Ted Trainer. University of NSW, Kensington. 2052.                                                                                           




It is commonly assumed that greenhouse gas and energy problems can be solved by switching from fossil fuel sources of energy to renewables.  However little attention has been given to exploring the limits to renewable energy.  The main problems are to do with the magnitude of the supply tasks that would be set and the difficulties that would be encountered integrating large amounts of intermittent renewable energy into supply systems.  This paper argues that wind, photovoltaic, solar thermal and biomass sources, along with nuclear energy and geo-sequestration of carbon could not be combined to provide sufficient energy to sustain affluent societies while keeping greenhouse gas emissions below safe levels.  The case is strongest with respect to liquid fuels and transport.  Brief reference is made to the reasons why a “hydrogen economy” is not likely to be achieved.  The conclusion is that consumer-capitalist society cannot be made sustainable and the solution to major global problems requires transition to The Simpler Way.


This c. 50 page account is updated from time to time, to summarise and improve on the discussions in Renewable Energy Cannot Sustain a Consumer Society, T. Trainer, Springer, 2007.


Web address: http://ssis,


(Early 2000s figures are used for the $(A)/$(US) exchange rate, i.e., $(A)(1 = .7 $(US) and for the price of coal.  Square metre is indicated by m, not m2.)


Awareness of the need to reduce use of fossil fuels and of the possibility that petroleum supply is close to peaking is rapidly is increasing.  However it would be difficult to find a more unquestioned assumption than that it will be possible to substitute renewable energy sources for fossil fuels without threatening the fundamental commitment of consumer societies to high “living standards” and economic growth.  It is generally assumed that we can move from fossil fuels to renewables without any need to question affluent living standards and economic growth. 

There has been little critical discussion of limits to renewable energy. There seems to have been only been one book published on the topic, Hayden’s The Solar Fraud, (2004) before my in Renewable Energy Cannot Sustain A Consumer Society (Trainer 2007a.)  Unfortunately people working on renewable energy technologies tend not to throw critical light on the difficulties and limits.  They typically make enthusiastic claims regarding the potential of their specific technologies.


The concern in Renewable Energy Cannot Sustain A  Consumer Society was to summarise and interpret accessible evidence as an early step in an overdue process which might in time arrive at confident conclusions.  Some of the book’s analyses are not very satisfactory, mostly because of the difficulty of accessing information.  Commercial operators possessing key information often will not make it public, often ventures are experimental with obscure implications for long term viability, and at times conclusions derive from modelling studies with uncertain assumptions rather than field experience, etc.  The book is therefore not offered as having settled many issues but rather as an attempt to assess the implications of the evidence that it has been possible to access, so that subsequent studies can build on these mostly tentative impressions.  The present paper summarises some of the book’s themes, but adds evidence and argument that have come to hand since the writing of the book.  It offers more sound analyses of some themes, especially solar thermal.


Because there has been little study of the limits of renewable energy little or no critical literature has been available for incorporation into the discussion of topics such as the capacity to solve the greenhouse problem.  The highly influential Stern Review (2006), the IPCC Third Working Group Reports (IPCC 2001, Barker, et al., 2007), and the Final Garnaut Report, (2008) have therefore made naïve and highly challengeable optimistic assumptions about the potential of renewable energy because they have made no reference to the factors which indicate that renewables cannot solve the greenhouse problem. For a critical analysis of the Stern Review see Trainer 2007b, and of the IPCC see Trainer 2008, and of Garnaut see Trainer 2008.  These discussions overlap as the three reports all make the same mistakes and a combined critique is in Trainer, 2007d .  Their conclusions regarding mitigation have relied solely on a large economic modelling literature which assumes without examination that renewables can be scaled up sufficiently.  As a result in my view their general and universally accepted conclusions, i.e., that the greenhouse problem can be solved and that it can be solved at negligible cost, are invalid and are leading to fundamentally mistaken policies and actions.


It must be stressed that the argument in this paper does not question the analyses the discussions of climate science in these three reports.  Nor does it argue against renewable energy sources; we must move to full dependence on them as soon as possible, but it is argued that we cannot run a consumer-capitalist society on them.  The claim that we could live well on them via The Simpler Way is argued in the last chapter of Trainer 2007 and detailed on The Simpler Way webpage, Trainer 2006.


It is necessary to divide a discussion of renewable energy potential into two parts, one to do with electricity and the other to do with liquid fuels.  Liquid fuels set the biggest problem.


            A note on “Technological Advance.”


No field is more ridden with ecstatic boosters than that of renewable energy.  Frequently the media reports another miracle technical breakthrough that is guaranteed to save us.  The doubts and difficulties don’t get mentioned.  One important point here is the significant difference that usually exists between,


·      Technical potential”; i.e., what might be achieved without regard to costs.


·      Economic or ecological potential; i.e., what could be done at reasonable cost, or acceptable environmental impact. (Smeets, and Hoogwijck estimate technical potential for global biomass-energy production at c. 1400 million ha...but the WWF estimates the environmentally acceptable area at 250 million ha.  Smeets says the technical potential from extra forest production is 64 million tonnes...but the environmentally accepted amount is only 8 million tonnes.


·      The net achievement.  Costs must be subtracted from gains.  It is possible to save a lot of the heating energy loss from buildings, but this requires energy in the form of insulation and electricity for air-conditioning and heat pumps.  The WWF graphs appear to show no net gain for buildings.


·      The socially acceptable achievement.  It would be possible to reduce urban transport energy markedly by greater use of public transport, but many people will prefer to keep using their cars.


·      The Jeavons effect.  Often savings of energy made possible by a technical advance enable greater use of energy.


Thus it is important to be very cautious about what an announced technical advance will actually achieve; it is likely to be well below initial expectations.




There is a strong case that biomass cannot meet more than a very small fraction of the global demand for liquid fuels (i.e., oil plus gas.) Any very large scale scenario will have to be via ethanol produced from woody biomass.  There is far too little forestry waste, oil crop potential, or corn/wheat input material for biodiesel or ethanol production on the necessary scale. (Hydrogen will be considered below.)


            Land area and yield assumptions.


Unfortunately estimates of the land areas that could be used for biomass energy production, and yields vary greatly.  Hoogwijk et al. (2005) conclude that 1100EJ/y is achievable, smeets and Faaij (2007) say 1538 EJ/y, whereas Field, Campbell and Lobell (2007) say the amount is 27 EJ if ecological damage is to be avoided.  Hoogwijk et al.’s assumptions and derivations seem quite implausible,  e.g., that 2+ billion ha of abandoned agricultural land could be used, up to 40% of the planet’s land area could be planted for biomass harvest, and yields could be 15 t/ha from very large areas.  The IPCC (2011) notes that the total Net Primary Production of the entire planet is only about 1550 EJ/y

Hoogwijk et al. do note the standard distinction between “technical potential” and “economic potential”, indicating that they recognise that their high figures are well beyond rates likely to be achieved.  Also important here is the fact that much of the land Hoogwijk et al. report is in very remote regions and biomass is bulky and not very energy-dense y volume, and thus costly to transport. The energy produced would then have to be transported to users in distant locations again cutting net yields.  These factors would rule out use of much of the “technical potential” they identify.


Following are the main reasons for thinking that a realistic biomass energy yield will  be quite low.


·      There is already great pressure on all the land on the planet, and it is commonly accepted that food production will have to double.  Normal economic growth will deliver an economy in which there is four times as much  producing and consuming going on in 2050 as there is now, with corresponding increases in resource demand.  Rising energy costs will tend to move demand for structural materials from steel, aluminium and cement to timber.  Three billion more people, mostly in poor countries will greatly increase demand for land and its products.  Thus the demand for land to produce other than biomass energy will probably greatly intensify.

·      As the IPCC 2011 report notes water is a problem for very large scale biomass production.  Large quantities would be removed from ecosystems in the biomass. 

·      Large quantities of soil nutrients and especially carbon would be removed.  Developed countries have suffered long term deterioration in soil carbon levels.  Patzek (2007) argues that over the long run no carbon should be removed because if it is soils inevitably deteriorate.  If the answer is to capture the carbon after extracting energy and return it via biochar, we would need reliable figures on the percentage that can realistically be transported back to where it came from, at what cost, especially at what plant capital cost.

·      The biodiversity effects are probably the most disturbing.  The holocaust of species extinction humans are now causing is primarily due to the fact that we are taking so much natural habitat.   Humans take 40% of the land NNP.  (Vitousek, 1986.) Obviously we should be returning vast areas to natural habitat, not thinking about taking more.

·      The IPCC (2011) says that 80% of the present 50 EJ/y global harvest of biomass energy is “traditional use” by tribal and peasant people.  This is labelled “inefficient” use and the Report anticipates shifting this land to the much more productive ways characteristic of modern biomass energy systems.  That area is likely to correspond to 750 million ha.  But this land provides crucial services sustaining the lives, livelihoods, ecosystems and communities of the poorest billions of people on earth, the building materials, food, medicines, hunting, animal fodder, water, products to sell, traditions, social networks...  The greatest onslaught of the global economy on the poorest billion is precisely the taking of the land on which they depend for life. To move this land into modern “efficient” production would inevitably be to transfer the resource from the poor to the rich, if only because the operation would be governed by “market forces”.  When markets are allowed to determine distribution the rich get the scarce goods because they can pay more.  The economies determining the use of those lands now are “subsistence” economies, largely governed by social rules and traditions and not by market forces or profit.  To move these lands into the market would be to eliminate the processes which ensure that the poor majority benefit from them.

It is therefore anything but clear how much biomass energy we should attempt to produce, but it would seem that the figure would be a small fraction of the 250 EJ/y the IPCC reports as the average of the estimates made. 


The common biomass yield per ha assumption of 13 t/ha/y, made by the IPCC also seems to be unrealistic.  It is easily achieved in good conditions, such as willows on cropland, and adequate irrigation and fertilizer applications, but very large scale biomass energy will have to use large areas of marginal and/or damaged land.  Biomass in the form of forest can be produced at 20 t/ha/y, and more than 35 t/ha/y as sugar cane (dry weight), but only in special conditions.  World average forest growth is around 2-3 t/ha/y.  A more biomass-energy realistic yield figure might be 7 t/ha/y.  Foran and Crane, 2002, appear to assume 6 t/ha/y.  At 7 t/ha the 250 EJ/y the IPCC says is the average of the estimates it reviews would require 2 billion ha, an extremely unrealistic figure.


Easily overlooked is the fact that 250 EJ/y of primary biomass energy will only yield about 80 EJ/y of ethanol, and an even lower quantity of electrical energy. (El Bassam, 1998, reports the average efficiency of biomass electricity generation in the US at 18%.  The IPCC, 2011 Annex III gives four estimates, averaging around 30%.)  If the mid point in the Greenpeace estimate is taken, 134 EJ/y, this corresponds to only about 45 EJ/y of ethanol. Given that world energy demand is heading towards 800-1000 EJ/y by 2050, 45 EJ/y would not go far towards enabling total demand to be met by renewables, or to plug gaps left when there is no wind or sun.


The view among the main researchers and agencies tends to be that in future it will be possible to produce about 7 GJ of ethanol from each tonne of woody biomass.  (Derived from Fulton, 2004.  See also Hoehenstein and Wright, 1994.)   Foran believes the yield might eventually rise to c 90 GJ/ha.  In addition 1 GJ of electricity per tonne of biomass might be generated from the associated process heat. However some authorities doubt that ethanol from cellulose will become economically viable.  (See Augenstein and Benemann, 2007.)  The 7 GJ figure is an estimate of net yield, i.e., the amount after all energy costs of production have been paid.  Foran and Crane (2002) conclude that a somewhat better yield might ultimately become possible via methanol.  Mardon (personal communication)  points out that estimates of ethanol yield from biomass vary considerably and that as there is as yet no commercial plant operating on cellulosic inputs. Consequently confident conclusions are not possible.


In view of these figures it will be assumed here that ethanol will be produced from woody inputs at 50 GJ/ha/y.  Australians use about 128 GJ of liquids (oil plus gas) per capita per year.  This would mean each Australian would need 2.6 ha of land growing biomass to provide for their liquid and gas consumption (in the form of ethanol net, not primary energy.) To provide the 9+ billion people we will probably have on earth by 2060 we would therefore need 24 billion ha of biomass plantations.


Stern implicitly assumes (evident in his Fig. 9.4) that by 2050 biomass will yield 110 EJ. This is a doubtful assumption because it would require 850 million ha, equal to more than half the present area of cropland.  If shared among 9 billion people this amount of biomass would provide ethanol equivalent to only 4 GJ per person p. a., when the present Australian transport fuel consumption is 60 GJ/person (and is increasing at 2% p.a.).


Are dramatic increases in yields from genetically engineered new biomass crops likely to change the outlook?  Sinclair, Purcell and Sneller (2004) say “…future applications of biotechnology to crops does not seem to offer much hope for substantial yield increases.”  Field, Campbell and Lobell (200) point out that Green Revolution yield increases were for grain not plant mass.


There are many reasons why the potential for biomass energy  production is likely to  decline in future years, including increased pressure on land for food and building materials as energy-intensive materials become more expensive, and especially the effects of the greenhouse problem.  For instance the water resources of the Murray-Darling river system in Australia are likely to be greatly reduced this century.


The potential in the harvest of algae has often been raised, given the very rapid growth rates some exhibit.  Mackay says that they need large inputs of C02 to sustain high growth and without this growth can fall to 1%.   Thus it is sometimes suggested that they could take gases from power stations, but this would have no net effect on greenhouse emissions as the carbon would eventually go into the atmosphere when the fuels produced from the algae were used.


Proposals to derive a high proportion of energy from renwewables are likely to rely heavily on biomass to fill gaps left in solar and wind supply.  Easily overlooked is the very low efficiency such plant is likely to have. El Bassam (1998, p. 33) says that it can be as low as 5 – 10% for plants up to 1 MW capacity and 15 – 30% for capacities from 5 to 25 MW.  Biomass electricity plants must be small because they must use biomass produced within relatively short distances.  In addition to transport costs biomass must  be dried before combustion and for large scale used this would set cost and logistical difficulties, e.g., for machinery, kilns or covered storage areas.


There would therefore seem to be little chance that biomass could provide more than a quite small proportion of world liquid fuel demand.  Therefore the above assumptions can be varied considerably without it becoming possible to show how all people could rise to anywhere near the present rich world liquid fuel consumption derived from biomass.


The Australian situation differs from most countries  because we have much more sun, good wind and far more land for  biomass per person than the world average.  However Trainer 2010c sets out a numerical case supporting the conclusion that it would be too costly for Australia to attempt to meet anticipated 2050 demand on renewable energy.




The renewable energy outlook would  be significantly affected if much of the economy could be converted to electricity.  The extent to which this is possible is not clear as the relevant statistics are not collected. (ABARE and the ABS confirm Ayres 2008 on this.)  ZCA (2010) claims that almost the whole economyh could be converted.  At present only 25% of final energy use is electricity but most of the 33% used for transport ould be converted.


Many sources could contribute some renewable electricity but the most likely three are wind, photovoltaic solar and solar thermal.  Several other technologies are valuable and/or promising (briefly referred to below) but it is not clear that they are likely to contribute significantly to very large scale electricity production.






Lenzen’s review (2009, p. 86)  concludes that while global wind energy resources are very large, most of it is in Northern Canada, Siberia and Patagonia.  Only 5% is in areas of high electricity consumption.


