Can Australia run on renewable energy? The negative case.
Ted Trainer is a Conjoint Lecturer in the Faculty of Arts at the University of New South Wales. Email F.Trainer@unsw.edu.au
The current discussion of climate change and energy problems is generally based on the assumption that technical solutions are possible and that the task is essentially to determine the most effective ways. This view relies heavily on the expectation that renewable energy sources can be substituted for fossil fuels. Australia is more favourably situated regarding renewable sources than almost any other country. This discussion attempts to estimate the investment cost that would be involved in deriving Australia’s total energy supply from renewable sources. It is concluded that the total investment cost is likely to be unaffordable, mainly due to the intermittency of renewable energy and the resulting implications for storage and plant redundancy.
It is commonly assumed that greenhouse and energy problems can be solved by intensified conservation and efficiency effort along with a transition from fossil fuels to renewable energy sources. In addition Stern (2006) and others assert that the cost will be easily afforded.
Trainer (2010a) explores the possibility of meeting a probable global 2050 energy demand of 1000 EJ/y within “safe” greenhouse gas emission limits. The approach is to estimate the amount of renewable capacity that would be required to meet demand in winter. The conclusion is that the average winter monthly quantity could not be provided at an affordable investment cost. The present study applies this approach to the Australian situation, using more confident data on possible systems and costs.
Australia probably has the most favourable global conditions for maximising reliance on renewable energy sources and there is a strong tendency for it to be taken for granted that Australia could run on renewables.
Little attention has been given to the critical assessment of the potential and the limits of renewable energy. (Trainer, 2007 attempted a critical overview, and an updated summary is given in Trainer 2011a.) The approach taken in this discussion follows that in Trainer, 2010a, by exploring a probable 2050 Australian energy supply target that might be met by a combination of energy conservation and renewable energy. After establishing working assumptions, two critical issues are discussed, firstly to do with whether the quantities of alternative energy capacity needed to meet average winter demand could be afforded, and secondly to do with the implications of solar and wind variability for plant quantities and total system capital costs.
The main purpose of this analysis is to indicate the value of the approach taken to the derivation of an energy budget, so that future studies can refine this when better data becomes available. The assumptions and derivations are transparent enabling the exercise to be reworked using other assumptions.
The probable 2050 energy target.
Australian Bureau of Agricultural Economics (ABARE, 2009) estimates that Australian primary energy demand in 2008 was 5.9 EJ/y, increasing at about 2.5% p.a. ABARE expects the rate of increase to fall to 1.9% p.a. by 2030. A rate of 2.1% p.a. will be assumed here for the 2009 – 2050 period, meaning a 33 year doubling time. Thus an Australian 2050 “business-as-usual” primary demand of 13 EJ/y will be tentatively assumed for working purposes.
Moriarty and Honery (2009) report that the ratio of final to primary energy is .69. The 2050 target will therefore be taken as delivering 8.97 EJ/y of final energy. It will be assumed that 2050 “business as usual” energy consumption in the electricity and transport sectors will be the same proportions of projected final energy as they are now in Australia, i.e., 21% (i.e., 1.884 EJ/y) and 33% (i.e., 2.96 EJ/y) respectively. (ABARE, 2007.)
Very large scale production of renewable energy, especially via solar thermal and PV farms located at the most favourable regions, will involve long distance transmission. European supply from solar thermal fields will probably have to come via several thousand kilometre long HVDC lines from North Africa and the Middle East. Losses in the vicinity of 15% are likely, along with another c. 7% for local distribution. (Mackay, 2008, Czisch, 2004, Breyer and Knies, 2009, NEEDS, 2009, Ummel and Wheeler, 2008, and Jacobson and Delucci, 2011, pp.1183-4.)
The best Australian supply regions for solar thermal electricity are in Central Australia and these will be crucial for winter supply. It will be assumed that losses from long distance plus local distribution will be 15%.
Embodied energy costs.
From the gross output figures for a renewable energy device the amount of energy needed to produce the device must be deducted. Few estimates take into account all “upstream” costs, e.g., the energy needed to produce the steel works that produced the steel used in solar thermal plant construction. These factors can greatly increase cost conclusions. (Lenzen 2009, Lenzen,1999, p. 359, Dey and Lenzen, 1999, Lenzen and Treloar, 2003, Lenzen and Munksgaard, 2002.) Lenzen, (2008) derives an all-inclusive embodied cost of 6.6% for wind, and 33% for PV. (See also Lenzen et al., 2006.) Hall and Pietro, 2011, state an even higher figure for PV located in Spain, and Crawford (200) finds that the all-inclusive PV figure can reach 50%. However the wind assumption made here is 4% and the PV assumption 15%.
