Comments on
ÒSimulations of scenarios
with 100% renewable electricity in the Australian National Electricity
Market. Solar 12011, 49th
AuSES Annual Conference, 30 Nov – 2 Dec., By Ben Elliston,
Mark Diesendorf and Iain MacGill,
UNSW...Published in Energy Policy, 2012.
Ted Trainer
(29.4.13 revision.)
The paper outlines a
supply pattern whereby it is claimed that 100% of present Australian electricity
demand could be provided by renewable energy.
The following notes
indicate why I think that although technically this could be done, we could not
afford the capital cost. This is mainly
because the analysis seems to significantly underestimate the amount of plant
that would be required.
I think this is a valuable
contribution to the discussion of the potential and limits of renewable
energy. It takes the kind of
approach needed, focusing on the combination of renewable sources that might
meet daily demand. However it is
not difficult to set out a scenario whereby this might be done technically; the
problems are what quantity of redundant plant would be needed to deal with
fluctuations in renewable energy sources, and what might the capital cost of
this amount to?
Required capacity?
Two of the plots given sett out the
contributions that might be combined to meet daily demand over about 8 days in
2010, in summer and winter. It
seems to me that when these contributions are added the total capacity needed
is much more than the paper states.
The task is to supply an average 31
GW. The plots given show that at
one point in time wind is contributing a maximum of 13.5 GW, but at other times
its contribution is close to zero, meaning that other sources are backing up
for it. The corresponding peak
inputs from the other sources are, PV 9 GW, solar thermal 27, hydro 5 GW and
gas from biomass 24 GW. Thus the
total amount of plant required would be 75.5 GW of peak capacity... to supply an
average 31 GW. (In his response to
Peter Lang, Mark Diesendorf says their total
requirement is 84.9 GW.) ThatÕs the magnitude of the redundancy problem and
this is the major limiting factor for renewables; the need for a lot of back up
plant, which will sit idle much of the time --- and impose high capital costs.
It is stated in the paper that 15.6
GW of solar thermal capacity would be needed, but this seems to be an important
confusion. Fig. 2 seems to show
that at times the solar thermal component will be delivering perhaps 27
GW. A solar thermal sector that
delivered 27 GW on the less than ideal day illustrated would probably have to
contain enough plant that to deliver well over 50 GW in full sun...not 15.6 GW....and
there would be much worse days than the one represented in Fig. 2.
So if we take the NREL (2011) SAM
example central receiver costing $6,580/kW(p), the solar thermal sector required for Fig.2 might cost 50+GW x $6,580/kW =
$329+ billion. If we accept Hearps and McConnellÕs expectation that Australian solar
thermal capital costs will fall by one-third (which others more or less assume,
e.g., AETA 2012, but it is highly doubtful given the probability of rapidly
rising energy and resource costs in future), and assume 30 year plant lifetime,
the capital cost p.a. would be $7.4 billion, which is almost as much as the
present total annual investment sum for the whole of the Australian
energy sector. (Birol, 2003 and Pfuger,
2004, put this at around .7% of GDP, i.e., 0.007 x $1300 billion = $9 billion .).
Note that this would only pay for
about one-fifth of the plant this proposal assumes (i.e., the solar thermal
sector) for the provision of the one fifth of primary energy demand that is electricity. These are back-of-envelope figures but
they indicate the kind of accounting needed before this proposal could be said
to be viable.
It is stated but not explained that
to use more than 6 hour solar thermal storage is not viable. The paper explicitly does not deal with
costs but to go from 6 hour storage to 17 hour storage, which Beyond Zero
Emissions (Wright and Hearps, 2010) assumes, would be
very expensive. The figures given
by Lovegrove et al (2012, p. 23) relating storage
capacity to capital cost, and their statement that construction in remote areas
multiplies cost by 1.3 – 1.4, indicate that plant with 17 your storage in
most of Australia would cost twice as much as the amount commonly given in terms
of dollar capital cost per peak kW.
(The NREL SAM Package figures assume only 6 hour storage.)
The problematic PV component.