An examination of wind maps indicates that the annual quantity of wind energy that is available in the US and SE Australia could well be considerably greater than demand. The European situation seems different; Trieb (undated, p. 48), a strong believer in the potential of renewables, estimates total onshore plus offshore potential is about 4 EJ. Lenzen states much the same figure.  On land usually only a small fraction of the suitable area can be given to wind farms, for reasons such as prior uses.  This is especially so in densely populated Europe where the fraction could be under 10%.  In off-shore regions this is not such a significant problem but off-shore potential is less clear because much depends on the water depth limit assumed.  The maximum water depth for windmills at present is around 18 metres. (Mackay, 2009 gives a similar figure.)  Windmills might eventually be mounted on floating platforms but the cost and the movement make this problematic.


If wind was to provide a large fraction of electricity demand then many times the present wind farm area would be needed. For instance Stern’s assumed wind contribution, 62 EJ, by 2050 would be about 120 times the early 2000s contribution. (Coppin, 2008.  Installed wind capacity is increasing rapidly, confusing comparisons.)  However this is a misleadingly low target.  If wind was to provide one-third of the 4500 EJ that would be needed to provide 9 billion people with the per capita electricity use Australians are heading for by 2050, the multiple would be about 3000 times the early 2000s wind contribution.  Even a 10-fold increase for Europe would require use of very distant regions, such as Morocco and Siberia, along with a possibly15% loss in transmission (Mackay, 2009), embodied energy costs of transmission plant, and/or use of less than ideal sites.  So far only the best sites have been used and the average “load factor”  (ratio of output to peak output) is only .23. (IPCC, 2007, Section  Lenzen’s review, 2009, states .25 for 2008.) (The figure for off-shore mills is .28. House of Lords, 2007-8.)  Technical advance (many of the present mills are aging) and higher hub heights will tend to raise this average capacity factor in future, but the best close sites will have been taken already, so future sites are likely to have lower capacity factors.  Better sites, at very long distances away could be accessed, but then there would be losses in transmission.  Also relevant is the fact that Germany has relatively poor wind resources but has built a lot of windmills, tending to lower world average output.


Lenzen (2009, p. 97) reports the embodied energy cost of wind at 3.5 – 7.5% of lifetime output.  However a large scale contribution from wind would have to rely heavily on off-shore turbines, which cost almost twice as much as on-shore turbines.  This refers to use of relatively shallow sites (reported as c. 18 metres at present), and deeper water sites will have to be used in future.


The intermittency problem.


The major limitation with most renewables is not to do with quantity but concerns their intermittency.  The typical pattern of output from a wind system rises and falls markedly much of the time and sometimes there is little or no wind for long periods.   Australian modelling by Poldy (2008) shows that electricity supply from a large integrated system would more or less rise and fall by a factor of 2 every day.  In the past it has been generally thought that because of its intermittency wind might be able to contribute up to 25% of demand, but there is reason to think that the figure will be lower.  Lenzen’s review (2009, p. 88) concludes that it will be 20 - 25%, because problems and costs due to variability increase steeply after that point.  For instance dumping increases considerably.


The Germans, with far more wind mills than any other country, and the Danes with the world’s highest ratio of wind output to electricity consumption, experience difficulties at times even though wind is supplying an average of only about 5% of national demand.  (See Sharman, 2005, E.On. Netz, 2004, 2005.  Sharman (2005) reports that even in Denmark in 2003 the average output of the wind system was about 17% of its peak capacity and was down to around 5% for months at a time.  The E.On Netz  (2004) report for Germany also says that in 2003 the system averaged only 16% of its peak capacity, and around 5% for months. They stress that 2003 was a good wind year.\


Denmark’s output of wind energy is equivalent to c.18% of the demand from its very small population, but the DEPOS think tank says most of this is not used locally and can be conveniently exported to large neighbouring countries with hydro storage capacity or large demand.  Lund et al. dispute this figure, claiming that only 1% is exported.  The issue is complex, depending on how the statistics are interpreted. The correlation graphs show exports increasing as wind input increases, but drawing causal conclusions is difficult; Lund et al. say exports from coal fired plant also goes up when wind is high, but it seems to me that this just means when winds are strong there an excess and all suppliers seek to export.


The magnitude of the integration problem is made clear in a recent study by Oswald Consulting (2006) modelling the typical performance of a system spanning the whole of the UK.  They found that in mid-winter, the best wind time of the year, system output could plunge from 85% of peak capacity to 10% in 10 hours.   Following is Oswald’s plot for January (...a good wind month.).






Mackay presents a similar picture on pp. of 186 – 187 of Sustainable Energy; Without The Hot Air, (  Lenzen’s representation of data from Oswald, for the whole of Germany, follows. (To be added.)  Note thmat at times output is close to zero, for some days.



It would be difficult if not impossible to “ramp up” coal or nuclear capacity to fill the gap that quickly if wind constituted a large proportion of generating capacity.  Note above how at a number of points in the plot almost all wind input is lost in a few hours.  In any case the jagged wind supply distribution would require constant variation in output from other generators and this is not good for their efficiency or wear and tear.  (Gas turbines can vary more easily, but gas resources are about as limited as oil, and fossil fuel use must be greatly reduced; see below.)


Davey and Coppin (2003) carried out a valuable study of probable aggregate output from an integrated system of windmills across 1,500 km  of south east Australia.  Its findings align with those of Oswald.  Coppin points out that this region has better wind resource than Europe in general.  Linking mills in all parts of the region would reduce variability of electricity supply considerably, but it would remain large.  Calms would affect the whole area for days at a time.  Their Figure 3 indicates that the aggregated system would be generating at under 26% of capacity about 30% of the time, and for 20% of the time it would be under 20% of capacity.  Clearly a very large inter-connected wind system would have to be backed up by some other large and highly reliable supply system, and that system would be called on to do a lot of generating.


The study of the wind energy potential of a system spanning the whole of Ireland (Coelingh, 1999) yields a plot (Fig. 7) similar to those from Oswald and Davey and Coppin, but with less favourable values.  For instance, output would be under 20% of capacity 40% of the time, under 8% 20% of the time, and under 4% 10% of the time.


Mackay (2008, p. 189.) reports data from Ireland between Oct. 2006 and Feb. 2007, showing a 15 day lull over the whole country.  For 5 days output was 5% of capacity and fell to 2% on one day.


Lenzen’s review (2009) confirms the fact that synoptic weather patterns can cause whole continents to undergo stable and calm conditions for days at a time.  For instance weather patterns tend in SE Australia to come across the continent from the west subjecting a particular region to several days of a particular regime or set of conditions.  He notes that having to ramp up and down output from coal-fired plants to compensate for fluctuation in wind input means reduced efficiency of generators.


Lenzen’s graphs make the magnitude of the problem clear.  One from Oswald et al, (2008) shows wind energy availability over the whole of Ireland, UK and Germany for the first 300 hours of 2006, i.e., in mid winter, the best time of the year for wind energy.  For half this time there was almost no wind input in any of these countries, with capacity factors averaging around 6%.  For about 120 continuous hours UK capacity averaged about 3%.  During this period UK electricity demand reached its peak high for the year, at a point in time when wind input was zero.


Soder et al. (2007) provide a similar plot for West Denmark in mid winter, again one of the best wind regions in the inhabited world.  For two periods 2 and about 2.5 days there was no wind input at all, and in all there were about 8 days with almost no contribution from wind energy. 


Clearly these periods of calm are not rare and of minor significance.  For several days in a winter month in good wind regions there would have to be almost total reliance on some  other source.  The capital cost implications of having a back up system capable of substituting for just about all wind capacity are rarely focused on.


Lenzen’s third plot is for the whole of Germany, again showing hardly any wind input for several days in a row. (See also E.On Netz, 2004.) 


The following diagrams represent the magnitude of the problem.  The first diagram below represents sun and wind input on a cloudy and calm day, assuming the peak capacity of each is about equal to demand (see diagrams 3 and 4.)  The second represents input on a sunny and windy day.



The  third and fourth diagrams, below, add these inputs (S + W), and also show the average  hourly demand for a typical day.    On the cloudy and calm day solar plus wind input falls far below demand, but on the good day they far exceed it, meaning much energy would have to be dumped, if it could not be stored.  Note the big difference between total S +W contribution on the two days, differing by a multiple of about 6.






Because the wind sometimes does not blow at all, in a system in which wind provided a large fraction of demand there would have to be almost as much back-up capacity from other sources as there is wind generating capacity.  E. On Netz has emphasised this problem with respect to the German experience. The Oswald study showed that in Britain, possibly the best wind region in the inhabited world, and in January which is about the best month of the year for European wind energy, there would be about three times during the month when wind energy fell almost to zero.  So if we built many wind farms we would have to build almost as many coal, gas or nuclear power stations to turn to from time to time.    (The problem would be offset in so far as solar sources were contributing at these times of need, but this is not a strong prospect in Europe in winter.)  This mistaken assumption is evident in Stern’s Fig. 9.4.)


This means that renewable sources tend to be alternative rather than additive.  Therefore it is not a matter of having each renewable source carrying a fraction of the load all the time.  If we build one unit of wind power and one unit of PV power we would not necessarily have two more units of renewable energy generating capacity; sometimes we would have no more, e.g., on calm nights.  This means we might have to build two or even four separate systems (wind, PV, solar thermal and coal/nuclear) each capable of meeting much or all of the demand on its own, with the equivalent of one to three sitting idle much or all of the time.  This would obviously be very expensive.


In addition electricity distribution grids would have to be reinforced and extended to cope with the new task of enabling large amounts of power to be sent from whatever region had high winds at that time.  Centralised coal or nuclear powered systems do not have this problem.


One aspect of the variability problem is the seasonal difference in wind strength.  Czisch ( 2004, Fig. 5.) shows that in February Europe gets almost 5 times as much wind energy (not mean speed; energy is proportion to speed cubed) as in May, so if we built a system big enough to meet demand in February it would only do 20% of the job in May.  The difference is evident in the above winter and summer capacity figures for Denmark and Germany.


            Inter-continental grids?


There are schemes for connecting vast intercontinental regions into the one wind energy system, e.g., from Morocco to the Sahara and Kazakhstan. (Czisch and Ernst, 2003.)  This would considerably reduce the variation problem because when the winds were low in Western Europe they would probably be high in some of the other regions. The important point however is that even though wind speed correlations across such distances could be zero and some wind would usually be blowing somewhere, there would still be many times when the average wind across the whole system was low, and that means the wind system as a whole would not be producing much.  The studies by Davey and Coppin, Oswald and Coelingh referred to above show this.  “Synoptic” weather patterns often apply to large regions.  Sharman points out that Europe can experience long periods of very cold, calm and cloudy weather in winter.  As Hayden (2004, p. 150) says, “There are times when the wind is calm everywhere.” 


Thus it should be clear that the common statement, “...the wind is always blowing somewhere...” fails to grasp the problem.  If we assume that the wind is always good in Morocco, or Kazakhstan or Siberia or Western Europe, then if we are to have a system that always reliably meets demand from one or other of these regions, we would have to build four entire systems each big enough to meet demand.  We would also have to build several costly 4,000-5,000 km transmission lines to Europe (losing perhaps 15% of energy generated.) 


Note that most of these regions are well to the East of Europe so it will be night time there when European demand is highest, during the day.  Winds tend to be low at night.


Czisch (2004) estimates that long distance transmission might add 33% to electricity cost.  The IEA (2010, p. 336) estimates that the average (mostly short distance) transmission cost adds 25%.


            Capacity credit.


If many windmills are added to a supply system relatively little difference is made to the amount of coal or nuclear generating capacity that will be needed.  There is in other words little “capacity credit”.  Lenzen’s review states that if wind met 20% of demand this would only reduce the need for coal fired plant by 8% of the wind capacity installed. (2009, p. 92.)  See also House of Lords report () for the same conclusion.


“Capacity  credit” refers to “...the fraction of average capacity that is reliably available during peak demand.” (Lenzen, 2009, p. 92.)  The south Australian electricity supply agency estimates that for its wind supply system this value is only 3-4%.  However ”reliably” in this context means 95% probable and the crucial point concerns what can happen in the remaining 5% of the time, which is 17 days of the year.  As the above cases show it is very likely that what can happen is the occurrence of long periods with negligible wind.  The probability of a loss of load event might e very low, but if and when it happens the entire wind contribution would have to be made up by some other source, and as Lenzen notes the capital cost of this provision should be accounted to the wind system.


A similar problem associated with higher penetrations of wind and solar is to do with periods of over-supply and dumping.  Lenzen (2009, p, .94) reports Hoogwijck et ,al. 2007 as finding that “...the amount of electricity that has to be discarded grows strongly for penetrations  in excess of 25-30%.”  If wind and PV were to contribute 25% and 30% of electricity then on sunny and windy days they would be generating more than twice average demand.  Some degree of system “over-sizing” will probably make sense but the capital cost implications are easily overlooked.  System capital costs should be divided by electricity delivered, not generated, to arrive at a realistic system capital cost per kW.  The Zero Caron Australia proposal involves solar thermal input that regularly reaches twice the amount that can be used, but this is not taken into account in capital costing.




The probable future cost of renewable energy systems is quite uncertain.  Confident projections are often encountered, usually indicating significant reductions, e.g., to one-third of present costs.  It is important to recognise that these predictions can be little more than educated guesses.  The recent evidence on costs actually indicates significantly rising trends for wind and solar thermal, and in future much higher pkrices for materials and energy are likely to have a major effect.


In the 2000s wind farm costs have usually been quoted as c. $(US)1000/kW, but this is misleading.  The cost of some recent Australian installations reported in (Trainer 2007, Chapter 2 has been up to $(A)2,400/kW(e).  However ABARE 2010 reports an average of $2,900/kW.) 


More importantly these figures are for peak output.  Average capacity at a good site can be well above 35%+ of peak output but the global average is .23 (IPCC,2007, Section  Again the German system in 2003 averaged .16.  (We should focus on the performance of the system, not of individual mills; the system involves other factors and losses.)  If we take the recent Australian cost and a system with 25% capacity,  then the capital cost of wind-generated electricity would be almost 7 times that for a coal fired station plus fuel for its lifetime (early 2000s coal price and .8 capacity assumed.)  To this would have to be added the cost of revisions to the grids and the almost 100% duplication of wind plant with back up coal or nuclear plant if wind was to be a large component of the total system.


Also important re wind costs is the fact that a heavy dependence on it would have to involve off-shore turbines, and their cost can be c. twice that of on-shore farms.  This is assuming the present shallow water locations, recently 18 metres or less.  In addition there is the cost of getting the power ashore, which has been reported as capable of being equal to that of the turbines. (A.B.C. radio, 27, Feb., 2011.)


The limit to wind’s contribution -- about 25%?


The following analysis indicates that even in a good region wind probably can’t contribute more than about 25% of average demand.


Let us assume a system with an average demand of X GW and in which X GW of peak wind capacity has been built.  Taking the UK average wind system capacity, about .25 over a year, the wind system would generate on average about .25 X GW, leaving .75 X GW to be generated by coal or nuclear sources. (This is to simplify; other renewable sources could take some of the load.)  We would have cut coal use significantly but carbon release would remain far greater than safe greenhouse limits (below), and we would still need X GW of coal or nuclear capacity to call on when there was no wind.  Our electricity generation system’s capital cost would be X GW of coal/nuclear plus X GW of wind capacity.  We would have doubled system capital cost to cut greenhouse emissions by less than 25% (after wind system embodied costs etc. were subtracted.)


