistan [56], Saudi Arabia [57], Turkey [58], Ukraine [59] the Canary
Islands [60] and the Åland Islands [61].

###  4.7 Places already at or close to 100% renewables

The authors state that the only developed nation with 100% renewable
electricity is Iceland. This statement ignores countries which come close to
100% and smaller island systems which are already at 100% (on islands the
integration of renewables is harder, because they cannot rely on their
neighbours for energy trading or frequency stability), which the authors of
[73] chose to exclude from their study.

Countries which are close to 100% renewable electricity include Paraguay
(99%), Norway (97%), Uruguay (95%), Costa Rica (93%), Brazil (76%) and Canada
(62%) [146]. Regions within countries which are at or above 100% include
Mecklenburg-Vorpommern in Germany, Schleswig-Hostein in Germany, South Island
in New Zealand, Orkney in Scotland and Samsø along with many other parts of
Denmark.

This list mostly contains examples where there is sufficient synchronous
generation to stabilise the grid, either from hydroelectricity, geothermal or
biomass, or an alternating current connection to a neighbour. There are also
purely inverter-based systems on islands in the South Pacific (Tokelau [229]
and an island in American Samoa) which have solar plus battery systems. We
could also include here any residential solar plus battery off-grid systems.

Another relevant example is the German offshore collector grids in the North
Sea, which only have inverter-based generators and consumption. Inverter-
interfaced wind turbines are connected with an alternating current grid to an
AC-DC converter station, which feeds the power onto land through a High
Voltage Direct Current cable. There is no synchronous machine in the offshore
grid to stabilise it, but they work just fine (after teething problems with
unwanted harmonics between the inverters).

Off-planet, there is also the International Space Station and other space
probes which rely on solar energy.

###  4.8 South Australian blackout in September 2016

The authors implicitly blame wind generation for the South Australian blackout
in September 2016, where some wind turbines disconnected after multiple faults
when tornadoes simultaneously damaged two transmission lines (an extreme
event). According to the final report by the Australian Energy Market Operator
(AEMO) on the incident [230] "Wind turbines successfully rode through grid
disturbances. It was the action of a control setting responding to multiple
disturbances that led to the Black System. Changes made to turbine control
settings shortly after the event [have] removed the risk of recurrence given
the same number of disturbances." AEMO still highlights the need for
additional frequency control services, which can be provided at low cost, as
outlined in Section 3.5.

##  5 Conclusions

In ‘Burden of proof: A comprehensive review of the feasibility of 100%
renewable-electricity systems’ [73] the authors called into question the
feasibility of highly renewable scenarios. To assess a selection of relevant
studies, they chose feasibility criteria that are important, but not critical
for either the feasibility or viability of the studies. We have shown here
that all the issues can be addressed at low economic cost. Worst-case,
conservative technology choices (such as dispatchable capacity for the peak
load, grid expansion and synchronous compensators for ancillary services) are
not only technically feasible, but also have costs which are a magnitude
smaller than the total system costs. More cost-effective solutions that use
variable renewable generators intelligently are also available. The viability
of these solutions justifies the focus of many studies on reducing the main
costs of bulk energy generation.

As a result, we conclude that the 100% renewable energy scenarios proposed in
the literature are not just feasible, but also viable. As we demonstrated in
Section 4.4, 100% renewable systems that meet the energy needs of all citizens
at all times are cost-competitive with fossil-fuel-based systems, even before
externalities such as global warming, water usage and environmental pollution
are taken into account.

The authors claim that a 100% renewable world will require a ‘re-invention’ of
the power system; we have shown here that this claim is exaggerated: only a
directed evolution of the current system is required to guarantee
affordability, reliability and sustainability.

## Acknowledgements

We thank Thomas Ackermann, Florian Dörfler, Ben Elliston, Veit Hagenmeyer,
Bri-Mathias Hodge, Jonas Hörsch, Nick Miller, Robbie Morrison, Antje Orths,
Mirko Schäfer, David Schlachtberger, Charlie Smith, Bo Tranberg and Helge
Urdal for helpful discussions, suggestions and comments. For their permission
to reproduce the figures we thank the German Federal Ministry for Economic
Affairs and Energy (Figure 1) and Bernhard Ernst (Figure 2). T.B. acknowledges
funding from the Helmholtz Association under grant no. VH-NG-1352 and from the
German Federal Ministry of Education and Research (BMBF) under grant no.
03SF0472C. T.B., H.L. and B.V.M. acknowledge funding from the RE-INVEST
project under grant number 6154-00022B from the Innovation Fund Denmark. The
responsibility for the contents lies with the authors.

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