Elliston, Diesendorf
and MacGill assume panels on rooftops in Brisbane,
Sydney Canberra and Adelaide. This
avoids transmission losses from solar farms. However winter global radiation in these
four mostly poor latitudes averages around a mere 2 kWh/m2/d
in some months, and the peak daily radiation is well under 400 W/m2. (This is for panels tilted at latitude
angle.) Not all panels on domestic
houses will be aligned perfectly, or maintained as well as in commercial farms,
or washed regularly etc.. This suggests that the winter output
from panels in this proposal might peak at around 35 W/m2. If this is so then to produce 14.6 GW
would require 417 million square metres of panels. A 135 W panel is about 0.9 m2
so 1 m2 would have a 150 W peak output. If we assume $3.5/W fully installed (under
the AETA 2012 global estimate) then
the cost per square metre would be 150 x $3.5 i.e., $525, and the cost for the 417
million square metres of panels would be $219 billion, not much different to
the solar thermal sector capital cost.
However as Palmer (2013) stresses,
what matters most is not the dollar cost of PV but the energy return on
investment. For PV EROI has been
commonly assumed to be around 10% of lifetime output, but only recently has
attention been given to attempting to estimate the all-inclusive value. Two major categories of energy cost and
loss have to be taken into account.
The first is to do with the ÒupstreamÓ factors, such as the relevant
fraction of the energy it took to construct the aluminium plant that made the
material for the module frames.
Studies which have attempted to do this have arrived at a figure of
around 33% for PV. (Crawford, R., 2011, Crawford, R, Treloar,
G. J., and Fuller, R., J., 2006., Lenzen, M., 1999, and Lenzen,
M., C. Dey, C. Hardy and M. Bilek,
2006.)
The
ÒdownstreamÓ factors include costs and losses after the plant has been
installed and which accumulate over its lifetime, such as losses in inverters and
invertor failure and replacement, accidents that damage equipment (e.g., rats
or possums that cause shorts), badly aligned panels, shading of panels, dust
and bird droppings on panels, corrosion at terminals and connections and
deterioration of panel efficiency due to age. In utility scale systems power
dumping must be accounted as a major energy loss affecting EROI. PalmerÕs Figure 3 shows that about
10% of German PV output in a summer period was exported. This was possible because neighbouring
countries did not have as much PV as Germany; if they did the Germans would
have to dump in summer.
Australia cannot export.
There is not yet agreement about
definitions and boundaries in the discussion of EROI (e.g., do you include the
energy cost of workers travelling to the nodule factory?) Palmer and others use the term Òextended
EROIÓ to refer to the net energy used when all these upstream and downstream
factors are taken into account. For
PV systems he arrives at a remarkable 2.1 – 2.3 for the extended EROI of
PV systems. Hall and Pietro (2012) arrive at a similar figure for installed PV
in Spain. This means payback time might be taking 15 of the 30 year lifetime of
the system. (p. 1434.) However it must be remembered that ER values depend
significantly on a particular set of conditions especially the location and its
typical level of solar radiation, and the size of system assumed (e.g., small
penetration might require no backup provision or dumping loss.)
A significant problem set by the
large scale introduction of PV into supply systems is the need to idle fossil-fuel
power stations in back-up mode, reducing their efficiency and increasing their
emissions per kW/h generated. PV does not align well with demand. In summer air conditioning use makes
electricity demand peak late in the afternoon. Palmer reports a study in NSW finding PV
input to be zero at this time.
These factors all subtract from the numerator in the total PV system
EROI ratio.
It would seem therefore that without
massive storage PV is not going to be capable of providing more than about 15%
of that maybe 18% of energy consumption (Palmer, 2013, p. 1429) that is
electricity, i.e., less than 3% of all energy demand, unless there is large
scale increase in use of electricity.
(Denholm and Margolis, 2007,say it is more or
less agreed that PV cannot contribute more than 10-20% of electricity
consumed.). Palmer concludes that
PV is not likely to be a major contributor. ÒÉ PV is not suited to taking on a
primary network role or delivering sufficient surpluses of energy when a fuller
account of embodied energy is included.Ó ( 2013, p.
1407.)
Transmission losses and costs.