If we now consider having twice as much wind capacity, 2X GW, the wind system would generate on average about .5 of demand, but much of this could not be used because when winds were strong the  2X GW peak capacity wind system would be generating twice the X GW required.  Wind would therefore be contributing perhaps .3 or .4 of demand, still leaving an unacceptable level of coal use, while total system capital costs would be X GW of coal/nuclear plus 2X GW of wind.


It is evident from the graphs from Oswald et al. (), Coelingh (), and Davey and Coppin () that no matter how much wind capacity we added there would still be several times a month even in the best wind time of the year when more or less the whole X GW needed would have to come from coal or nuclear plant, and that we could cut carbon emissions to the very low required level only if we had perhaps 5X GW of wind capacity and dumped most of the energy it generated (or stored it very inefficiently as hydrogen.)  Clearly the gains from “over-sizing” the wind system would be savagely offset by the rise in total system capital costs.  In addition it would not pay to have much more than X GW (peak) of wind plant, meaning plant capable of delivering on average about .25 of demand (or whatever the average wind system capacity fell to in view of the need to use very large areas.)


The same logic would apply to other renewables and to their combination.  The situation is complicated somewhat by the capacity to store some energy in dams, although hydroelectric generating capacity is small, and by the capacity of solar thermal plant to store heat (below). 




The main problem with PV electricity is not its high cost but that it too is an intermittent source and its possible contribution to a wholly renewable energy system is therefore limited without the capacity for very large scale electricity storage. Even in the best regions PV provides no energy for up to 15 hours on a hot and clear summer day.  It is valuable when it can feed surpluses from house roofs etc., into a grid running on coal or nuclear power, while households draw power from that grid at night.  However this is possible only when much coal or nuclear capacity is functioning as a giant “battery” PV can send surpluses into, and there is obviously a relatively low limit to the size of such a PV system.


Very large scale use of PV systems would set difficult integration problems.  Output from the whole system would go from 0% to 100% of capacity in an hour or two on a summer morning.  At night another system possibly about as big as the PV system would be needed to substitute for it, as was seen above regarding wind systems.  The above discussion of wind energy indicates that the PV system would probably be limited to providing a small fraction of electricity demand, by the capital cost and energy dumping problems encountered if systems are over-sized.


Lenzen says PV could provide a higher fraction of electricity demand than PV, but without storage it could not be more than c. 30% as the even on a sunny day there is little sun for 15 hours. A realistic figure would be well below this percentage because about one-third of electricity demand occurs between c. and 5 p.m. so if PV was to meet one-third of total daily demand it would have to meet all demand within this period, meaning that all wind capacity would have to remain idle (or store inefficiently) and solar thermal farms would have to store all their daily output and generate from it at night.  That would not be good for turbine efficiency or life.  (This issue of integration, redundancy and dumping is discussed further below.)


Lenzen (2009, p.107) states that the energy pay back period for PV has been underestimated in the past.  The common assumption (e.g., via Alzema) has been that the energy used to produce a module is produced by one in c 3.5 years.  Lenzen et al. n(2006) finds that when all relevant factors are taken into account the ratio of input energy to energy produced is a surprising .33.  Lenzen and Taylor (2003) discuss the way energy ratio calculations often fail to take in sufficient “upstream” factors, such as the energy needed to produce the factory that produced the machinery that made the cells.  In the case of steel a full accounting can double the resulting embodied energy conclusion.


The discussion of life cycleem bodied energy costs of renewable energy technologies seems to be in an unsatisfactory state.  Not many studies seem to have been carried out, and it seems that almost none have taken “upstream” factors into account adequately.  One wonders what difference thorough analyses would make to the viability of renewables.




This is a summary of the 30+ page analysis of the limits

 of solar thermal systems, identified  below as TLSTE.


The major drawback for renewable energy is the inability to store electricity from intermittent sources.  However solar thermal technologies can store heat and use it to generate electricity when it is needed.  Some claim this capacity will enable renewable energy sources to meet all electricity needs. (E.g., Trieb, undated, Czisch, 2004.)  The importance of the issue could hardly be exaggerated.  If solar thermal systems are not able to overcome the gaps left by the intermittency of the other renewable energy sources, then it is not likely that renewable sources can sustain an energy-intensive society. 


Solar thermal systems are likely to be among the most significant renewable energy contributors.  However they are best suited to the hottest regions and it is not clear how effective they can be in winter, even in the most favourable locations, and there seems to have been no examination of the question. It is the focal question in this discussion.  At this point in time it does not seem possible to arrive at confident conclusions because solar thermal developers are not primarily concerned with this question, being mainly interested in maximising summer and annual output, and because commercial developers (understandably) rarely make publicly available the key data on performance.  (Heller, 2010, Blanco, 2010, Manci, 2010.)


Solar radiation data indicate that Central Australia is probably the best global location for solar thermal plant, somewhat better than the South Western US. (ASRDHB, 2008, Meteonorm, 2007, RREDC, undated, Odeh, Behmia and Morrison, 2003, Fig. 1, NASA, 2010.)  The NASA solar radiation data source gives the Central Australian mid-winter DNI as 26% better than both the SW US and Eastern Shara.  The source also points out that the figures are for are averages and the minimum values can be 10 – 15%^ lower.  The winter average used below for Central Australia is 5.7 kWh/m2/day. (ARDHB, 2006.)    Because various sources indicate that Central Australia has the highest winter value, the following discussion will focus on the Central Australian situation. If this is problematic then the prospects for winter supply to North Western Europe from North Africa and the Middle East would be less likely.




Performance in relation to alignment and radiation received.


Several sources show that the winter performance of troughs falls a long way below summer performance, to c. .4 - .14.  (Odeh, Behnia and Morrison (2003, Fig. 2.) show c .14 the SEGS site.) This is due to unavoidable geometry set by the difference between summer and winter angles between sun, reflecting surface and absorber.  In winter this angle is relatively large for much of the day (for E – W troughs) or all of the day (for the normal N - S layout).  N – S layout maximises annual output and E – W layout raises winter performance, but not to a high value.



            The threshold problem and the effect of low DNI on efficiency.


A critical problem for solar thermal systems is what proportion of collected heat is above the threshold level required for production of sufficient steam pressure to initiate generation?  When DNI is below 700 W/m2 there arises the possibility that  considerable heat could be collected but without generating much electricity.  In addition heat must be circulated in cold conditions to prevent the heat transfer salt from freezing, and this requires a significant quantity of energy.  Thus DNI figures can be misleading indicators of electricity output.  In favourable regions daily winter DNI totals appear to be good fractions of annual average totals, e.g., 5.7/7.5 for Central Australia, but this does not mean that the ratio for electricity generated would be as high, because much of that 5.7 kWh/m2 would be below the threshold level.


A number of sources provide clear evidence of a marked effect on the solar                                                                                                                                                                                                                                                                         to electricity efficiency of all three solar thermal technologies as DNI falls.  Figs. 1 and 2 from Odeh, Behnia and Morrison show that when DNI drops 45% (from summer to winter Alice Springs averages) heat collected drops 71%.  This means that at the winter 430 W/m2 the solar-to-heat collected efficiency is only 60% of that at the peak average DNI of 780 W/m2. 


The other evidence noted in TLSTE indicates that physical and geometrical factors determine that the low output from troughs in winter is not amenable to significant technical improvement.  As DNI falls both the amount of solar energy entering a trough and the efficiency of its conversion fall.  It is therefore important to keep in mind that a site’s generating potential is not well indicated by comparing its winter DNI with average or summer DNI.  Apart from the fact that trough technology is regarded as being relatively mature and marked technical advances are not likely, the foregoing discussion indicates that the low winter performance of troughs is due to geometry and cannot be significantly altered.


Finally, in view of estimated global gas resources, troughs are severely handicapped by their dependence on the use of gas to raise temperatures when solar radiation is low.  About 25% of the electricity delivered by the SEGS system is generated by gas (the maximum permitted by Californian law.)  In a renewable energy world with strict CO2 limits little gas will be used.  In any case little gas will be left late in this century.  The consequences of limited capacity to boost generation are likely to be greatest in winter.


Thus the evidence on performance and on trough geometry seems to show that troughs are not likely to be able to make a major contribution to electricity supply in winter.  Hayden reports average annual output from the 2.23 million square metre SEGS collection area as 77 MW, or 34 W/m2.  From the above summer/winter figures this suggests that winter output would be in the region of 12 W/m2.  A plant capable of supplying 1000 MW in winter would need 83 times the total SEGS collection area.




Lovegrove, Zawedsky and Coventry (2006) claim dishes are in general 50% more efficient than troughs or central receivers.  The advantages of dishes are firstly that they can be pointed directly at the sun all through the day and thus avoid the cosine problem which affects trough and central receiver or tower systems and are especially serious in winter.  Secondly the high concentration ratios enable much higher temperatures than troughs, which make possible efficient generation of electricity via Stirling engines at the focus of each dish.  Thus the losses involved in transferring hot fluids long distances to a generator are avoided.  It is therefore not surprising that their efficiencies have been reported or anticipated at The NASA solar radiation data source gives the Central Australian mid-winter DNI as 26% better than both the SW US and Eastern Sahara, two to three times those of troughs.  Dishes could therefore be expected to perform better than troughs in winter.  However they are considerably more expensive, in the region of $6,000 -10,000/kW in the early 2000s according to Mancini, et al, (2003).  Energylan, (undated) put the dollar costs at perhaps 4.5 times as high as troughs.  However this is partly because trough technology is more mature and dishes are closer to being “hand made” at present. Probable future costs are considered below.


A year long record of the daily output from a 115 square metre US dish-Stirling unit located at Phoenix Arizona (Davenport, 2008) shows that in January (winter) output was 68% of the annual average, which is better than for the typical trough.   A year long output record for the 40 square metre Mod 1 and 2 dish systems at good US sites (NREL, undated) shows that on average annual output corresponded to a continual 24 hour flow of 42 W/m2.  However in January the Mod 1 output corresponded to a continual flow of 18 W/m2, and 22 W/m2 in December, i.e., around 50% of average output.  This  reduction corresponds to evidence on other dish-Stirling systems (Davenport, undated.)   The figure is somewhat puzzling as it is lower than for central receivers and for the big Dish plus ammonia system (below.)


The Australian National University “Big Dish”.


The main non-Stirling dish initiative is the Australian National University 400 square metre “Big Dish”.  (Lovegrove, Zawedsky and Coventy, 2006.)  Its annual average solar to electricity efficiency has been estimated at just under14%, but it is anticipated that this can be raised to 19% in future. (Uncertainties surrounding this figure are considered below.).  However it is not clear what the winter performance would be.  It is an experimental device and has not been used to provide electricity to the grid over extended periods.  The 14% and 19% figures are stated as estimates of output under average annual insolation conditions and therefore solar-electricity efficiency in winter could be expected to be lower in view of the evidence discussed above regarding troughs, and below for dishes.


Heat storage via dishes.


The crucial point for the purposes of this discussion is that dish-Stirling systems do not involve storage of heat but if solar thermal systems are to overcome the intermittency problem set by wind and PV they must involve energy storage.  Thus high efficiency Stirling engines would not be used (unless storage is via hydrogen; below). 


The three main strategies open are, taking heat from dishes to a power block, dissociating ammonia at the focus of each dish and pumping this to the power block, and using dish-Stirling devices and storing via hydrogen.


The dish-steam/oil approach.


Because there seems to have been little development of dish systems designed for heat storage it has been difficult to get evidence on their potential performance. 

European (Davenport, 2008) and American (personal communications) dish engineers stress the significant difficulties dishes would suffer compared with troughs if the intention was to collect and store heat.  The higher the temperature the greater the loss at the absorber and in transfer to a distant power block, and dish absorber temperatures are around twice those of troughs.  In a large plant there would be considerable heat loss from long lengths of pipe taking heat from the dishes to the power block, or the need for substantial insulation, affecting dollar and embodied energy costs.  A trough system has to move heat much the same distance but this is mostly done via the absorber pipes which are heated almost all the way.


Long distance transfer of heat to a power block would involve a pumping energy cost and a loss through insolation, and the embodied energy cost of the insulated pipes and pumps, all of which are avoided in dish-Stirling systems. 


The little information available on this heat transfer and loss issue leaves it unsettled.   Kaneff (1991, Fig. 78) reports that at the White Cliffs 14 dish project when DNI was 700 W/m2 34% of heat energy absorbed was lost between absorber and the nearby engine.  At peak insolation it was 23%. (Table X, see also Figs. 78 and 79.)


In the estimations of the energy loss/efficiency cascades for large scale solar thermal systems given by Kaneff (including a 500 MW plant) and by Lovegrove, Zawadsky and Coventry, (including a 100 MW plant), there is no discussion of the fact that heat would have to be moved long distances, whereas for the Big Dish and the White Cliffs 14 dish project the generator was within a few metres of the dishes.  The distances involved in large scale systems would be great.  If a 1000 MW plant required 100,000 dishes (see below) then the piping connecting them all to the power block might total in the region of 4000 km, (not that a single solar power station this big would be optimal; the maximum practical size for Central Receiver systems is generally assumed to be 220 MW(p).) 


Advocates of dish-steam approach claim that as scale increases system efficiency increases significantly.  However a problem that does not seem to have been discussed is that as field size increase the heat pumping distance and loss problems increase.  The outer reflectors in the proposed S220 central receiver (which would not involve heat piping), likely to average 137 MW as distinct from 1000 MW, would be more than 2 km from the power tower (ZCA, 2010), and a field 7 times as big would  be needed to average 1000 MW. (…not that a single CR this size would be constructed.)


Thus the dilemma for large scale projects is evident.  Either benefit from the greater efficiency of larger generators but suffer losses getting the heat to them from very large fields of dishes, or reduce the transfer distances and losses but suffer the reduced efficiency of smaller generators placed within the field.


These considerations reinforce doubts regarding the viability of dish-steam/oil/salt systems for heat storage, and indicate that the .19 predicted solar-electricity efficiency figure given for the Big Dish and used in the following derivations is likely to be a significant overestimate when large scale systems are being considered.


The ammonia dissociation strategy.


The ANU solar thermal group has been experimenting with the use of the high temperature achieved by dishes to transform ammonia into nitrogen and hydrogen which can be stored via processes common in the fertilizer industry, and recombined later to release heat. (Lovegrove et al., 2004.)  The designers estimate that an energy efficiency of .7 might be achieved by the ammonia process, although this seems to be given as the upper end of a possible range under ideal conditions.  (Kaneff, 1992, p.143 states the efficiency at 6.)  It is estimated that some 52% of the solar energy entering the dish would be available after storage.  The important merits are that the energy resulting would be at 490 degrees, suitable for efficient electricity generation, and that dissociated ammonia could be stored at ambient temperature.  In other words there would be no heat loss or need for insulation between dish and generator. 


This approach seems to be the best in view of the (quite uncertain) output and cost figures available.  The numbers will be given  below.


            The effect of low DNI on dish solar-electricity efficiency.