The situation regarding solar thermal plant is more uncertain. The relatively few studies have indicated a 1 – 11% cost but assumptions have varied considerably. (Dey and Lenzen, 1999, p. 359, Weinriebe, Bonhke and Trieb, 2008, Norton, 1999, and Vant-Hull, 2006, Kaneff, 1991, Herendeen,1988, Lechon, de la Rua and Saezes, 2006, Lenzen, 2009, p. 117.) No study taking into account all upstream factors seems to have been carried out. (Lenzen, 2012 and Crawford, 2012.) The unsettled state of this field prohibits the confident assumption of a value for this discussion. A 10% cost will be assumed.
If 15% efficient PV panels in large power stations are assumed to be located in Central Australia where total global solar radiation in winter is 7 kWh/m2/day on average (ASRDHB, 2006), then the electricity produced would be 1.05 kWh/m2/day, corresponding to a continual 24 hour flow of 44 W/m2. After deducting transmission losses and the above embodied energy costs a net 32 W/m2 would be delivered at distance. .
Large scale supply of liquid fuel from biomass will have to come mostly from celulosic inputs produced by forest plantations. Probable crop and municipal waste inputs in Australia are only a small fraction of potential plantation quantities. (Wood et al., 2012, Ch. 8, p. 4.) Diesendorf (2007, p. 43,) reports an estimate of potential Australian crop waste bio-energy inputs at 8% of total biomass energy potential, on the assumption that it is acceptable to leave 1 t/ha in the fields.
The extent to which biomass could and should be used for energy production is controversial. The main cause of the serious biodiversity crisis occurring is the amount of natural habitat that humans have taken, indicating that large areas should be returned to nature rather than put into biomass-energy production.
When the harvested crop mass is added to the above rate of “waste” at least 80% of biomass growth would not be being returned to the soil. Pimentel and Pimentel (1997, p. 241) argue that for long term sustainability of soil carbon levels no material should be removed. This is also the reason why Patzek (2007, p. 21) challenges the viability of biomass energy production. He reports on marked long term carbon loss in rich world soils and argues that in the long term no net loss of biomass is possible without decline in NPP.
In the coming era of probably severely limited availability of petroleum and fertilizers it is likely that agriculture will have to focus more intensively on the organic factors contributing to yields, as distinct from external and artificial inputs, meaning that maximum retention of soil carbon and therefore maximum recycling of crop “wastes” is likely to become crucial.
Haberl et al., (2012) point out that over the long term using biomass for energy production means that half its carbon content is in the atmosphere, whereas all of it could have been left locked up in the unharvested biomass. Crutzen et al (2008) find that nitrogen release from biomass-energy production could actually out weight the gain re greenhouse gas effects achieved by replacing fossil fuel use.
Unfortunately estimates of land areas that could be devoted to biomass energy production vary greatly, are often questionable and do not enable confident conclusions. The highly unsettled state of the field is often noted (Farine et al., 2011, IPCC, 2011, Harvey, 2010, World Wildlife, 2010) and is evident in the range of estimates given. For example, Smeets and Faiij, (2007), arrive at 1,500 EJ/y whereas at the other extreme Field, Campbell and Lobel (2007) conclude that when social, economic, moral/justice and ecological considerations are taken into account the figure is only 27 EJ/y. An examination of such analyses reveals the large difference there can be between “theoretical potential” and plausible harvest in view of all combined limiting factors.
Although Australia is much more favourably situated regarding potential biomass energy resources than most countries, having around 5 times the world average amount of productive land per capita, the little evidence available does not seem to yield a clear or agreed figure for possible Australian celulosic yield. Stewart et al. (1979, 1982) estimated that 26 million ha might be available for biomass plantations. Foran (2008) discusses ethanol and methanol produced on 30 - 45 million ha with average yields of 6 – 7 t/ha, and Foran (2011) discusses harvesting 58 million ha., but the availability of such areas is not established in these papers. The former area indicates a yield of up to 300 million tonnes, while the latter indicates 380 million tonnes. Foran (2008, p. 57) notes that the fertile Illawarra region can average 7-9 t/ha/y yield but for the wheat and sheep zone (where large biomass production would have to mostly be located) the average is 4 - 5 t/ha/y. Diesendorf (2007) states a yield of 292 million tonnes (although he seems to rely on Foran’s data so this is probably not an independent estimate.). Moghtaderi, Sheng and Wall (2006) estimate a 160 million tonnes harvest. O’Connell et al. (2007) estimate 220 million tonnes p.a. Farine et al., (2011) are not willing to assume use of more than 5% of cleared land, and claim biomass could produce 55 TWh/y of electricity, loosely corresponding to a less than a 40 million tonne annual biomass harvest. These reports include little or no evidence or derivations in support of the areas or yields stated. Except for Farine et al. the areas are large, compared with Australia’s c. 22 million ha of cropland, approximately 50 million ha of cleared agricultural land (Foran, 2011), and 2002 total coal production including exports of around 300 million tonnes. (Foran and Crane, 2002, p. 107.)