It is not clear what loss of energy
in transmission has been assumed in the paper, if any. All solar thermal plants are a very long
way from Sydney-Melbourne, several being located on the North Western coast. When long distance HVDC plus local
distribution are taken into account the loss is likely to be well in excess of
15% of the energy generated. The
cost of the lines would add significantly to the overall capital cost. Hearps and McConnell (2011) indicate that Australian
capital costs for ST plant are some 35% higher than those overseas. The AEMO (2011) estimate of a HVDC line
from South Australia is three times the international average stated by Harvey (2011.) The cost reported in the press for the
Queensland proposed Copperstring 1000 km HVDC
transmission line is 5 times the average figure in the reviews of overseas
projects.
The distance from the solar thermal
plants to the south eastern cities would seem to average about 1500km. The reviews, (e.g., Harvey, 2011)
indicate the cost of HVDC transmission at $.5 per kw-km. This suggests that the transmission
infrastructure to cope with the peak 24 (27?) GW task would add $40.5 billion
to the total system cost.
The winter problem.
The paperÕs conclusions
on the crucial winter problem are based on an 8 day plot for June 29 to July 6th
2010 (Fig. 2.) This is the kind of evidence
we want, but it is far from the extent required. The key questions re the limits of
renewables are not to do with averages in demand or supply; they are to
do with the coincidence of maximum demand and minimum supply. What matters is how often there would be
a period of several days in which there was little or no sun or wind across the
whole collection region. To cope
with one such day the biomass plant required in this analysis would have to be more
or less that capable of meeting total demand, i.e., about 25% greater than is
assumed in the paper. (Hydro canÕt be increased as it is already doing all it
can in these plots.)
What we need in all
regions are analyses of several years of climate data to establish how
often wind and sun availability are how low. (That is, we need combined Òloss of load probabilityÓ figures based
on wind plus solar energy availability.)
Even if periods of negligible wind and sun are quite infrequent, we
would need sufficient plant to maintain supply through them. In other words is quite misleading to
base conclusions about required plant and capital costs on an 8 day climate
record for a period that is far from the extremes that occur, as this proposal
seems to do. For
instance the graphs presented in the paper show that all of the 8 days had at
least considerable solar radiation...what happens when thereÕs little for a
week?
This is the Òbig gapsÓ problem. There is extensive documentation of
large and protracted gaps in wind availability in Europe. For instance Oswald
et al. (2008) document several days in February 2006 when solar and wind
sources contributed almost no energy across the European continent from Ireland
to Germany, and one of these days was the coldest for the year in the UK,
probably meaning that annual demand peaked. (Many references to similar studies are
given in Trainer 1012b.)
In an accompanying slide
set (http://www.ceem.unsw.edu.au/content/userDocs/presentation.pdf) Ben Elliston provides
some significant evidence on this issue, and it is not clear why this does not
seem to have been integrated into the paper. As he says the slides document ÒSome
very long low irradiance events.Ó
Some of these exceed 5 days of negligible radiation. A 6 day event is noted for Roma in
2000. A simulated solar thermal
plant output for Cobar indicates no output for almost 4 consecutive days. It is said that in the south of the
continent these events are most frequent in winter, which is the time of
highest demand. Another slide states
that it would not be economic to attempt solar thermal storage to cope with
these periods. This information
seems to clearly
contradict the paperÕs essential claim, that demand can be met at
all times.
I recently carried out an analysis of Bureau
of Meteorology data providing DNI over eight years (Trainer 2013a). I took four
sites in central Australia and one in Whyalla (where a ST plant is being built)
and one at Mildura (which BZE proposes for a site). I found that that in the last three
months of 2010 there were 12 periods of 3 to 8 (non-overlapping) days in which
the combined radiation at these sites would have been very low or
negligible. The average radiation
was 2.3 kWh/m2 over the 48 days. Dish-Stirling systems would have produced
almost no electricity in these 48 days.
Central receivers would have done better, but output would have been
negligible. This was an unusually
bad period, but the point is that such periods occur.
I also found that on the many days
when DNI kWh/m2 was middling, hourly average DNI was low, and at a level that
would greatly reduce solar thermal generating efficiency. This seems to mean that solar thermal
systems cannot be expected to deliver much in regions where, or times of the
year when, DNI levels are not ideal.
I detail the negative implications for the BZE proposal.
The biomass-gas-electricity sector.