There is evidence that as DNI falls the solar-electricity efficiency of dish-Stirling systems falls significantly, as was seen above to be the case with troughs, and this is a concern re probable winter performance.  The power curves for the 128 square metre Sundish and the SIAC/STM dish (Davenport, 2008) show that output at 700 W/m2 DNI is only about 50% of peak output, and solar to electricity efficiency falls to .71 of its value at peak insolation. Winter DNI at the best sites typically totals in the region of 5.7 kWh/m2/day but most of it is usually only a little over 700 W/m2, again meaning that dish output would be only around half peak output.


Little information on this possible effect for dish-steam or dish-ammonia systems is available.  However Kaneff’s report on the White Cliffs project (1991) indicates a marked reduction in heat arriving at the power block as DNI falls (i.e., greater than the proportionate reduction in DNI.)   Fig. 82 shows that as DNI fell 46% output fell 56%, again reflecting a decline in efficiency. 


Figures 3, 4, 10 and 11 from Siangsukone and Lovegrove (2003) show that the Big Dish exhibits a similar effect. 


It will be assumed below that this effect of reduced efficiency with reduced DNI applies to the dish-Ammonia process, although output and cost findings arrived at below are also considered on the assumption that there is no reduction effect.


To summarise the dish-ammonia strategy, the above figures indicate that if a) half the energy entering a dish becomes available for generating after the ammonia storage process, b) DNI is 5.7 kWH/m2/d, c) the efficiency of the turbine is .35 as Lovegrove predicts for the Big Dish, and d) reduced winter DNI reduces efficiency by 30%, then electricity would be generated corresponding to a 24 hour continuous flow of c. 29 W/m2.  Again this is a theoretically derived estimate and is probably much too high as it is some 50% higher than the output per square metre reported above for dish-Stirling systems, which are usually regarded as the most efficient solar thermal systems and involve no heat transfer problems and losses.  (The recent NREL Solar Adviser Model package (NREL, 2010) shows that a central receiver would also deliver about the same amount in winter.)


This output figure does not take in several of the 13 potential reducing factors discussed below.  Reference to two of these will be noted at this point. If only a 15% transmission loss and a10% winter start up delay loss are taken into account, then electricity delivered from a dish-ammonia system would be in the region of 22 W/m2, about 37% of annual average output without ammonia storage.  lf so, a plant big enough to deliver 1000 MW in winter from a site where average DNI was 5.7 kWh/m2/d, would need a 46 million square metre collection area.  This would equate to more than 110,000 Big Dishes, and at the future cost Lenzen (2009) reports as generally predicted the power station could cost $18 billion.


These numbers could be taken to indicate that the dish-ammonia system could deliver at a low but useful and acceptable average rate in winter, although at a high dollar cost. 


                                                Central receivers.


Because little or no evidence is publicly available on the performance of central receiver systems little space can be given to them in this discussion. (Only two plants are in commercial operation, in Spain, and the owners will not release performance information.  Helyer, Mancini, 2010.)  However some impressions regarding their likely performance and cost can be based on the figures given in Sargent and Lundy (2003) and by SANDIA/NREL, i.e., Radosevich, 1988, and more recently the NREL (2010) SAM package, the reviews by Hearps an McConnell, 2011, and the IPCC, 2011 Annex 111.


The anticipated long term future model is a (nominal) 220 MW peak system with a 280 m high tower and 2.65 million square metres of collection surface, set out over a 2+ km radius.  The anticipated average annual solar to electricity efficiency is .165 (although also given as .173 in some tables.)  This means that its 24 hour average output at a site where DNI is 7.5 kWh/m2/day would be 137 MW, 61% of the nominal peak rating.  (It is evident therefore that nominal ratings should not be taken too seriously.)


The recently published NREL Solar Advisor Model (NREL 2020) provides two examples stating that winter monthly output from a central receiver at a site (with 5/.2 kWh/m2/day radiation) would be 28 – 32 W/m2  .  When losses in log distance transmission are taken into account the delivered figure is more or less the same 27 W derived for the dish-ammonia system.  (Energy costs for embodied energy and dry cooling must be added; below.)


Factors further reducing solar thermal output.


Accounts and claims are often difficult to evaluate because it is not clear whether they take in all the factors that affect the output of a solar thermal system.  A full energy accounting would have to take into account the following factors which reduce the net energy that could be delivered.


a)  The embodied energy cost of plant.  The available evidence on this the life cycle embodied energy cost of solar thermal systems is unsettled and unsatisfactory.  There have been few analyses, different approaches make different assumptions, derivations are not transparent and they take into account different components, and they have arrived at a different figures. (See the detail in TLSTE.)


Dey and Lenzen (1999) report the embodied cost for trough systems at about 4% of lifetime output (25 year lifetimes are assumed.  The central receiver cost is reported as 8.5 – 10.7%, by Lenzen (1999, Table 3.)


A major issue is to do with the validity of these estimates in view of the fact that they take in only the energy costs of materials included in solar thermal plant.  Lenzen and Dey (2000, see also Lenzen and Treloar 2003) point out that such estimates do not take in “upstream” costs, such as the cost of constructing the factories and mines that produced the materials.   Lenzen et al. (2006) show that when the energy cost of  upstream factors is added to the energy inputs needed to produce materials the steel the energy cost of PV modules trebles the commonly accepted future. And pay- back period.  No approach to solar thermal plant along these “full accounting” lines seems to have been carried out.


b) The embodied energy cost of the ammonia heat storage system.  No firm evidence on this is available yet.  Note that it is possible that the storage pipe would have to be replaced several times in the 25 year plant lifetime, due to the effects of corrosive ammonia and the embrittlement of metals which hydrogen causes.  If the pipe had to be replaced each 8 years the lifetime embodied energy cost would treble.


Thus a full accounting could well show that the total embodied energy cost of a solar thermal dish-ammonia system is above 15% of lifetime output delivered at long distance. 


c)    Plant operating and management dollar and energy costs would have to be deducted from gross output.  Kreith and Goswani (2007) state these at 8% for a dish-steam system, but this is well below the 25-33% dollar cost stated by the IPCC (2011, Annex 111, p. 8.)  Presumably pumping ammonia from the many dishes to the turbine would require energy comparable to that needed to pump oil in trough systems.


d)   The embodied energy cost of the long transmission lines, transformers etc. also have to be taken into account along with their lifetime operations and management cost, e.g., vehicles, vessels for Mediterranean cable service, etc.  For Southern European supply from North Africa Czisch (2004) estimates the dollar cost for these lines at perhaps .3 of plant cost. One line can carry no more than about 5 GW, so several would be needed.   Thus lines to north Eastern Europe might add 50% to em bodied energy costs.


e)  Transients.”  When clouds pass over a dish it can take 5 or 10 minutes for output to rise to previous levels.  For trough systems this can reduce daily dish output an average 10%. (Sargent and Lundy, 2003.)   As has been noted, it is possible that a high daily DNI total could be made up of many short sunny periods separated by cloud, resulting in many warm up delays, and little or no generation of electricity. This factor has been estimated as costing 8% of output in the derivation of the .19 annual solar to electricity efficiency for the Big Dish.  However the winter value is likely to be considerably higher than the average and this has not been taken into account in the above derivation.  (See below on cloud occurrence in winter.)


f)  Down time for repairs would need to be accounted, although some of these could be carried out at night.  The modelling given for the Big Dish assumes down time will reduce output 6% (which has been assumed in deriving the .19 annual solar-electricity efficiency estimate.) 


g)  The start up delay is typically an hour on a summer day, representing an amount of solar energy that is not generating. 


h)   Storage loses some heat energy, although little from presently operating systems. Sargent and Lundy state this as .9% for troughs.  (2003, Table 4.3.l, see also Lovegrove, Zawadsky and Coventry, 2006.)  However this figure refers to the present c. 5 -7 hr storage and the need to store for periods between 16 hrs and several days, considered below, would increase losses.


i).  Turbine cooling. Solar thermal systems are most likely to be located in desert regions.  According to one estimate (Solar PACES, undated, 5-43) the turbines of the equivalent of a 1000 MW solar thermal plant would use 18.5 billion litres of water p.a.  In some situations sea water can be used but not in Central Australia, nor in North Africa because cloud occurrence increases with proximity to the sea.  Evaporative cooling is reported to cost around 10% of the energy generated by troughs, and takes 2.4 cubic metres of water per MW.   The figures are claimed to be lower for Central Receivers. (Solar PACES, undated.)  Air cooling is feasible, but at an energy penalty variously stated as 7 – 10% of output for troughs. (IEA, 2009 says 7%.)


j)  Loss in heat transfer, where relevant, e.g., not significant for central receivers. 


l)  Loss in long distance transmission.  For transmission via High Voltage DC lines from North Africa or the Middle East to Europe, or from the South West of the US to the North Eastern cities, a considerable loss of energy would occur.  Mackay (2008) and Czisch (2004) say this could be 15%.   Breyer and Knies (2009) concur, stating 3% per 1000 km.  However Ummel and Wheeler (2008) estimate 12% per 1000 km, plus .2% for the two substations required at the start and end of the line. 


The distance assumed isimportant; DESERTEC proposals are for relatively short distances, from North Africa to Italy, Greece, Spain for instance.   Transmission to the UK and North Western Europe might involve three times these distances.


Losses in local distribution, e.g., from substations to houses, might involve a 7% loss to ber adder to the long distance loss.


m)   Cooling  by the wind.  Kenaff (1991, Fig. 74a) reports that in 881 W/m2 DNI an

increase in wind speed from 2 to 4-5 m/s reduced energy absorbed by 9%.  Alpert and Kolb report that for a central received an increase in wind speed from 2 to 12 m/s reduces receiver efficiency 9.5% (Table 3 – 2, p. 27).  A 12 m/s wind doubles the heat loss from the absorber that occurs with no wind. (Table 3 – 4, p. 33.)  Note that the S220 central receiver absorber would be 280 m above ground level.


Dollar costs.


Evidence and claims regarding the likely long term future costs of solar thermal technologies vary considerably and estimates cannot be taken with confidence.  Conclusions are typically educated guesses and are not accompanied by numerical arguments providing derivations that can be verified.  Predictions also tend to assume cost “learning curves” observed in other (selected) engineering fields, but that term might best be confined to improvements in an established technology brought about by increased production scale, plant size, and technical advance, whereas dish and CR technologies (unlike troughs) might best be regarded as not yet established on a preferable path or at the anticipated scales. (Eg., central receivers in use are a small fraction of the 220 MW scale anticipated.)  Technologies that are in a pioneering and experimental phase often incur large cost overruns before the best strategies are established.   . 


A significant problem for those assuming cost reductions will occur is set by recent trends for wind turbines as these run sharply against the conventional wisdom.  In the Early 2000s the commonly stated cost was c. $1,500 per kW of capacity.  Wind might be regarded as a “mature” technology enjoying the “learning curve” benefits of a rapidly increasing production scale.  However in recent years turbine costs have risen not fallen, and ABARE reports the average cost or units built in Australia as a remarkable $2,900/kW, including a 30% increase in the last year. (ABARE, 2010.)  Jacobson and Delucci (2011) report a 37% increase in the cost of PV between 2002 and 2007.


In addition to these sources of uncertainty, the following evidence is that estimates of present and future costs vary considerably. 


Easily overlooked is the fact that all these cost figures refer to present materials, construction and energy costs, and in future materials and energy inputs are likely to be considerably more expensive than they are now.  Given the way all inputs into production involve energy it would not be possible to estimate the total effect on solar thermal plant cost that might be brought about by significant increase in energy costs.


Trough costs.


According to Sargent and Lundy (2003) the “near term future” cost of solar thermal trough systems is $(US)4,589/kW, or $(A)6,556 (taking the early 2000s exchange rate.)  This figure includes heat storage, which reduces required generator capacity and cost.  Their long term future (2020) cost prediction is $(US)3,220/kw.


However, NREL (2005) states that the 2003 cost for the SEGS systems is $(US)7,700/kW which would have corresponded to $(A)11,000/kW.  Viebahn, Kronshage and Trieb, state e5300/kW.  (20, Table 2 – 3, p. 12.)  They expect costs to halve by 2050. (Fig 3 – 7.)  However ABARE predicts only a 34% fall in solar thermal cost between 2015 and 2030.  EPRI (2009) actually reports a rise in solar thermal electricity cost from $175/MW to $225/MW, a 30% increase in the year to 2009.  It is noteworthy that a current cost estimate based on the recent NEEDS report (2008) estimate is in the region of $(A)17,000 per kW.  (Nicholson and Lang, 2010.)


A coal plant plus fuel (early 2000s price) over plant lifetime would cost approximately $(A)3,700 million, although more recently costs of electricity generating plant in general appear to have risen significantly.  The above solar thermal plant cost figures are for peak outputs but the average output from a coal plant is c. .8 of peak whereas for a solar thermal plant it is around .2 of peak capacity.  Thus taking the above coal power figure and the Sargent and Lundy estimate, the “near future” capital cost per gross kW delivered on average (as distinct from peak) from a solar thermal plant would be about 12 times as great as for coal including fuel, (so possibly 6 times as great now.) 


In addition solar thermal systems are typically located in deserts a long way from demand and the costs of long distance transmission lines should be added.  Transmission lines from the Sahara to Europe under the Mediterranean Sea would probably add one-third to plant cost, according to Czisch (2004). 


Lifetime operations and management costs must be added to capital costs.  The IPCC (2011,  Annex 111, p.8) puts these at  between 25% and 33% of capital costs.


            Dish costs.


Luzzi (2000) states that the cost of a Big Dish would be $440,000 but in future could fall to one-third of this figure.  Lenzen’s review (2009, Fig. 8.3.4, p. 119) indicates that the estimated future cost is around 37% of the present figure, i.e., $163,000. ($3,156/kW peak.)  When the  2003 exchange rate and subsequent inflation are taken into account this figure corresponds to $(A2010) 240,000.  The average between this and the Luzzi figure is $228,000.   The peak output from a Big Dish at .19 efficiency, would be 76 kW, but the peak output via ammonia storage would be 53 kW.  Therefore the capital cost per peak kW delivered via ammonia would be $4,528, and if we assume that the daytime half of total output would not involve ammonia storage, the final indicator of the capital cost of a Big Dish plus ammonia plant would be $3,7664/kw(p).


Note that this cost is just for the dish plus ammonia reactor and storage pipe, and does not include the power block components.. 


Central receiver costs.


Unfortunately the probable central receive future cost situation is not at all clear. Sargent and Lundy (2003) expect the present figure they state of around $9,090/kW for central receivers to fall to $3,220 by 2020.  When converted to $A2010 this is S4,600 and when inflation is added the figure becomes $6,072. 


The NREL SAM package (2010) provide (theoretically modelled, not actually performing) examples of central receivers at c. $(US2010)6,700/peak kW, suggesting that if they had included an estimate of future cost it would have been below that from Sargent and Lundy.


 Aringhoff (2004, reported in Lenzen, 2009, Fig. 8.3.4.) expects costs to fall to c. 38% of the present cost. Viebahn, Kronshage and Trieb (2004) state e10,140 at present.  Jacobson and Delucci (2011) quote an IEA estimate of $(US)3,082/kW(p) for 2030 costs, a 38% fall from the present cost.