A significant area of uncertainty concerns the ecological implications of large scale biomass production, such as the problems of erosion, water use, nutrient depletion and biodiversity loss. (Farine, et al., 2011.) If the use of fertilizers on such large scales is envisaged then the associated ecological effects of runoff would have to be factored in. Foran (2008) notes the large quantities of water that would be diverted from their natural flow paths if large scale biomass production were removed from a region. His methanol scenario would remove 17,000 Gl/y, equivalent to 85% of Australia’s present total “managed water use”. The IPCC (2011, p. 24) reports a study finding that biomass plantations reduce stream flow 50%.
Of most concern would be the biodiversity impact of converting large areas to simplified ecosystems if not monocultures which are cleared periodically. The global ecological problem is largely a consequence of the expropriation of nature for human purposes, and the impending “fifth holocaust” of species extinction indicates the urgent need to transfer large areas of land back to their natural forest and grassland conditions.
Thus confident area and yield assumptions are elusive. In view of the above estimates 35 million ha yielding 6.5 t/ha will be assumed. This would seem to be quite optimistic, being almost twice the area of all cropland and almost twice that of all high quality forest, and the biomass yield, 227 million tonnes p.a., (4.1 EJ/y of primary energy) is 2.3 times that arrived at by the recent detailed analysis by Farine, et al., (2011) and accepted by the Grattan Report, (Wood, et al., 2012, Ch. 8, p. 4.)
Fulton’s review (2005) concluded that the net yield of ethanol from cellulosic inputs is likely to be c. 7 GJ/t. Farine et al., (2011) report 6.5 GJ/t. Foran (2008) reports the belief among researchers that future yield could be in the region of 9 GJ/t. However the potential is debated. Patzek (2007) says only two plants are in operation in the world, performance is not made public, and energy analysis indicates that the process will not be viable. A significant problem concerns the contradiction between the need for large scale processing plants for energy and economic efficiency, and the need to minimise transport distances for low density biomass and therefore for many small plants closer to sources. As Wood et al., (2012) point out, future energy and dollar costs and efficiencies are uncertain.
For the purposes of the following derivation it will be assumed that biomass ethanol is be produced at a net rate of 7.5 GJ/t, and therefore 48.75 GJ/ha, from the equivalent of 35 million ha, meaning a gross liquid fuel yield of 1.71 EJ/y. The above embodied energy 10% cost will be assumed, meaning that 1.54 EJ/y will be available. (These energy costs of ethanol production and plant only refer to the plant producing ethanol; those associated with the production and supply of the biomass would need to be added.)
This source has provided approximately10% of Australia’s 0.7 EJ/y electricity supply, although in recent years drought has reduced this to 4.3%. (Booras, 2010.) ABARE (2007) estimates hydroelectricity production at 52 PJ/y. Given the relatively low embodied energy cost of hydroelectricity and its relative close location to demand, these factors will be disregarded and net delivered energy will be assumed to be .03 EJ/y, although this could be optimistic in views of the probable future effects of the greenhouse problem.
Lenzen’s review (2009, p. 19) concludes that wind is not likely to be able to contribute much more than 20+% of the electricity required within a system, because at higher penetrations integration problems rapidly increase. Wood et al. (2012, Ch. 2, p. 14) indicate a slightly higher figure. In this discussion 25% will be assumed.
Not taken into account here will be the fact that globally a large scale use of wind energy would have to assume much off-shore capacity, which is around 2.5 times the cost of on-shore capacity (IPCC, 2011, Annex 111, p. 9, Lenzen, 2009, p. 97.)
The world average wind capacity factor is in the region of .23. (Smil estimates .2: 2011.) Mainly because in winter winds are stronger the figure assumed here for the discussion of the winter supply task will be .38, meaning that a 1.5 MW turbine would generate 570 kW. Applying the above 4% embodied energy cost for wind reduces this to 547 kW. Wind farms are more easily located closer to demand than are large scale solar supply systems which would need to be in deserts to enable a reasonable winter contribution. The combined loss due to transmission and distribution will be assumed at 10%. Therefore a delivery rate per turbine of 492 kW in a winter month will be assumed.