There are significant
uncertainties concerning the biomass-gas-electricity component of the proposal. The Grattan Report (Wood et al., 2012)
on renewable notes the difficulties in biomass-electricity, for instance the
need for large generating plants for efficiency, but these involve long
distance trucking of biomass. Lenzen (2009) notes that gas clean up sets a Òmajor
technical difficultyÓ.
Gas turbines can be quite
efficient but when the efficiency of the gas production system (potentially 67%
at best, according to Van der Meiden, Veringa and Rabou, 2010, and Mardon, 2012),
and the energy costs/losses in producing the biomass, trucking it, drying, and
returning ash to the fields are taken into account the overall energy
efficiency of biomass-gas-electricity component is likely to be around 20% or
less.
The proposal assumes a
very substantial use of biomass, and the implications of this need to be
spelled out. Fig. 2 suggests that in
winter daily biomass-electricity input would be about 25 GW by 15 hours. Thus the annual biomass electricity
production might average half this.
If the biomass-gas-electricity system is 25% energy efficient, then this
would require about 1,250 PJ/y of biomass, or perhaps 70 million tonnes of dry
biomass p.a. This would cut into
the biomass available to provide the other c. 75-80% of total energy needed,
including at present about 1,300 PJ of energy for transport (Érequiring around
4,250 PJ of biomass if the energy is in the form of ethanol, or an annual harvest of maybe 230 million tonnesÉwhich would probably
need 30 million ha of plantations.)
As Peter Lang points out, the
suggested capital cost of $800/kw for the biomass-gas-electricity sector is
highly implausible. That might be
the cost of a small qas turbine generator but the
capital cost estimate given by AETA, (2012) and AEMO 2(012) is over $5,000
kW. This does not include the cost
of growing, fertilizing, harvesting, drying, and trucking the biomass to the
generator and the ash back to the fields, or the dollar and energy costs of
trucks, machinery, sheds etc. Above all it will not have included the cost of
the gas producing plant. The
biomass to be transported in this case seems to be more than twice the weight
of the national annual wheat harvest.
The efficiency of the biomass-gas-electricity generation
part of the whole cycle is low,
maybe 28%. Putting all these
factors together would probably produce a very low overall system EROI.
Previously Diesendorf
(2007) argued that about one-third of electricity could be produced from
agricultural wastes, assuming 1 t/ha is left in the field. This would mean that when the harvested
mass is taken into account around 75 – 90% of biomass growth would be
removed, which is ecologically problematic. If the overall efficiency of the biomass-gas-electricity
system is 0.25 the 24 Mt/y mass would produce about 100 PJ of electricity,
which is only around one-eighth of present Australian consumption.
Large scale use of biomass seems to
be increasingly questioned. Just to
note a few issues, the coming holocaust of biodiversity loss is primarily due
to the taking of far too much of nature by humans meaning that we should be
returning vast areas to nature not taking more, over the long term use of
biomass for energy maintains half its carbon content in the atmosphere whereas
all of it could have been left locked up, overlooked has been the greenhouse
effect of nitrogen release from biomass-energy production and this could actually
out weight the gain achieved by replacing fossil fuel use (Crutzen,
et al., 2008), in an era when artificial and energy-intensive fertilizers will
become more scarce it will be imperative to return crop ÒwastesÓ to the soil,
and in any case some such as Pimentel and Patzek
argue that no biomass should be removed in view of the declining carbon content
of soils. (Note that crop harvest
as distinct from crop ÒwasteÓ represents a significant constant loss of
nutrients.)
The total system cost?
In Trainer 2013b I derive capital
costs for delivering 1kWh, in winter, at long distance,
net of embodied energy costs, and taking future capital cost estimates (50% less than now). When these figures are applied to the
amount of plant Elliston, Diesendorf, and MacGill believe would be sufficient (which I have
challenged above), the total is around $630 billion, or around $21 billion p.a.
assuming 30 year plant life. (See appendix for notes on derivation.) The figure does not include the cost of
the hydroelectric sector, or of the long distance transmission lines for solar
power. Nor does it include a
realistic figure for the total biomass-gas-electricity sector (making up one-third
of the capacity required), it takes the EDM assumption of $0.8//W. Nevertheless the sum is over three times
the early 2000s world ratio of capital investment in energy of all kinds
to GDP (Birol, 2003, Pfuger,
2004.) Note again that this
proposal is only for electricity provision, which makes up only about 20% of
energy consumption.