The best estimates of future costs would seem to be from the reviews by Hearps and McConnell and IPCC 2011 Annex 111 reviews, which include IEA estimates.  Their figures for present central receiver systems are closer to those in the NREL 010 SAM package.  The costs of overseas PV and solar thermal systems are loosely expected to fall by 50% by 2030 – 2050, but Australian solar thermal costs are only expected to fall about 33% (presumably due to distance from suppliers and consultants, etc.)   The only estimate for Australian costs is from AEMO and is $4,166/kW. 


Although the evidence is scarce it is somewhat reassuring that there is some consistency among these figures.  It would seem that the central receiver cost would be better than the Big Dish ammonia cost.  The two expectations are about the same but only because Luzzi assumes a 2/3 fall, which is twice the AEMO expectation and greater than the other estimates considered in Hearps and McConnell and the IPCC, (i.e., c 50% falls.).


                        The intermittency problem for solar thermal.


As has been noted the significant merit of solar thermal technologies is their capacity to store energy as heat and therefore to be able to generate when there is no sunshine.  The intent in current designs is to build in c. 12 - 16 hour storage to enable 24 hour operation.  This sets two questions, firstly whether storage capacity can enable constant supply from a solar thermal plant despite the intermittency of solar radiation, and secondly whether this capacity can enable solar thermal systems to overcome the gaps left in renewable energy supply by the variability of wind, sun and seasons.  In other words, can they provide the very large scale heat storage that a totally renewable supply system would need in order to maintain electricity supply for several calm and cloudy days in a row?


Focusing on mean DNI levels as in the above discussion can be misleading.  What matters is variation in DNI about the mean, and therefore the minimum levels that will occur, not the average levels.  For instance at the best Australian sites winter DNI averages around 5.7 kWh/m2/d but in particular months it can be 40% below this. (See ASRDHB 2006, RREDC undated, Kaneff and Hagen 1991.) A solar thermal system intended to guarantee constant supply would have to be big enough to cope with the periods of minimum DNI, just as a conventional power system has to be capable of meeting periods of peak demand.  For conventional coal/nuclear systems this typically requires construction of up to 50% more plant than would meet average demand.   For solar thermal systems this would require corresponding increase in storage provision. 


In other words despite their capacity to store energy solar thermal systems also have to deal with significant problems of intermittency and integration and these are obscured if DNI averages are attended to. 


The evidence detailed in TLSTE on the variability of solar radiation in winter at ideal sites shows that the problem of intermittency for solar thermal systems is likely to be significant.  Particularly problematic is the occurrence of several days in a row of cloud.  For instance at the Daggett US Dish site (Davenport, 2008) the sequences of consecutive days of low output were as follows; December one run of 2 days, and another of 5 days, January a run of 4 days and another of 5 days, separated by 2 days, February a 4 day run in which there was a total of only 4 hours over 700 W/m2.  Over a 19 day period at the Mod 2 dish-Stirling site there was output on only 2 days, totalling 25 kWh, less than 2% of the level that peak output would have been for that period.


Australian climate data aligns with the above data from the U.S.  At Alice Springs each of the three winter months averages 5 to 8 “cloudy” days and only 17.1 “clear” days. (Bureau of Meteorology website.)  NASA radiation data shows 21% cloud cover for central Australia in July.  Kaneff (1991, table XV-A) reports the following runs of “completely cloudy” days for three of the years in the 1980s when the White Cliffs (Central Australia) project was under way (each figures stands for the number of days in the month).  Year one, 7, 17,10.  Year two, 6, 11, 13, 8, 9, 11, 7.  Year three, 7, 10, 7, 11, 6, 7.  In other words in every one of 7 months in one year at least 6 of the days were completely cloudy, and in all years there were at least two periods when there was complete cloud for one-third or more of the month.  In two of the years there was no sun for about half the three winter months.  NASA climate data for North Africa similarly indicate considerable cloud cover in winter.  In may Algeria has cloud 37% of the time To put it mildly, sequences like these would set a formidable challenge for any expectation that solar thermal storage capacity could overcome variability problems.  .


As has been explained these figures for days on which DNI is low will probably be misleadingly high indicators of electricity generation on those days, because much of the radiation will have been at levels too low for generation, or will have accumulated in several short periods between cloud.  In the latter case the warm up delays could conceivably determine that little or no electricity is generated during a day when clouds come and go.


To summarise, despite their storage capacity there remains a significant problem of intermittency and solar thermal systems suffer a kind of “peak supply” problem similar to that experienced with coal-fired plant; i.e., the need to build a large amount of generating or storing capacity that will only be drawn on rarely.  This means that the estimation of total system costs must not be based on the cost of the number of solar thermal plants corresponding to average demand but on the number of plants and the amount of storage needed to meet demand from storage through periods when radiation is minimal.


This is why “levelised cost” calculations can be misleading.  They indicate the amount of plant needed to meet demand under average generating conditions, whereas the amount actually needed is that which will meet demand under the least favourable conditions.


Some solar thermal systems currently operating have the capacity to store for up to 7.5 hours.  The standard provision in future is expected to be 17 hour storage and this is being built into some systems under construction.  However the above radiation data sources show that runs of four days in a row with little or no sunshine are not uncommon in Central Australia.   NASA says that medical stand alone solar energy supply systems assume a need to cope with 6 consecutive “black days.” 


If electricity from a 1000 MW(e) solar thermal plant was to be despatched from stored heat for 4 cloudy days, some 350,000 MWh of heat would have to be stored and storage capacity would have to be 13 times that built into plants presently operating.  Sargent and Lundy (200, 4 – 11) expect that storage capacity in 2020 will have fallen by 60% of the present cost to be $11.7/kWh(th), and 23% of plant cost.  The first figure indicates that sufficient storage to provide four days output at 1000 MW would cost twice as much as a 1000 MW coal fired plant. 


Heat losses from the present 5 -7.5 hr storage systems are low, around 1% per day, but if 13 times the amount of heat must be stored for 13 times as long losses would be much greater.  (However the surface/volume ratio of tanks decreases with volume, and storing via ammonia would not involve significant heat losses.) 


Solar thermal conclusions.


The (rather unsatisfactory) evidence accessed suggests that although solar thermal systems will be valuable contributors they will not be able to make a large contribution in winter, let alone to solve the problem set by the variability of other renewable sources.


The best option would seem to be central receivers.  The performance of dishes storing heat via ammonia is not known yet, but the above estimate is that output could be similar to that of central receivers.  Cost would probably be higher though.  The winter rate of electricity production seems to be in the region of 30 W/m2.   However when embodied energy cost, transmission losses and dry cooling energy costs are taken into account the rate of delivery in winter seems to fall to c. 20 W/m2.  Adding the other factors noted above could take it well below this figure.  


The present cost of the systems described in the NREL 2010 SAM package is  $658 per square metre of plant.  At 20 W/m2, we would need 50 million square metres of collectors to generate and deliver a constant 1000 MW.  This system would cost $33 billion...which is about 16 times the cost of a coal-fired station capable of the same performance.


The future overseas cost for average annual supply (not winter as immediately above) would probably be a multiple of 6-7.




World hydro potential could probably double the present contribution, to 19 EJ/y.  Small scale sources might add to one-eight of this.  (Lenzen, 2009, c. p. 74.)  The greenhouse problem will affect hydro potential.  In recent years the Australian hydro contribution has fallen from 10% to 6% of electricity supply.




Large quantities of energy exist as heat in dry rock masses and it is possible to tap these by pumping water down one bore hole and up another. A 1994 study for the Australian Government’s Energy Research and Development Corporation concluded that Australia is probably the only country with extensive hot dry rock resources. (  Jacobson and Delncci (2011), keen enthusiasts re the possibility of running the world on renewables, say geothermal will only contribute 4%.  The same figure is given by the WWF Energy Report.(?to check?)


Much energy will have to be used to drill the holes some 4,000 to 5,000 metres deep, fracture the rock and force water 500 to 1000 metres from one hole to the other.   Most heat is in rock of low permeability. (Lenzen, 2009, p. 124.)  When the water comes up it will only be around 270 degrees C in Australia meaning rather low generating efficiency. The US has no resources over 200 degrees C, and the European average is likely to be c. 170 degrees.  (Moriarty and Honery, International Journal of Hydrogen Energy, p. 35.) Uncertainties include the energy needed to fracture the rock between holes to enable water to be pumped from one to the other, the amount of water lost in the rock cracks, and whether the path the water takes is straight and therefore “mines” little of the rock volume.  Lenzen’s review states that the resource is likely to have  been depleted in the plant’s lifetime.  In other words embodied energy cost, net energy return and generating efficiency are largely unknown at this stage, and are problematic.   The IEA estimates global capacity at 2.4 J/y. (Moriarty and Honery, IJHE, p. 36.)  Water availability will be a problem in Australia as the main resource is in the desert.  Air cooling is possible but lowers efficiency.  Also uncertain is the effect of high ambient temperature on generating efficiency.  Scheirmeir et al. (2008) say the global potential is probably in the region of 70 GW.  A world of 9 billion living as Australian’s expect to by 2050 would need some 15,000 GW of electrical generating capacity.


The main experimental project in Australia, undertaken by Geodynamics, was abandoned in 2011 due to technical difficulties fracturing rock, writing of $350 million.  The only power station in Australia is at Birdsville.  The temperature is only 98 degerees C, and efficiency of generation is 6%. (Kimble, 2011.)





Despite many years of experimentation no commercial wave power plant had been put into operation before 2004.   The main problems are to do with storm damage.


According to a source within the industry (personal communication) there are 16,000 km of coast around the world with excellent wave energies, i.e., 30 kW/m, and three times as much energy again if sites down to 20 kW/m are used.  Industry sources believe 40% efficiency can be achieved, meaning output of 12 kW/m at the best sites.  If 10% of these ideal sites could be used and 40% efficiency achieved, output would be equivalent to 18 power stations.  The equivalent of a 1000 MW power station would have to be 80 km long.  Hayden (2004, p. 210) derives a130 km length from another experimental project assuming 25% efficiency.  Mackay says a wave power system providing 4% of UK lenergy would need to pontoons etc along 500 km of Atlantic coast.


Adding the estimate for 20 kW/m coasts suggests a total potential roughly equal to 76 power stations.  This would be a welcome contribution, but industry sources consulted do not think wave power will exceed 5 – 10% of world demand.  This roughly aligns with the estimates for wave and tide potential given by Scheirmeier et al, 2008.  World electricity supply at rich world rates of consumption for the present total world population would equate to roughly 9,000 power stations.  (Transport will have to be mostly electrical in future, multiplying the electricity supply task by about 3; below.)


                                                OCEAN CURENTS.


Some places are capable of generating considerable electricity from turbines set on the bottom of the ocean where there are fast flowing currents, but the global total harvestable does not appear to be great.  Hostile and corrosive environments raise costs.  Mackay(?) estimates global potentialar 450 GW.




Might the geo-sequestration of carbon dioxide from coal use (also referred to as Carbon Capture and Storage, CCS) enable sufficient coal use to plug the gaps left by renewables?  First let us consider dealing with the possible 1100 EJ 2050 world energy supply without exceeding the IPCC (2007) emission limits.  For an atmospheric limit of 450 ppm the IPCC said that 2050 CO2 emissions must be cut by 50 – 80%, i.e., to 5.7 to 13 GT/y. This corresponds to 1.4 – 3.6 GT/y of carbon and 1.98 – 5.1 GT/y of coal.    (Coal will be the only fossil fuel available in significant quantity after 2050.)


Geosequestration can only be applied to stationary sources (so not to vehicles).  Only about 50% of emissions p.a. come from stationary sources, i.e., at the power station. The IPCC says it is only possible to extract 80 - 90% of carbon dioxide from stationary sources. Hazledyne (2009) says that when all sources are included, such as the fugitive emissions from coal mining, the figure is 75%. Barry (2008) says only 71 - 79%.


But what is a safe emission limit?


It is very likely that in the near future it will be generally agreed that the IPCC’s 2007 emission limits are much too high.  That analysis did not take into account the many powerful feedback effects in the greenhouse problem, for example the warming is accelerated by methane from the drying tundra, the acidification of the oceans, the decrease in snow and ice cover as glaciers and polar ice diminish.  These factors were not sufficiently well understood to be included as consensus statements in 2007.  In the two years since the report the observed warming effects have been much greater than was expected.  All trends are tracking above the highest estimates the IPCC made.  Hansen argues that the global atmospheric concentration target should be 350 ppm, although it is already 380 ppm, and a “350 Movement” has emerged.


A recent article in Nature by Meinhausen et al. (2009) finds that to keep the probability of exceeding a 2 degree temperature rise below 25% emissions must be cut from their present level to zero  by 2050. (This is my interpretation of their statement that the limit is 1000 Gt/y and the present annual emission is c. 40 GT.) Yet they state that in the 2000s emissions have increased rapidly.


It is therefore very likely that soon there will be general agreement that all emissions must be eliminated by 2050.  This means that if geosequestration cannot eliminate 100% of emissions generated then it cannot be used at all, unless some way of taking vast amounts of carbon out of the atmosphere is found.)


There is also uncertainty regarding recoverable coal quantities.  There could be 15,000 billion tonnes in the crust but the recoverable quantity is generally assumed to be c.1000 billion tonnes.  (Some sources state four times as much, without clarifying the plausibility of recovery.  Mackay says 1.6 billion tonnes.)  The Energy Watch Group (2007) believes the recoverable quantity might be in the region of 500 billion tonnes, and supply might peak within two decades.


These uncertain ranges complicate the scene.  Table 2 sets out the approximate values for a) the amount of electricity that could be generated, b) the amount of coal that can be used, and c) the life of coal resources assuming 1000 billion tonnes recoverable, in relation to a CCS rate of 80%, 85% or 90% of CO2e generated and a safe emission rate of 5.7, 9.35 or 13 GT/y of CO2e.


Table 2.


Emissions (a), coal use (b) and coal life (c), for different CCS capture rate, and safe emission assumptions.


                                   CO2 capture rate.


                                                 80%                         85%                      90%







           5.7GT/y           (a)        86 EJ/y                       129 EJ/y              172 EJ/y

                                   (b)       9.8 GT/y                     14.6 GT/y            20 GT/y             

                                   (c)       104 y                          79 y                     52 y


            9.35GT/y        (a)       154 EJ/y                      230 EJ/y             308 EJ/y

                                   (b)       17 GT/y                       24 GT/y              30 GT/y

                                   (c)        59 y                             45 y                    32 y


            13 GT/y          (a)        223 EJ/y                     335 EJ/y             446 EJ/y

                                   (b)        25 GT/y                      35  GT/y             50 GT/y

                                   (c)        40 y                            30 y                    19 y




The table indicates that if it was safe to release 9.35 GT/y of CO2, the IPCC 2007 mid range figure for 2050, and if CCS could capture 90% of emissions, then CCS could provide 9 billion people with a little less than the present Australian per capita electricity consumption.  At that rate coal would only last about 32 years.  


Note that the coal life times given do not take into account the amount that would have been burned between now and 2050. For instance if we increase coal use from the present c. 7 GT/y to 20 GT/y by 2050 then by 2050 we will already have used up 57% of the estimated recoverable amount, and the life time for coal after 2050 would be 20 years.


It should be stressed that these estimates do not take into account the energy needed to build the geosequestration plant and operate the process, including pumping liquid CO2 long distances.  In addition the system operating energy must be deducted, and this has been estimated at 10 – 40% of energy produced by the coal generating the CO2.  (Lenzen, 2009, p. 28.  Barry, 2008 states 30%.)