Because solar thermal systems can store energy as heat and thereby overcome to a considerable extent (but not entirely; see below) the intermittency and storage problems which most renewables involve, they will be major contributors. However the (limited) technical and climate data accessible indicates that even in the best locations such as Central Australia winter output will be problematic. Troughs are not likely to be viable given their typically low winter to summer ratio of output, in the region of 0.25. (NREL, 2010, 2011.) Unfortunately commercial operators of central receivers do not make performance data public. Trainer (2011b) derives the conclusion mainly from the theoretical modelling in the NREL Solar Advisor Model (2010, 2011), that the best future option is likely to be central receivers (confirmed by Wood et al., 2012) and that the 24 hour flow rate of electricity delivered over long distance in winter, net of embodied energy costs and dry cooling energy costs is likely to be in the vicinity of 20 W/m2 of collection area.
It will be assumed that although other renewable energy sources might in future become significant contributors, at this stage that seems unlikely (Trainer 2007, 2011b.) The exception in Australia could be hot dry rock geo-thermal electricity, although Wood et al. (2012) elaborate on the considerable difficulties and uncertainties.
It will be assumed that around 60% of the 2.96 EJ/y business-as-usual 2050 transport energy demand assumed here could be shifted from fossil fuels to electricity by use of battery powered cars (if long distance car travel can be included.)
The energy efficiency of electric cars is commonly claimed to be in the region of 4 to 5 times as great as for petrol driven cars. However such figures typically apply to “battery to wheels” and do not include losses due to distribution, transforming from 240 V to 12 V, battery charging and discharging, discharge from idle batteries, the embodied energy costs of batteries and cars (claimed by Mateja, 2000, to be high), battery lifetime and replacement multiple per car life, and global supply of the relatively scarce element Lithium. Especially problematic is the embodied energy cost of Lithium-ion batteries, estimated by Smil (2010) to cost $35,000 and to last around three years. (Jacobson and Delucci, 2011, believe future battery cost will be half this sum, and that batteries will last the life of a car.) In view of these uncertainties it will be assumed that the present energy efficiency of cars can be trebled. (For a supporting analysis see Trainer, 2011a.) Bossell, (2004), argues that it can only be doubled.)
Consequently it will be assumed that the 60% of the “business as usual” 2.96 EJ/y transport energy budget, i.e., 1.78 EJ/y, will require .592 EJ/y. Another 40% of the 2.96 EJ/y, i.e., 1.184 EJ/y, will be required for transport in non-electrical form.
Low temperature heat.
In the absence of clear data it will be assumed that 10% of final energy demand, i.e., .897 EJ/y, will be in the form of low temperature heat supplied by passive solar etc. means, and therefore will not add to the need for electricity generation.
Discussions of the potential of renewable energy sources usually do not take into account the need to convert energy from forms that are available to forms that are needed, or that can be stored. This would not be so relevant if large scale direct storage of electricity was available. Conversion is typically quite energy-inefficient, meaning that much more primary energy needs to be generated than might appear to be the case. For instance according to Bossel (2004) fuelling transport by hydrogen produced from electricity would require generation of about 4 times the amount of energy that is delivered to wheels. (This aligns with the figures in Harvey, 2010, p. 458.)
It will be assumed that in those scenarios where conversion is necessary it will take place via the generation of hydrogen with an overall energy efficiency of .5, taking into account losses in electrolysis, compression, pumping and distribution. (Harvey also states this figure, 2010, p. 459.) Where hydrogen is used as an energy store for later regeneration of electricity via fuel cells, a further .4 - .5 efficiency reduction factor would apply. Where liquid hydrogen is required, for instance for aircraft fuel, the overall efficiency for wind turbines-to-engines would be in the region of 20%. If the embodied energy cost of all equipment on this path was deducted it is possible that there would be no net energy return, given the low energy density of hydrogen gas and therefore the need for large pressurised tanks, and for cooling of liquid hydrogen containers.
Energy conservation effort.
Significant reductions in energy supply are likely to be achieved by future improvements in energy use efficiency and conservation. Estimates vary considerably and an attempt to arrive at a confident figure for 2050 is beyond the scope of this discussion. For present purposes a working assumption of a 33% improvement in energy use efficiency will be made, for all but the 60% of transport energy assumed here to be converted to electricity.
Summarising the demand situation.
The foregoing assumptions and conclusions are summarised in Table 1. This enables others to assess the derivation of conclusions, and to consider the effects of differing assumptions.
Table 1. Annual Supply and Demand Assumptions.
