“Simulations 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.
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?
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.) That’s 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 McConnell’s 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 “upstream” 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 “downstream” 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. Palmer’s 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 “extended EROI” 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. “… 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.” ( 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 paper’s 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 can’t 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 “loss of load probability” 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 there’s little for a week?
This is the “big gaps” 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 “Some very long low irradiance events.” 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 paper’s 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 “major technical difficulty”.
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 (…requiring around 4,250 PJ of biomass if the energy is in the form of ethanol, or an annual harvest of maybe 230 million tonnes…which 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 “wastes” 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 “waste” 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 ABARE’s 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 (…which 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.