Another typically ignored issue is the amount of carbon that has to be released in the reduction of metal oxides in order to produce pure metals.  For instance to produce 108 tonnes of aluminium 12 tonnes of carbon electrodes are consumed.  ( Kimble, 2011.)


The next problem concerns the availability for storage sites. The Australian east coast has few possible storage sites close to generation sites (although depleted off shore oil fields might be viable.)  It is not likely that storage of very large quantities of CO2 in the deep ocean would be regarded as acceptable, given that the ecological effects would be uncertain, the CO2 would return to the surface in time, and global warming will decrease the ocean’s capacity to absorb CO2 and will make ocean currents less predictable. Hendricks, Graus and Van Bergen (2004) say that the best estimate of the land storage capacity is 1700 GT. (The highly speculative upper limit given is 6 times as great.)   There are also concerns about the probability that sites will leak. (Lenzen, 2009, p. 28.)


Smil points to the huge volumes that would have to be dealt with.  If half the US emissions were compressed to 1000psi the volume would equal twice that of all the oil produced p.a. in the world.  Where do  you put that, at what cost?


The IPCC’s medium 2050 permissible emission rate of 9.35 GT/y, along with the assumption that 10 times as much can be generated and 90% of this captured, would mean that 81 GT/y would have to be sequestered.  At this rate global land storage capacity might last no more than 20 years.  Similarly, using coal at the corresponding rate of 30 billion tonnes p.a. would exhaust coal resources in perhaps 3 decades.


However all of the above discussion now seems to be more or less irrelevant, because atmospheric warming effects observed in the last two years or so are occurring much faster than the IPCC expected so a satisfactory target will surely be under the 450 ppm figure underlying the foregoing estimates.  As has been noted, it is increasingly accepted that we must almost completely eliminate emissions this century, and possibly before 2050. (Hansen, 2008, Climate Action Summit, 2008, and especially Meinshausen, et al., 2008.)




The intermittent nature of most renewable electricity sources would not be a problem if electricity could be stored in very large quantities.  However this is not possible and although potentially valuable technologies are being researched at present there would not seem to be good grounds for expecting this problem to be solved.  The very large scale of the problem needs to be kept in mind.  Calm conditions can apply across most of a continent for several days in a row in winter.  If most of Europe’s electricity demand for say four days was to come from stored wind or solar energy then in the order of 50,000 GWh would have to be stored, not taking into account losses in storage.  For illustrative purposes, to store this quantity of energy in lead acid batteries would require around 2 billion tonnes of lead some 600 times annual world production (taking into account the fact that lead acid batteries should not be more than 20% discharged, and assuming 90 KJ/kg; Sorenson, 2003.)


Following are brief comments on what seem to be the most promising storage options at present, and their limits.


Pumped water storage.


The gaps left by intermittent sources can be filled to some extent by electricity generated by water that has been pumped up into dams.  The energy efficiency of the process might be .7.  However the capacity compared with demand is limited.  World hydro-electric generation meets only about 15% of electricity demand, and the 10.7 EJ is not likely to be doubled.   Hydro electricity has been c. 9% of supply in Australia but seems to be heading for 5% in recent dry years.  It can provide 18% of demand for a period in Australia.  Mackay (2008, p. 232) reports European capacity at 67 GW, which is remarkably small for a hilly and wet region.


However this is misleading because it refers to water released in a once-through flow from the high dam, whereas pumped up storage is not possible unless there is also a low dam close by to hold the large volume of water to be pumped.  So the actual amount of hydro capacity is not a good guide to pumped storage potential; what matters is how many dams have or could be given adequate low dam capacity.  The sea can be used as the low “dam” but this sets problems to do with seepage of salt into the ground at the high dam sites.  This is why a proposal in South Australia was abandoned.


Mackay’s analysis of UK potential capacity shows that it is only a small fraction of what would be needed.  The UK does not have high mountains but it does have high rainfall.


A major problem seems to be the inability to predict whether we will need empty high dams to store surplus energy from a coming surge in wind for instance, or full high dams to enable generation through a coming lull in wind energy.  There is also the need to keep dams somewhat empty to enable mitigation of floods, in an era in which the frequency of extreme weather events is likely to increase.  (The severity of the 2011  Brisbane floods was attributed to the need to release water from the Wyvenhoe dam. The subsequent inquiry ruled that it should be kept at 785% of capacity.)  These would not be such serious problems if very large storage was available and could be kept half full, but there is little capacity that big. 


Smil points out that stop/start generation sets problems regarding high volume water flows over long distances. Getting large volumes moving uses energy, lowering overall efficiency.


Lang (2010) explored the feasibility of tunnelling 50+ km between two dams in the Australian Snowy Mountains scheme and found that the venture would be too expensive.  It would only generate 9 GW for 3 hours, but Australian consumption is c. 30 GW.  Tumut 3 dam, the largest available in the Snowy region, only generates 1.5 G



The greenhouse problem is likely to reduce hydro capacity in future.


The vanadium battery.


Electrical energy can be stored using vanadium solutions.  An 800kWh system is in use on King Island in Bass Straight, Australia.  (Skylass-Kazacos, n.d.)  However the energy density is quite low and for very large scale storage the materials, energy and dollar costs would be very high.  About 70 litres are needed to store 1 kWh. (Personal communication, Cougar energy; see also   Petrol is about 850 times as energy-dense.


For a PV power station to store energy equivalent to that which a coal-fired station would provide for the 16 hours when the sun is not shining, i.e., 16 million kWh, 1,120 million litres would be needed.  This would require 53 tanks of 30 metres diameter and 30 metres high.  A renewable energy system would need the capacity to store for many days.


The cost of the 800 kWh King Island system is very high, $4 million, although if mass produced cost per kWh would be much lower.  If we assume half of this for the storage part of the system, i.e., $2,500 per kWh, then the cost of the 16 hour storage task for a 1000 MW power station would be $40 billion, and for a four day storage task would be  $240 billion…when a $1.2 billion coal-fired plant would do the same job (or $3.7 billion including coal fuel for its lifetime.)


Then there is the cost of the bulky “engine” to produce electricity from the stored solution.  According to figures from Cougar Energy, a 1000 MW power station would probably require about 30,000 tonnes of materials.


These numbers are uncertain and costs are likely to fall considerably with development, but it would appear that the extreme dollar and embodied energy costs would prohibit very large scale use of this technology.


            Compressed Air storage.


Storage of energy by compressing air is claimed by some to be between 40% and 70% efficient, but Mackay states a surprising 18% (which I have not been able to confirm via personal communication; it might refer to systems not using added heat at the expansion/regeneration stage; see below.) 


Easily overlooked is the fact that we would have to pay the capital cost of at three (probably two; below) generating systems.  The first would be the windmills creating the electrical energy, the second would be the equally big system of compressors converting the electrical energy into compressed air, and the third would be equally big system of turbines converting the compressed air back into electricity.  However it is likely that the compressing turbines can be reversed to do the regenerating, meaning that we would only need to build twice the plant.  In other words, for each 1000 MW wind power station providing the energy to be stored we would have to build another capable of generating 660 MW at night from compressed air. That more or less doubles capital costs to deliver perhaps 40 – 70% of energy initially harvested, suggesting an overall reduction factor of 4 for capital cost per unit of energy delivered.  (The multiple would be less if the regenerating turbines cost less than windmills, as is probably the case.)


Fthenakis says the cost of CAES is half that of lead-acid battery storage.  If so it would seem to be prohibitively high for very large scale use.


Very large storage volumes would be required to store significant quantities of energy.  According to Fthenakis (2009) there is sufficient storage space in the US, especially in the form of old gas fields.  Most other countries would have less of these.  Sorensen (2000) says 15 MJ can be stored per cubic metre, i.e., 4.16 kWh.   If this is so, then to deliver 10,560 MWh to meet night time demand from a 1000 MW plant via a 0.5 efficient system (i.e., storing 21,120 million kWh) would require a storage volume of approximately 5,068 million cubic metres, i.e., a 3mx3m mine shaft approximately 563 km long (or 1,564 km long if Mackay’s efficiency figure is valid.)  In many countries there would probably be too few caverns or old mines large enough for this form of storage to enable bulk electricity supply via intermittent sources.  In many countries there would probably be too few caverns or old mines large enough for this form of storage to enable bulk electricity supply via intermittent sources. Mills claims excavation in rock is economically feasible for heat storage in water, but it would seem to be much less so for the much larger volumes required for compressed air storage.


The main storage task however is coping with several calm and cloudy days in a row, as distinct from 16 hours night time after a normally sunny day.   Providing a four day capacity would set a task more than 6 times as big as the 16 hour problem discussed above.


The biggest problem would seem to be the fact that high efficiency requires the addition of heat via gas burning at the regeneration stage.  In a wholly renewable energy world this will not be possible.  Solar heat could be used, but this would mean solar plant would have to be added to collect energy in the form of heat equivalent to a large fraction of the energy collected by wind, and the plant to store it would also have to be built.  Heat availability would be at its lowest in winter when wind energy for storage was at its highest.


There would therefore seem to be very high capital costs, given that the task of generating the initial electricity would be as great as that of compressing the air so compressor plant would more or less equal the amount of wind turbines.  Then there would be a cost for the digging or preparing the caverns, the plant to handle the gas for heating, and the cost of turbines to turn the compressed air back into electricity.  However the compressing turbines might be reversed for this. 




Within the above discussion of solar thermal reference has been made to the possibility of storing large quantities of heat via chemical reactions such as the dissociation of ammonia.  This would seem to be quite promising for solar thermal systems.  However it would seem to involve very high plant embodied energy costs for heavy pressure containers, for 12 hour storage, let alone 4 day storage.   It is also argued in Trainer 2008 that solar thermal’s energy storage capacity could not overcome the much greater combined gap problem set by all renewables in a system.


Use the batteries of electric vehicles?


It is sometimes claimed that if we had a large number of electric vehicles then their batteries could be used to organise large scale storage of electricity, by plugging into the mains for several hours a day.  This seems to be quite problematic.  The car would need a fully-charged battery when it is to be used so its battery could only be of use for other purposes if it could be plugged in when low, charged up and then run down powering the general electricity system and recharged fully again, all before the car was needed again.  At present it can take 7 hours to recharge fully so it is difficult to see how the battery could be available for long for general system storage contribution.


Many car users could not predict when they were likely to want to use the car.  Most probably would not want to use it unexpectedly at night, but electricity demand falls markedly at night so there would not be that much need for storage then. It is not likely that this could be organised effectively, that is making sure that each of the millions of cars in a system stored and delivered energy and then was fully recharged when it was to be used.  Even if car users could set the time when they intended to drive again, the “smart charging” system would have to organise charging, storage, use, and recharging by that time.  Would there be a need for storage in that period?  Storage would be most needed on a cloudy or calm day and how could this be provided for in advance?  It would seem therefore that although there is potential storage capacity here, the quantity could not be well estimated just by knowing how much car battery capacity existed. 


The capital cost of a system would have to include the cost of a separate battery charger for every vehicle, or parking lot, so that mains voltage can be transformed to c.12.4 volts.


The best battery option at present seems to be Lithium-ion.  Other types of battery are possible, but there is limited Lithium availability.  Mackay reports world reserves as 9.5 million tonnes, and says 6 kg are needed for one car.  This would enable 1.6 billion cars, compared with the c. 1 billion in use now.  This quantity would store power from 2000+ solar power stations for 16 hours a day, when a world of 9 billion people living as Australians are likely to in 2050 under BAU would require perhaps 10,000.  Lithium will also be required if DT fusion is got to work.


Smil says Lithium batteries deteriorate in the field quickly and have to be replaced in 2 – 3 years, (200, p. 29.)  He says a set for a car costs a remarkable $35,000.  Jacobson and Delucci estimate future cost at $(US2011)7,980 -17,310, assuming recycling of Lithium, and believe that in future a set will last 15 years.  High ambient temperatures worsen performance and life.  It would be important to have estimates of the embodied energy cost of Lithium-ion batteries. 


Lenzen (2009) concludes that not much excess wind energy cannot be taken up by car batteries.  The problem of 7 hour charging time could be eliminated by having batteries removable and replaced by new ones at “refuelling” stations.  However this would double the quantity of batteries required for the fleet, with significant effects on life cycle energy costs, and the availability of materials.


If exchangeable battery technology is adopted, whereby low batteries are rapidly  replaced by charged batteries, the above delay problem would be much reduced, but the total mass of battery material would have to be doubled, with implications for cost, embodied energy and materials scarcity.


Lenzen’s review reports that wind can’t supply me than about 20 – 25% of electricity demand because of its intermittent nature.  It would seem that the same limit would apply to vehicles if they are run on electricity, i.e., that these would be just like other appliances people want to use (charge up) at a point in time.  In other words the 25% limit would apply to the total of direct plus transport electricity.


There is also a concern re the quantity of energy that could be stored relative to demand.   If for example, half the c. 30 GW output from Australian power stations was to be stored in our 2.5 million vehicle batteries, i.e., 30 x 12 GWh/day, each would have to have enough battery capacity to store 30 kWh.


Finally there is the economic situation the car owner is in.  He pays 13c/kWh now for the electricity to put into his battery, but is he to be paid the same as suppliers such as power stations,  4 c kWh, when he provides electricity to the grid from his battery?  If he is to be paid 13c/kWh then society is subsidising him x3 the base price.  You’d probably have to offer him much more to be in the scheme, given that by using his (very expensive) battery you are shortening its life.




New kinds of batteries are being developed for wind power,  but at this stage seem to be 10 – 30 MW scale.  Exetec says it is aiming at a cost of $(US)500 per  kWh.  This would seem to be far too high.  It is around half the cost of batteries for solar home lighting systems today.  To store the 16,000 MWh from a 1000 MW PV power station for night time supply would cost $8 billion, some 4 times the cost of a coal-fired 1000 MW plant.




Advocates of renewable energy often fail to take into account the fact that energy is needed in particular forms and this sets the problem of converting it from other forms and the problem of the associated losses.  (Stern’s Fig. 9.4. fails to deal with this issue.)  This is most obvious with respect to transport. If biomass is used to produce ethanol about 2/3 of the primary energy is lost, and if coal is used to produce liquids the energy efficiency is around .6.  More significantly, if electricity is to provide liquid fuel for transport in the form of hydrogen, four times as much electrical energy has to be generated compared with the amount of energy to go through the wheels of vehicles.  (Bossell, 2004.)


If we assume that Australia’s transport fleet operates at 40% efficiency (petrol to wheels) then some 500 PJ would be needed at the wheels of vehicles (ignoring the fact that electricity cannot power air or sea transport.)  To provide this via the hydrogen path would require generation of 2 EJ and when this is combined with the .7 EJ of direct electricity demand, 4 times Australia’s present electricity generation would have to be produced. 


The general efficiency involved when electrical energy is stored as hydrogen and then used via a fuel cell is likely to be around .2.  This is evident if we assume .65 for hydrogen production (the present commercial level, but it might be improved), .8 for hydrogen storage, pumping/piping and distribution, and .5 for fuel cells (more  like .4 now). Note that even if cars are run on electricity about 45% of total energy use would be non electrical, and when low temperature heat and biomass, nuclear and hydro contributions are subtracted there remains a lot of energy that would have to be converted from electricity in a renewable energy world.