Primary energy demand, 2050, assuming 2.1% p.a. growth
from 5.9 EJ/y in 2010 13 EJ/y
Final energy demand, 2050, assuming a 0.69
final/ primary ratio 8.97 EJ/y
Demand for low heat, temperature (e.g., space and water) .897 GJ/y
Demand for transport, 33% of total 2.960 E/y
Demand for electricity
Direct (21% of final) 1.884 EJ/y
Transport (assuming 60% of the 2.960 EJ/y transport
energy) 1.776 EJ/y
Remaining energy demand:
For transport 1.184
For other purposes 4.126
Demand after applying conservation assumptions:
Direct electricity, 1.884 EJ/y reduced by one-third to 1.256 EJ/y
Electricity, , i.e., 1.776 EJ/y, i.e., 60% of transport,
reduced by two-thirds to .592 EJ/y
Non-electrical transport energy, 1.184 EJ/y reduced
by one third to .789 EJ/y
Remaining demand, i.e., 4.413 EJ/y, reduced by one
third to 2.942 EJ/y
Therefore totals needed:
Electricity, 1.256 EJ/y + 0.592EJ/y 1.848 EJ/y
Non-electrical energy, 2.943 EJ/y
Totals needed after allocating hydroelectricity, (.03 EJ/y)
and biomass (1.54 EJ/y),
Electricity, 1.842 EJ/y - .03 EJ/y 1.818 EJ/y
Capital cost assumptions.
Evidence and claims regarding the likely long term future construction costs of solar and wind technologies vary considerably and estimates cannot be taken with confidence. Use will be made of studies reported by the IPCC, Annex 111, (2011), Harvey, (2010), and Hearps and McConnell, (2011), Wyld Group, (2008), and Wood et al., (2012). Hearps and McConnel report that future PV and solar thermal costs are estimated to fall by an average of 50% by 2030, but Australian costs are likely to fall by only 35%, presumably due to distance from suppliers and consultants.
Easily overlooked is the fact that cost estimates for plant are based on the present materials, construction and energy costs, and in future materials and energy inputs are likely to be considerably more expensive than they are now.
Because wind power technology might be regarded as relatively “mature’, estimates of future cost tend not to be markedly lower than present cost per kWe of capacity. The only accessed estimate of 2030 capital cost per kW(p) is $2,415, reported by Hearps and McConnell, (2011) for Australian onshore wind, from the Australian Energy Market Operator (AEMO. This represents a 20% fall from 2010. For the 1.5 MW turbines assumed below this corresponds to $3.62 million per turbine.
Hearps and McConnell (2011) report the AEMO estimate for 2030 Australian P/V at $3,581/kW. This figure will be assumed here although it is a 50% fall from the figure Lenzen’s review states for 2009, whereas Hearps and McConnell say that only a 35% reduction is expected for Australian conditions.
Because one square metre of 0.15 efficient PV panels will generate 150 W in peak solar radiation, 6.7 m2 would be needed to generate 1 kW. Over the average winter day this area of panels located in Central Australia would generate c. 6.7 m2 x 7 kWh/m2 x .15 = 7 kWh, corresponding to a 24 hour flow of 292 W. In other words, a capital cost of $3,581 will pay for sufficient PV panels to generate a gross flow of 292 W in winter, or 167 W net of the value of 15% transmission and 15% embodied energy costs. Therefore the net cost per watt delivered at distance would be $16.7.
It is reassuring that the main estimates for overseas built central receivers accessed (NREL, 2010, IPCC, 2011, Annex 111, Wood, et al., 2012 and Hearps and McConnell, 2011, and Wood et al., 2012) are more or less in agreement on the present cost. The only Australian estimate Hearps and McConnell quote, by AEMO, anticipates a 35% fall by 2030, to $4,166/kW(p). (ABARE 2010 also expects a c. 35% fall.) For construction in Europe and the US the fall anticipated is 50%. However Wood et al. (2012, Ch. 4, p. 7) show that after rapid initial falls the capital cost of solar thermal plant has not fallen for several years.
The cost estimate given for a 100 MW example central receiver described by NREL (2010, 2011) is $658 million, or $6,580/kW(p), i.e., for present construction. It is predicted to generate 19 million kWh in a winter month, corresponding to a continuous flow of 25.5 MW. It is assumed here that this cost figure includes interest costs and dry cooling energy and dollar costs. Adjusting for the above 15% transmission and 10% embodied energy costs this comes to 19.4 MW, or a continuous 24 hour flow of 19.2 W/m2. Thus the present net capital cost per watt delivered at distance is ($658 million)/(19.4 MW) = $33.7/W.
The AEMO expectation that central receiver costs will fall 35% below present costs by 2030 indicates a future cost of $22/W, and this will be used in the budget below. Note that the AEMO future cost estimate of $4166/kW (p) is close to a 35% fall from the NREL SAM example central receiver cost of $6,580(p).
Quantities and costs for winter supply.
From Table 1 above the supply task is 1.818 EJ/y of electrical energy and 1.403 EJ/y of non-electrical energy. Three possible strategies will be explored, focusing on meeting demand in winter.