These are very rough and uncertain
figures but they indicate the magnitude of the challenge which this proposal
seems to face, and why my general view is that dealing with intermittency makes
the capital costs of 100% renewable energy supply are unaffordable..
Some final notes.
If ABAREÕs projections of population
(a 48% population increase by 2030) and their anticipated energy growth rate
are taken the total 2050 energy demand would be around twice the present
amount. At the same time the cost
of materials and energy to build renewable plant is going to rise sharply from
here on. (See Clugston,
2012.) These considerations will tend to make my above cost conclusions much too
low.
Note that in the early years of
construction the above capital cost figures would not apply, since they assume
33% reduction on present costs estimated to be achievable by 2050.
Note again that the paper is only
concerned with the provision of the present amount of electricity used, and
that makes up only 20%+ of total Australian final energy use, and this sets the
question, from what renewable sources the remaining 80% are to come from. The analysis in this paper assumes use
of considerable biomass, which would be most needed to meet the demand for
transport fuel. If it is assumed
that this can be reduced by shifting most transport to electricity, then the
plant required and the capital costs would be greater than those assumed in
this proposal.
Trainer 2012a sets out an easily followed
derivation of a world renewable energy budget, assuming a target of twice
present supply and future output and cost estimates common in the literature
(e.g., Hearps and McConnell, 2010. The target might
now be regarded as too high; the analysis is transparent and enables an
alternative derivation based on a reduced target.) It is concluded that the ratio of
investment to GDP would have to be much more than 16 times the present figure
(again not including several important factors.) In other words it would be quite
unaffordable. Note that that
target, 1000 EJ/y primary energy, would only give the expected 2050 world
population one-third of the present Australian per capita use. (Three
strategies were explored; dealing with the gaps via hydrogen storage, electrifying
as much as possible and relying mostly on wind, electrifying as much as
possible and relying on solar thermal for storage.)
(In 2010 I published an early
attempt to apply this approach to budget estimation, which arrived at a higher
estimate of capital cost, but I now see that as being too high. At that stage, before the
availability of the NREL SAM package (2010, 2011) providing estimates of solar
thermal output and cost it seemed that Big Dishes with ammonia storage would be
the best solar thermal strategy. It
now seems clear that central receivers are preferable, and there is much better
evidence re probable future costs.)
It therefore seems to me that the
paper falls far short of establishing its basic claim. Trainer (2012b) applies my approach to
the Australian situation, again making all assumptions and derivations
transparent, but again not including several important factors. Australia is more favourably endowed with
renewable resources than most if not all other countries, especially re
potential biomass. However the
conclusion I arrive at is that the ratio of energy investment to GDP would have
to be much more than 9 times the early 2000s rich world average, and thus would
be unaffordable. Note that this is
assuming use of 35 million ha for biomass production, almost twice the cropland
area, which is far more than Farine et al. (2011) are
willing to assume for biomass-energy production.
Just to add my usual note that this
is not an argument against transition to 100% renewable energy. It is an argument that this is not
possible in energy-intensive consumer-capitalist society. My main mission is to get people to
grasp that such a society is totally unsustainable, and irredeemable for
reasons to do with global justice, and that solutions to global problems can
only be achieved by transition to The Simpler Way (Éwhich is detailed in
Trainer, 2010, and 20
I would welcome critical feedback on
my world and Australian analyses.
(F.Trainer@unsw.edu.au)
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Appendix: Notes on the derivation of
the capital cost estimate:
These are not the commonly quoted figures which are for plant to generate 1 kW in peak
conditions. They are for the amount
of plant needed to deliver 1 kW in view of typical capacity factors, at long
distance, in winter radiation/wind, net of embodied energy
costs. Thus they are much higher
than $/W(p) figures. Capacity and unit cost
assumptions are given in the text above.
Wind:
13.5 GW x 4.61/W =
$62.4 billion.
PV:
9 GW x $12.81/W =
$115.3 billion.
Solar
thermal: 27 GW x $16/W = $432
billion.
Biomass:
24 GW x $0.8/W = $19
billion
Total:
$629 billion.
Annual figure, assuming
30 year plant lifetime $21 billion.