Thus the quantities of renewable energy required when conversion losses involved in providing needed energy forms are taken into account will be much greater than it might appear if the various amounts of “service” or “final” energy, (e.g, transport) are simply added.  Note also that transport energy accounts for only about half Australia’s total oil plus gas consumption, so after meeting Australia’s transport demand it would be necessary to provide as much liquid energy again through the conversion of other primary forms, again at a high energy cost.





Imagine a system in which wind and sun contribute on average over a year 25% and 30% of demand.  It can come as a surprise to realise that during a day when wind and sun are both at their maximum these two sources might be generating several times total demand.  This is because average wind output (i.e., output over the long term, compared with peak output) is c. .25 but peak wind output can be .8 - .9, and average PV output is around a 24 hour continuous flow of 13 W per panel (e.g., 60 W from a half square metre panel for 5 hours on an average day, divided by 24 hrs) but peak flow would be 60 W.  So if the system had enough capacity to meet .25 + .3 of demand p.a. then there would be times when wind and sun together were generating maybe 5 times demand and most of the energy they were generating would have to be dumped.


This shows the mistake evident in Stern’s Fig 9.4 where total demand is neatly divided into solar, wind etc. components and contributions.  This common approach conceals the large problem of redundancy, i.e., the fact that in order to achieve those fractional contributions each of the sources would have to have far more capacity than those fractions suggest, (because for a lot of the time much of their capacity will be idle.)


Consider the role of solar thermal in a renewable system with .25 of total demand met by wind and .3 by PV.  If solar thermal is the only other contributor then on average it must have enough capacity to meet .45 of demand, but when there is no wind or sun for PV it must supply 100% of demand, and it must do this from storage meaning that the storage and generating systems must be many times bigger than normal.


The variability between summer and winter would more or less double the magnitude of this problem for solar sources, given that in good solar regions winter insolation can be about half the summer value.  (The multiple is greater in the lower latitudes.) Thus a PV system designed to meet 30% of demand in winter might meet 60% of it in summer.  The effect would be offset to some extent by the fact that winds tend to be higher in winter.  However with daily variability the effects compound rather than compensate; i.e., at night when there is no solar input winds tend to be lower.


                                    AVERAGE vs PEAK DEMAND.


When estimating quantities of generating capacity for a whole system attention must be given to the peak demand the system is likely to have to meet, not the average.  Systems typically have 30% or more generating capacity than would meet average demand.  Optimistic discussions of renewable systems typically fail to attend to the implications of peak demand and estimate only in terms of average demand.  (Stern’s Fig 9.4 makes this mistake.)  Thus conclusions re the amount of plant and its cost often seriously underestimate.




With coal or nuclear plant there is no variation in fuel supply, but with sun or wind there is.  This has major implications for the redundancy that has to be built into whole systems to ensure that a continuous supply can be delivered.  In those periods of several days in a row when there is negligible sun or wind some other generating source would have to plug the gap, and thus enough of it would have to be built to meet almost all demand.  To deal with times when there is plenty of wind but no sun, are we also to build enough windmills to meet total demand?  It is at times thought that solar thermal storage will get totally renewable systems through such periods, but this just means large redundancy in solar thermal storage and generating plant.


This point invalidates some proposals which envisage only a small need for a particular source to plug the gap left by wind or sun.  For instance ZCA claims only a small need for biomass, but their diagrams show that they have focused on the total annual contribution and amount of biomass needed in a year, and not on the times when there is no sun or wind and biomass would have to meet close to total demand.




Renewable energy sources are usually thought of as additive, that is, as if building X GW of wind capacity and X GW of PV capacity would give us the power that 2X GW of generating capacity would deliver. However on calm nights these two sources would deliver no power at all.  Thus they are best thought of as sources which at times can be alternated with or substituted for coal fired power, but not as sources which can always be added to each other.  (Stern’s Fig. 9.4 reveals that the various components are being thought of as additive.)  This means that we might have three or more very expensive systems each capable of more or less meeting demand while the others sit idle, and in addition we must retain a coal or nuclear system capable of meeting most or all demand when most or all the renewables are down.




Chapter 6 of Trainer 2007 outlines the reasons why we are not likely to have a hydrogen economy. Firstly the hydrogen would have to be produced from some renewable source. Present industrial production of hydrogen from electricity is around 65% energy efficient.  Bossel concludes that if the hydrogen is then compressed, pumped, stored and re-used, the energy losses at each of these steps will result in something like only 25% of the energy generated being available for use to drive the wheels of a fuel-cell powered car.  (Bossel, 2003, 2004, and undated.) That this plausible can be seen if we assume  .7 efficiency for production of hydrogen from electricity, an optimistic .8 for storage and distribution by compression, pumping or tanking, fuel tank filling, and .4 for fuel-cell operation, which would combine to yield an overall mill to wheels efficiency of 22%. In fact plausible assumptions can make the final figure closer to 10%. (North, 2005.)  Mackay says “…hydrogen powered vehicles are a disaster.” They use more than three times as much energy as a petrol driven car. (2008, p. 7.) 


It is by no means generally assumed that fuel cell efficiency will rise to c. .5 - .6.  In addition, platinum resources are insufficient for large scale use of PEM fuel cells (Gordon, Bertram and Graedel, 2006), although other forms of fuel cell might become viable.  Because the hydrogen atom is very small and light it leaks through vales and seals easily.  It also reacts with other elements, making metals brittle.  How often would pipes etc. have to be replaced?  How much petroleum would it take to put in a plastic pipe distribution system (inside steel pipes to take the pressure)  Consider the extent of the existing gas supply infrastructure; another more expensive system about as big would have to be put in for a hydrogen distribution system (if only because the gas system will still be in use.) 


Bossell details these and other difficulties.  For instance he points out that a standard tanker can deliver 20 tonnes of petrol, but it would only deliver 320 kg of compressed hydrogen. To pump hydrogen to Europe from the Sahara would take 65% of the energy going into the pipe line at the start. It is therefore not likely that energy-intensive societies could be run on hydrogen shipped around the world in tankers from sites such as the Antarctic where winds are very strong.


Lovins (2003) argues that for these reasons the best strategy would be to distribute electricity to many small hydrogen generating outlets for storage and vehicle refuelling.  This would reduce the distribution losses, but it would probably still involve a considerable (e.g., 10 – 15%) loss in transmission of electricity from distant renewable electricity sources such as wind farms in Siberia (Czisch, 2004), a lowered hydrogen generation and storage efficiency because of the need for many small units, and it would still involve compression losses in filling vehicle tanks, and the need for considerable storage. Pressurised tanks in vehicles would add weight, reducing the efficiency of vehicles, and constitute a much greater explosive crash risk.  The overall mill to wheels efficiency would therefore probably remain around .25.  Lovins’ optimistic assumptions are questioned (Crea, 2004, and Wilson, 2002) and he does not seem to take into account the considerably greater embodied energy costs in the kinds of super-efficient vehicles he assumes.  (Matejda, 2000, documents surprising embodied energy costs of this kind.)


Consider the capital and embodied energy costs of a system to deliver 1000 MW.  This would have to include the capital cost of the windmills, the transmission lines, the hydrogen generating plant, the compressing, pumping and storage equipment capable of handling very large volumes of gas, and the cost of the “power station” required to produce electricity from the stored hydrogen.  The last item would be equivalent to the 1000 MW coal or nuclear power plant that would have avoided the need for all this plant on the hydrogen path.  To deliver the initial 1000 MW electricity we would need 3,000 MW of wind capacity, even at an ideal wind site, and 4340 MW at the world average site where capacity is .23 (IPCC, 2007, Section


The hydrogen optimist’s best strategy might be to have wind and solar to meet say one-third (or one-half) of system electricity demand directly and to meet the rest via much additional capacity storing hydrogen for use at c. .25 efficiency.  In other words to meet the remaining two-thirds (or one-half) of the target 8 times (or 4 times) as much electricity would have to be generated as would meet that first one-third (or one-half) of demand.  Thus contending with variability greatly multiplies the need for plant, with associated embodied energy costs, e.g., for hydrogen production and storage and regeneration equipment.  Adding the transmission task from distant wind fields, would seem to imply an impossibly costly system…just to meet the 20+% of total energy demand that takes the form of electricity. To also run transport this way would be to add a task that is almost twice as big. (Australia’s early 2000s electricity consumption was 700 PJ and transport use was 1200 PJ.)


These considerations are also relevant to the idea of “over-sizing” wind and PV systems with a view to saving excess supply as hydrogen.  When the low efficiency of the cycle is added to the embodied energy cost of all the hydrogen generating, transporting, storing and regeneration plant, it is conceivable that no net energy would be delivered.  This is especially likely with respect to using liquid hydrogen for aviation fuel, as liquefying the gas involves a further 50% energy loss, and then there is the embodied and other energy costs associated with keeping the liquid very cold.





It is easy to overlook the significant difference between peak and average delivered output from renewable sources.  A coal-fired power station will deliver at around .85 of its peak rating, but  for wind, PV and solar thermal the figure is around .3 - .33.  This means that if you  build a coal-fired power station knowing that the capital cost is $2000 per kW(p), you will actually be paying $2000/.8 = $2,500 per average kW delivered throughout its lifetime.  But if you build a windmill knowing that the capital cost is $2,000 per kW9(p) you will actually be paying $2000/.33 = $6,000 per average kW delivered throughout its lifetime.


This means that figures on “levelised cost” for energy, and on capital cost per peak kW of plant capacity can be quite misleading.  Discussions of the viability of renewable focus exclusively on these values.  It is often said that the cost of wind plant is about the same as for coal-fired power stations,but this is a reference to peak output, and not average or delivered output, which ag ain for coal is s four times as high as for wind.





It is often assumed that the difficulties set by renewables means that nuclear energy must be adopted.  Chapter 9 of Trainer 2007 presents several reasons why nuclear reactors (burners; on breeders see below) cannot solve the general energy problem, if only because there is likely to be far too little fuel.  If reactors were to provide 9 billion people with the present Australian per capita electricity use nuclear generating capacity would have to be around 40 times as large as it is now, (and Australian electricity demand might double by 2050).  The commonly stated 3 – 4 million tonne estimated Uranium resource figure (Leeuwin and Smith, 2005, Zittel, 2006) would last about 2 years.  Lenzen says current fuel use would last 85 years. (2009, p. 50.)  So nuclear energy cannot make a significant difference to the global energy situation, (unless fusion or breeder technology is assumed.)  Taking the highest speculative estimates (c. 13 million tonnes) and adding thorium would not alter the outlook significantly.    There are large quantities of Uranium in very low grade sources such as sea water and crustal rock, but Leeuwin and Smith argue that the energy cost of retrieval would be greater than the energy required to do this.


Even more important than fuel scarcity might be the scarcity of the many non-abundant metals needed in reactor construction.  A world providing rich country levels of energy consumption to 9 billion would have perhaps15 000 power stations.


It is sometimes claimed that the use of breeder reactors would make possible inexhaustible quantities of energy, especially as the fourth generation Integral Fast Breeder could use low grade ores, existing spent fuel waste, and bomb-grade Plutonium.  I can’t assess the plausibility of this general claim but following are some of the issues on which we would need clear and convincing information.


a)    How much fuel would be available from low grade ores when the energy cost of mining and processing was taken into account.  According to Leeuwin and Smith this would rule out use of crustal rock and sea water.  If this is so then the energy return from processing the next higher grade resource category would also be low, etc.  So we would need to see analysis of the whole spectrum of ore grades along with the associated retrieval energy costs.


b)    What is the energy cost of plant, including the IFR, the mining and fuel production, etc equipment, and plant for decommissioning, and for dealing with wastes.  The ER for burners has been estimated at a mere 4.5, not including fuel production, decommissioning or waste treatment.


c)    What is the “extraction rate” for very low grade ores?  Leeuwin and Smith say that for Phosphates it is only 22% of uranium in the ores can be extracted.  Mackay says there is only 22 million tonnes of Uranium in phosphates (This does not seem to align with McGreggor and Deffeys??)


d) What limits are set by the difficulty of separating the newly bred fuel from the contaminants in spent Uranium coming out of a breeder?


e)     How many times the energy produced by a burner can a breeder

produce from a unit of fuel? Estimates seem to range between 33 and 100, with 60-70 most common. (E.g., Mackay, 2008.)


f)      What is the breeding rate; i.e., the time it takes for enough fuel to be

bred to start up a new reactor.  Blees says 7 years.  How long then would it take to start up the many reactors that a nuclear world would require?


g)    There would be fuel reprocessing and in my opinion this is too dangerous,

given that advocates of the IFBR see it as providing abundant world energy, and therefore involving large numbers of technicians in all countries.  It seems likely that  before long someone somewhere would make a mistake that would devastate large area permanently.  The history of reprocessing, e.g., at Sellafield, has already been a serious concern and the scale envisaged would be much greater.


h)    What is the scope for diversion of radioactive material for bomb

production, terrorism etc?.  Blees says terrorists would not try because it would be much easier for them to tap other sources than IFBRs, but that does not mean they are not a source and a danger.


i)   What are the decommissioning and waste storage implications; more           complex than for burners?


j)  What scale are we dealing with?  Let us take an unrealistic upper limit.  If 9 billion people were to have the per capita energy consumption Australians seem to be heading for by 2050, perhaps 500 GJ, all from reactors, then the world would be consuming 4500 EJ/y, around 8 times present world energy consumption.  This is at least 460 times the present amount of electricity generated by reactors.  It would be equivalent to about 250,000 1000 MW reactors operating at .8 capacity, and to cope with peak demand we’d need to have more than 3,300 reactors built and in use or ready to use.  The need to convert electricity to meet demand for non-electrical energy (e.g., aircraft) would increase this primary generating task further.  Much more significant would be the greatly increased need for energy to provide minerals from very poor ores, grow food in greenhouses, deal with ecological impacts of so many on high living standards, etc. Thus the scale of all the above problems would be very great if nuclear energy was to be the main energy source for a world in which all enjoyed the “livings standards” we expect in coming decades.  The sheer heat release from the energy generation and use might be intolerable in terms of geophysics, i.e, might produce unacceptable global heating.


In my view the fate of consumer-capitalist society is very likely to have been settled before 2040.  The “2030 Spike (Mason) will hit us with overlapping, serious and insoluble shortages of energy, water, phosphates, various minerals, land, fish, forests, food, and increasing population, urban overload, and especially ecological stress, including global warming effects, and very likely intense resource wars.  I think there is much too little time to built alternative technologies to cope with this time of troubles, even if they clearly existed. To build 250,000 large power stations by 2050 would be to build about 10,000 every year, if they last about 25 years.  So even if the IFBR is as problem free and abundantly productive as some of its advocates say, I don’t think it can save us.




The foregoing evidence seems to leave much doubt as to how much electricity from renewable sources we are likely to be able to afford or integrate into the supply system.   It seems to show that it is unlikely that demand could be met in winter.  It is much more unlikely that renewables will be able to generate sufficient electricity to fuel all of our transport via electric or hydrogen vehicles.


Again it should be stressed that only 20% of our final energy demand takes the form of electricity, and that electricity is the form of energy that almost all the renewables (except biomass) produces.  How are we to provide the other 80% solely from renewable energy sources, and if this is via conversion from electricity, what will be losses add to?