From the above discussion of conversion efficiency, to produce the required quantity of non-electrical energy in the form of hydrogen, (1.403 EJ/y x 2) = 2.806 EJ/y of electricity would need to be generated. The total amount needed would therefore be 1.818 EJ/y + 2.806 EJ/y = 4.624 EJ/y, corresponding to an average flow of 147 million kW. If divided equally between wind, PV and solar thermal, each would have to supply 49 million kW in winter.
Meeting Strategy 1 Demand.
Required in a winter month, 49 million kW
Output and cost assumptions;
492 kW/turbine, $3.45 million per turbine.
Therefore capacity needed
(49 million kW)/492 kW 99,600 turbines.
Cost $344 billion.
Required in a winter month 49 million kW.
Cost assumption: $16.7/W.
Therefore cost $818 billion.
Required in winter 49 million kW
Cost assumption: $19.4/W
Therefore cost $950 billion
Total cost $2,102 billion
Average cost p.a. assuming 25 year plant lifetime $84.1 billion
Percentage of 2011 GDP, approximately 6.5%
The 2011 annual investment sum is more than 9 times the early 2000s ratio of rich country energy investment to GDP (i.e., .7%, for building and maintaining plant, not for purchase of energy.) (Pfuger, 2003, Birol, 2003.)
The 2010 ABARES report states that energy investment in Australia has risen to $32 billion p.a., approximately 2.1% of GDP. However 71% of Australian energy production is exported so the amount of investment required to maintain domestic supply is taking about .7% of GDP. (ABS, 2010.) This is the percentage of GDP which Pfuger reports is the average for developed countries.
There are several major cost factors which have not been included in this exercise and if they could be quantified accurately they would probably multiply the above cost figure a number of times.
If confident estimates of these factors could be taken into account they would probably multiply the above $84.1 billion p.a. sum several times.
Thus the hydrogen path would clearly seem not to be viable.
It is likely that in future the proportion of electricity in the total energy supply will be increased significantly. Let us assume that conservation effort reduces the 8.97 EJ/y final demand by one-third by to 5.98 EJ/y, (i.e., assuming a one-third not a two-third efficiency gain for the 60% of transport electrified in strategy 1, to simplify the case), that biomass provides 1.54 EJ/y, hydroelectricity .03 EJ/y, and the 10% of final energy in the form of low temperature heat can all come from solar panels. The remaining energy supply task would be 3.533 EJ/y, corresponding to a flow of 112 million kW. If we assume that all of this demand can be met by electricity (which is not plausible), then this plus the hydro electricity would constitute 60% of total final energy supply, with biomass and low temperature heat making up the rest.
If the 112 GW task is allocated 25%, 30% and 45% to wind, PV and solar thermal sectors the supply from each would have to be 28 million kW, 34 million kW, and 50 million kW respectively. (The wind and PV percentages are the maxima regarded as capable of being integrated into supply systems; Lenzen, 2009.) Applying the reasoning in Table 2 to the winter monthly supply task results in a total annual investment cost which is 82% of that for Scenario 1, the hydrogen path. Again this does not include the many omitted items noted above except for the hydrogen items.
It would appear therefore that increasing the proportion of the economy running on electricity would not make a large difference to the capital cost. At first sight this is counter-intuitive as the task of generating twice as much electricity as is needed in the form of non-electrical energy has been avoided. However, firstly this only reduces the amount of electricity that needs to be generated by about 15%. Secondly strategy 1 assumed wind, the cheapest of the three renewable, contributing 33% of demand (after biomass, hydro and low temperature heat), whereas in Scenario 2 it contributes 25%, and the much more costly solar thermal contribution is increased by 20%.
However, strategy 2 would not seem to be viable due to problems of variability, intermittency and storage. There can be periods of several consecutive days when there is negligible wind or solar energy anywhere within continental sized regions. Several studies document this phenomenon. For instance Oswald, Raine and Ashraf-Ball, (2008) shows that for the first 6 days of February 2006 there was almost no wind energy generated from Ireland to Germany, and one of these days was the coldest of the year in the UK. Although not reported, it would probably also have been a period of negligible solar energy. Similar documentation is given by Soder et al., (2007) for West Denmark, Sharman, (2005), and Mackay, (2008), for the UK, E On Netz, (2004) for Germany, and Davey and Coppin, (2003), Lawson, (2011) for Australia, and in Lenzen’s (2009) review of wind energy.
An economy heavily dependent on electricity could not function through such weather events unless extremely large quantities of electricity could be stored. At present this is not possible and it is not foreseen. For instance, the magnitude of the task greatly surpasses the potential of pumped storage (shown by Mackay for the UK, 2008). The difficulties in storage via hydrogen have been discussed above, and for solar thermal storage they will be considered below. Also to be considered in strategy 4 is dealing with gaps via biomass.
If it is assumed that the gaps could be plugged by biomass generation then another significant problem of redundancy arises. During periods when the sun and wind failed to provide energy sufficient biomass-burning generating plant would be needed to meet total demand. Given the lower efficiency of biomass generation of electricity (the IPCC, 2011 Annex 111 indicates 28%, Farine et al. 2011 report 27%, El Bassam, 1998, reports the average for US plants at 18%, and Harvey, 2010, reports a range from 14% to 28%), Australia would need about 7 times as many biomass power stations as the number of coal-fired power stations it has now, to deal with average demand, and more to meet peak demand. Most of these would be idle most of the time. Lenzen (2009) notes the issue of back up capital costs and points out that these should be accounted to the renewable technology requiring them.(Generation via biomass-gas powered turbines is highly efficient, but this is only part of the complete process including production of the gas, production and trucking of the biomass, and return of ash to the plantation land.)
A third conceivable strategy would be to use as much electricity as possible and to attempt to solve the intermittency and storage problems by relying on the capacity of solar thermal power stations to store heat.
If all of the 112 GW of electricity supply could come from solar thermal plant at $19.4/W, the capital cost of the quantity of plant required in winter would be $2,328 billion, considerably higher than for Strategy 1 above. However this does not take into account the intermittency problem solar thermal involves despite its storage capacity.
The discussion of solar thermal potential is typically carried out in terms of annual and at times monthly average levels of solar radiation whereas what matters most are minima and their frequency of occurrence. The following notes indicate the magnitude of this problem. The ASRDHB (2006) provides tables on the probability of sequences of cloudy days at Australian sites. At Alice Springs the probability of a 5, 7 or 9 day run in which average daily global radiation in winter is under 4.86 kWh/m2/d is 100% in all cases. (DNI data is not given but other tables show that DNI is around 15% lower than global.) There is a 90% chance of a 4 day run averaging under 3.75 kWh/m2 (i.e., under c 3.2 kWh/m2/day of DNI), and in each of the 4 winter months there is a 25% chance of a 4 day run with global radiation averaging under 3.75 kWh/m2/d. Even on a 4.86 kWh/m2 (global) day DNI would rarely reach 700 W/m2, a level at which dish-Stirling output falls to 50% of peak. At 3.2 kWh/m2/d DNI virtually no output would be produced by solar thermal systems. (Odeh, Behmia and Morrison show that under 600 W/m2 trough output plunges.) There is a 100% chance that in June there will be a sequence of 14 days in which global radiation is under 5.5 kWh/m2 day. This means DNI would be under 4.8 kWh/m2/d, i.e., under 85% of the 5.7 kWh/m2/d winter average for central Australia. Elliston (2012) documents 4 to 9 day periods of negligible solar radiation at a number of Australia’s best solar thermal sites.
Thus even in the best sites, in winter solar thermal systems would experience lengthy periods of low or negligible output. At present only about 7 hours of heat storage capacity is being built into solar thermal plant but 15 hours is being planned for future systems. The above evidence indicates that for the solar thermal sector to make a continuous contribution more than four day or 96 hour storage would be needed. If however the solar thermal sector is to be equipped with the heat storage capacity capable of meeting total electricity supply system demand through four cloudy and windless days, then it would need 40 times the c. 7 hour storage capacity currently being built into solar thermal power stations. The NREL (2010, 2011) breakdowns of component costs for central receivers indicates that this might multiply the dollar cost of a power station by a factor of 7.
The energy cost of building additional storage would also have to be deducted from gross output. Foran’s figures (2011, p.107) indicate that the embodied energy cost of 7 hour storage is 1/7 that of the energy cost of the remainder of the plant. This suggests that the embodied energy cost of the foregoing four day storage requirement would multiply the plant’s embodied energy cost by approximately 7, possibly making it almost as high as plant lifetime output.
In addition the power block would have to be big enough to generate at three times its normal rate of output, and transmission lines from solar thermal farms would have to have the capacity to carry three times normal loads. These factors would significantly increase dollar and embodied energy costs.
It would therefore seem to be clear that solar thermal heat storage capacity could not enable a renewable system to overcome the big gap problem.
Strategy 4. Plug the big gaps with biomass.
Elliston, Diesendorf and MacGill (2012) claim to show how all Australia’s present electricity demand could be met by renewable energy. Their approach is valuable in focusing attention on the way renewable sources might be combined to meet demand at any time. Of most interest here is the possibility of plugging the gaps in wind and solar energy with biomass generated electricity.
Their Fig.2 shows that over a six day period in winter 2010 approximately 40% of electricity supply came from biomass generated electricity. However if a “big gap” event left most of the continent with negligible wind or solar radiation then biomass generation would have to provide approximately 77% of demand, the rest being provided by hydroelectricity. These figures set two problems, the first concerning the amount of redundant or back-up plant required, and the second the amount of biomass required.
Fig.2 shows that times about 25 GW of biomass generating plant is being used, and at other times about 19 GW of wind energy is being generated. When the maximum contributions of all sectors is added around 75 GW generating of capacity is needed to meet the average 25 GW demand, i.e., three times as much as would be needed in a coal-fired system. When the estimates used in the above Table 1 and 2 derivations is applied to these quantities, the total capital cost arrived at is $609 billion, not including the hydroelectric system or the large biomass electricity system. This corresponds to $24 billion p.a., or 1.8% of GDP, almost three times the rich world investment/GDP ratio for the total energy system, not including hydro, biomass or transmission components.
From Figs. 1 and 2 it seems that biomass would be providing 20% of annual electricity supply. Although biomass-gas-electricity generation has a high efficiency (Diesendorf indicates 40%, 2007), a value for the whole plantation to transmission system does not seem to be available. If an overall 30% is assumed the amount of biomass required would be approximately 29 million tonnes p.a. This would draw on the quantity available to meet liquid fuel demand.
Note that this proposal to meet 25 GW average demand, i.e., 790 PJ/y, leaves the task of providing the other c. 80% of present Australian energy demand. If total energy demand doubles by 2050 as is assumed in the above derivations, the remaining task would be to supply 8.97 EJ/y of final energy, some 11.4 times as much as Elliston, Diesendorf and MacGill set out to explain. Again the capital
cost implications would seem to be insurmountable.
These capital cost conclusions might appear to be irreconcilable with the fact that the predicted capital costs for some renewable technologies such as wind, and their associated levelised cost of electricity (LCOE), are or will soon be comparable with those of coal-fired plant. However levelised costs are misleading indicators for the derivation of total system costs. Firstly, easily overlooked is the fact that these are typically statements about cost per peak watt of output, not per average delivered watt. A coal-fired plant might generate at full output 90% of the time, whereas for PV and solar thermal plant the figure is around 20-25%. Thus the capital cost of renewable plant per kW delivered is much higher than the “nominal” or peak value, i.e., the usually stated cost per peak watt of output.
Thus the “levelised cost” of renewable energy is a misleading indicator of system capital cost as it does not indicate the cost of the required redundant back-up plant when wind or solar resources are making negligible contributions.
The two most questionable assumptions in the foregoing analysis would seem to be the 2050 supply target, and the biomass yield. Reducing the target assumption by 25% would not seem to bring it within achievable range. The Australian population is now estimated to reach 36 million by 2030, a 75% increase, so only a little increase in per capita energy use would be needed to double total business as usual demand by 2030, twenty years before the target date taken in this discussion.
The biomass harvest assumed here is 2.5+ times that arrived at by Farine et al, 2011. If the highest assumption noted above for biomass energy producing land accessible, 58 million ha, is taken, an additional 1 EJ/y would be produced. This would reduce the amount of wind, PV and solar thermal capacity needed, and its combined capital cost by 30%, but the cost of the biomass component would be increased by 40%. It would seem therefore that taking the highest biomass assumption would still not make the strategies considered affordable.
Similarly assuming 20% PV efficiency rather than 15%, and a 50% fall in solar thermal capital cost rather than a 35% fall, would not make the total system capital cost affordable.
This has not been an argument against full transition to renewables. It is an argument against the possibility of running the presently energy-intensive Australian society on them. As with a number of previous attempts to analyse the potential of renewable energy (e.g., Trainer, 2007, 2010a) the general conclusion supported by this discussion is that the greenhouse and energy problems cannot be solved by action on the supply side, i.e., by technical developments which promise to provide the quantities taken for granted in energy-intensive societies. This general “limits to growth” perspective is that these and the other major global problems can only be solved by action on the demand side, i.e., by moving to ways, values, institutions and systems which greatly reduce the consumption of materials, energy and ecological resources.
The Simpler Way vision elaborates on the general claim that marked reductions in energy and resource consumption and in ecological impact could be achieved while improving the average rich world quality of life, but only if large and radical changes were made in lifestyles and systems. Among these would be abandoning the growth economy, severely controlling market forces, shifting from representative to participatory democracy, developing mostly small and highly self-sufficient local economies, and accepting frugal and cooperative lifestyles. Although at this point in time such a transition would seem to be highly unlikely, Trainer (2010b) details the case that the global limits to growth predicament cannot be resolved unless it is achieved.
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