To this we must add the fact that electricity demand is rising all the time, and fast.  In recent years Australian peak demand has increased at more than 3% p.a.  At this rate it would be more than 4 times as great as it is now by 2050, although The Australian Bureau of Agricultural and Resource Economics (2006) expects the rate of energy growth to have fallen to 1.9% p.a. by 2030.  However energy consumption growth in the Third World and for the world as a whole is increasing much faster than in the rich countries.  Garnaut’s Figs. 2 and 4 (2008), taken from IPCC sources, indicate that continuation of business as usual growth in energy use would see CO2 emissions 4 to 5 times as great by 2050.




It is commonly assumed that technical advance and greater conservation effort can greatly reduce the need for energy. Lovins and von Weisacher (1997) have argued that a “Factor Four“ reduction is achievable, i.e., halving resource and environmental loads while doubling GDP.  Most of Lovins’ (valuable) analyses of particular instances indicate 50 – 75% reductions.  But it is easily shown that these would be far from sufficient.


Let us assume that rich world energy use and other resource and environmental impacts must be halved (…although solving greenhouse and footprint problems would require around factor 10 reductions.)  If by 2070 there are 9+ billion people on the “living standards” Australians would have by then given 3% growth, total world economic output would be 60 times as great as it is now.  If by that point in time we have reduced present environmental impacts by 50%, we would have made a Factor 120 reduction in the rate of impact per unit of economic output or consumption, as distinct from a Factor 4 reduction.  This is far beyond the realm of credibility.


Mackay (2008, p. 133) says not much improvement can be expected re aircraft. Moriarty and Honnery indicate perhaps at best 50% cuts for some transport sectors, but note that these gains are being swamped by rapid increases in demand.  Car transport is set to multiply by 2.4 by 2050, and the multiple for heavy vehicles is greater.  Buildings seem to be the most promising sector.


Moriarty and Honnery point out that the ratio of final energy (produced/delivered) to primary energy (total input into processing) has fallen in recent times.  This is very important, indicated declining efficiency of producing energy.  The “Productivity Paradox” notes that the advent of computers has not improved the general economic productivity of the economy. (If productivity was measured properly, focusing on energy inputs, it would probably be found to be falling now, and productivity gains are likely to cease soon due to this factor.  Ayres, 2006.)


The few estimates I have found do not support a confident overall conclusion.  They indicate that a 33% overall reduction in energy use in major activities is plausible.  Mackay’s overall estimate is c. 30%.  The IPCC concluded that carbon mitigation effort might cut emission of CO2 by 16 – 31 GT/y, from BAU projections of 49 – 68 GT/y, for 2030.  In other words technical advance in this field might achieve a 50% reduction.  The Energy Efficiency and Greenhouse Working Group of the Australian government (2003) thought that a 20-30% reduction with present technology is possible.  McKinsey (2009) says US primary consumption could be reduced to 20% below where business as usual is taking it.


The areas with greatest potential are electric cars and building heating.  In both reductions of 70 -80% are commonly claimed to be possible, but these need to be examined carefully.  The buildings figure is usually a statement of possible gross reduction and needs to be offset by the energy required to insulate, double or triple glaze windows, run heat pumps and air conditioning, and produce this equipment.  The WWF analysis seems to indicate that large scale savings on heat loss are possible, but at an almost similar large increase in electricity use.


The domestic and commercial sectors of the economy only account for about 15% of total energy use, so even spectacular reduction in the energy going into heating buildings is not likely to result in much reduction in total energy use.


The car figure typically only refers to “tank or battery to wheels”, and leaves out the energy losses in charging the battery, in getting the electricity from the windmill of solar thermal farm to the battery (which might be 4000 km), and in batteries sitting idle much of the time, and in the embodied energy cost of producing high energy intensive plastics for bodies, Lithium batteries, and engine parts for electric vehicles. Also car weights must be comparable, i.e., the typical 9 litres per 100km for a normal car today refers to a fairly heavy vehicle, not a very light electric car.  A thorough life-cycle analysis for the predicted electric vehicles might yield an energy efficiency 3+ times that of a comparable vehicle.


            “Technical potential.”


It is important to keep in mind that claims about technical potential can be misleading, because what is achievable in the real world typically falls far short of what can be done in the lab. Consider the differences between...


·      Technical potential”...what can be done irrespective of cost and convenience and acceptability.


·      Economic potential”...what you can afford to do.  It might be technically possible to get every last particle of a pollutant out of a gas flow, but only at a very high cost.


·      Socially/politically” achievable.  Transport fleet efficiency could be greatly improved if everyone moved to bicycles and small cars, but this is not acceptable.


·      The Jeavons/rebound effect.  When technical advance enables savings these are often spend buying more.  E.g., if a technical advance enabled car mileage per litre of petrol to be doubled, many would drive much further.  Thus the technical advance will not necessarily lower resource use.


Finally, sometimes a technical advance in one area can be achieved only by increasing costs somewhere else.   Water supply problems might be reduced by desalination, but only if the energy and greenhouse problems are increased. Reducing building heat use usually involves considerable increase in insulation cost, and especially electricity for circulating heat.  Electric cars cut energy use in the car dramatically, but appear to involve much higher embodied energy costs. (Mateja, 2003.)  Bryce (2010) says 60% of the energy and environmental cost of these cars is to do with their production and disposal, not their on-road performance, and these costs are typically not included when optimistic claims about their energy cost are made.


To summarise, optimistic claims typically refer to what is technically possible regardless of costs and difficulties land therefore energy conservation and efficiency gains likely in the real world are probably going to be considerably less than the tech-fix optimists usually claim. Very important is the fact that the cost of energy is very likely to increase significantly in future and this will increase the cost of conservation measures, and thus reduce their implementation.




The difficulties involved in a renewable energy world can be made clearer by attempting to explain how a future world energy budget might be composed. The figures and assumptions used here are from the early 2000s are somewhat crude and simplified and the exercise is only meant to be indicative of the magnitude of the problem.  The detailed analysis can be found at Trainer, 2010. 


The main assumptions and items in the derivation are as follows.


Global primary energy target, 2050,                                  1000 EJ/y


 Final energy therefore,   .7 of final,                                     690 EJ/y.


Conservation and energy efficiency gains:

assume 33% reduction in energy needed.

So final energy target after conservation effort                    455 EJ/y


Direct electricity demand, 25% of final energy                     115 EJ/y


Transport demand, assuming 60% electrified                      152 EJ/y

            So, electricity                                                               92 EJ/y

            Liquid fuel                                                                    60 EJ/y


Low temperature heat (assume solar panels

not requiring electricity etc.), at 10% of final

 energy demand                                                                      46 EJ/y


Electricity generated from hydroelectricity;

assume twice present).                                                19 EJ/y


Biomass ethanol (assume 1 billion ha, @ 50GJ/ha)               50 EJ/y




So, electricity demand is 115 EJ/y direct + 92 transport =    207 EJ/y.


Hydroelectricity                                                                        19 EJ/y


Electricity remaining to be generated                                    188 EJ/y


Demand for non electrical fuel 455 – (115 direct

electricity + 92 transport + 46 Low temp. heat) =                  202 EJ/y


Available biomass                                                                  50 EJ/y. 


Liquid fuel needed (202 – 50) =                                              152 EJ/y                                                                     



Let us assume this nonelectrical energy can be provided in the form of hydrogen generated by renewable electricity at .5 efficiency.  Thus to provide the 152 EJ in non-electrical form would require generation of 304 EJ of electricity.


Therefore the total amount of electricity required from above would be 188 EJ/y plus 304 EJ/y for conversion, i.e., 492 EJ/y to be supplied.  This is 41 EJ each winter month.   


Let us assume a system in which wind and photovoltaic systems each contribute 25%, i.e., 10.25 EJ/month, and solar thermal systems contribute 50%, 22.5 EJ/month. (Different assumptions will be explored below.) The task will be to meet demand in a European winter.


Wind:  Although the present world average capacity factor is .23 (IPCC, 2007, Section, in winter in several European countries it rises to around .38. (Wind Stats, 2008.)  At this rate a 1.5 MW mill would generate 1.5 TJ/month.  Therefore to generate the required 10.25 EJ per winter month 6.8 million mills would be needed, and at $3 million per mill the total cost might be in the region of $20.4 trillion.


PV: Even in the most favourable US regions in winter solar radiation on a square metre tilted at latitude is only around 2.5 kWh/m/day.  However in mid European countries it is around .7 kWh/m/d. (Morrison and Litvak, 1998)  However let us assume the PV farms are located in deserts where winter daily global radiation might total 7 kWH/m2/day, i.e., 117 MJ/m2/month.  To provide 10.25 EJ/month 88 billion square metres of PV panels would be needed. At an all inclusive installed cost of $1000/m (roughly corresponding to $6.5/W; Lenzen states $7/W for present cost, grid connected, 2009, p.119.) the cost would be $88 trillion.


Solar thermal:  The example central receiver cases given by NREL 2010 indicate that a $^%* million plant would generate 358 million kWh/y, i.e., 1.288 PJ/y.  To generate 20.5 EJ/y we would need 16,000 such plants, costing $10.5 trillion.


The assumed plant lifetime here is 25 years.  (Some sources assume 20 years for renewable, e.g, IPCC, 2011, Annex 111, p. 11, IEA, 2010.)


The total would be $129 trillion.  When averaged over an assumed 25 year plant lifetime this would be $5.16 trillion p.a., around 11.5 times the present amount of world annual energy investment, which is $450 billion. (Birol, 2003.)


It must now be stressed that the real figure would be far higher than this, because there are several major components of a total energy supply system whose costs have not been taken into account in the above exercise.  These include the embodied energy and dollar costs of all the systems, the cost of the many long distance transmission lines from deserts, the low temperature heat collection panels and tanks, the components of the hydrogen processing equipment.  Nor have operations and management energy costs for the lifetimes of any plant or components within the total energy system been accounted, (which for solar thermal would be equal to .25-.33 of capital cost; IPCC 2011, Annex 111, p.8.) In addition no account has been taken of the need for additional plant to meet peak demand. Whatever the sum comes to, it must be multiplied by perhaps 1.


Very important is the fact that the exercise only dealt with capacity needed to meet average demand, and a renewable supply system would also need the capacity to deal with times when the wind and solar energy sources are at their minimum levels.   Average winter monthly insolation can be 40% below average winter insolation, at the best sites. (NASA climate data.)  Even worse, there can be several days in a row when there is negligible sun and wind, and if solar thermal storage is supposed to cover these periods than we would need enough ST generating capacity to meet almost total demand may be 20 times normal ST storage capacity would be needed.  (See The limits of solar thermal electricity.) ...or, if  biomass is supposed to plug the wind + solar gaps, then we’d need to have built and paid for enough biomass burning plant to meet total demand.  


Taking these factors into account would probably treble the plant and cost figures.


            The implications of 10 billion on rich world “living standards”?


The target taken in the foregoing exercise, 1000 EJ/y, would be well below the quantity needed to provide energy equity and affluence to the whole world.   If the expected 2050 world population of 10 billion were to consume energy at the per capita rate Australians are likely to rise to by 2050 under a business as usual projection, world energy supply might have to be in the region of 4000 and maybe 5000 EJ.


The effect on the global energy investment budget is not proportional to this four-fold multiple for the quantity of energy involved.  The above assumed nuclear, hydro, biomass and geo-sequestration contributions would still account for only 128 EJ/y, 3% of the required amount, and allowing for conversion the amount of electricity to be generated would  be 2163 EJ/y, five times the amount derived in the first budget above, some 35 times the present world total.


 The implications for redundant generating capacity.


A major implication of the foregoing analysis is that the amount of alternative generating plant that must be built to cope with the variability of sources and winter is likely to be much greater than might be imagined from an initial understanding of the required supply.   For instance in the above budget 435 EJ need to be provided after taking into account nuclear, biomass, hydro-electricity and electricity via geo-sequestration.  If this was to be provided by coal-fired or nuclear power stations the peak generating capacity required to be built would be 13.8 b KW (ignoring down time.)


However the average rate of generation for coal or nuclear plant is close to the peak rate but for wind, PV and solar thermal it ranges between .13 and .38, and for solar thermal seems to be about .1 in winter (above).  In addition as we have seen there are times, especially in winter, when one or more of these sources is contributing little or nothing, meaning that the other(s) need to be large enough to make up for such shortfalls.  If on the other hand all contributors were coal power stations there would be no need for redundancy of this kind. 


The combined effect in the above budget is that far more peak generating capacity must be built than 13.8 billion KW.  In fact the amounts of peak capacity in the above budget are, wind 9 billion kW, PV 26 billion kW and solar thermal 64 billion kW, making a total of 101 billion kW, some 7.3 times as much as would have been needed in the form of coal or nuclear plant.  (The solar thermal figure is so much higher than wind mainly because for wind the ratio of winter to peak capacity is 4 times better than for solar thermal, and solar thermal’s contribution is 25% higher than wind’s contribution, in the budget above.)


This means that at times of good wind all and solar radiation when all renewable components are functioning at peak output, supply would be 7.3 times demand, and there would be times when their combined output would be close to zero, and supply would have to come from coal or nuclear sources.


An important implication is that the concept of “levelised cost” can be quite misleading in estimating the affordability of renewables.  This figure refers to the cost per kWh if a system functions for a lifetime, under specified conditions.  What concentrating on such figures does not make clear is the need for much redundant capacity to be Built if a wholly renewable system is to meet all demand, including those times when much of the plant (which would have a low levelised cost if it was used all the time) is standing idle.




It could be argued that the best strategy would be to use nothing but solar thermal systems.  When one contemplates the supply pattern for wind in Figs. 1 and 2 of ZCA (2010), or the reported performance of NSW wind farms, one realises that from time to time the wind system would be contributing almost nothing, meaning that there would have to be on hand sufficient other renewable generating capacity to meet total demand.    Some provision for biomass generation might make sense to deal with storage problems over several days, but otherwise the best renewable strategy might be to rely almost entirely on solar thermal sources, paying a long distance transmission penalty.  Why build anything else if there will be times when none of it will be contributing and you will have to have enough solar thermal to meet total demand?




The ZCA report assumes that the whole economy can and should be converted almost entirely to run on electricity.  This would seem to be the best “high-tech” strategy (as distinct from Simpler Way strategy, which involves dramatic reduction in demand, and reliance on a variety of energy sources.)  What is not clear is the extent to which this can be done.  There does not seem to be good data on the end uses of energy enabling conclusions about what functions could be converted.


It would seem however that the investment cost for an electric economy based on solar thermal plant would be extremely high.  Assume for instance a 2050 Australian final demand  of 7 EJ/y, i.e., .6 EJ/month in winter, all from dish-ammonia plant providing 20 W/m2 in winter = 8 KW/m5 of 2 = 192 kWh/dish/day = 691 MJ/dish/day = 21 GJ/dish/month.  We would need 32.7 million big dishes, which would cost $5.33 trillion, or $213 billion p.a.  This would be around 20% of GDP whereas world investment Is around .7% of world GDP.  (This estimate is an earlier one based on Big Dishes using ammonia for heat storage.  Central receivers now seem to be cheaper.)


                                                THE CO2 COST OF RENEWABLES.


Easily overlooked is the fact that fossil fuels would have to be used to produce renewable energy technologies.  In a world using nothing but renewables there would be no CO2 emissions, but even if we could get there a great deal of CO2 would be emitted in the early years to produce the necessary windmills and solar panels etc.  Lenzen’s review summarises the total life cycle emission rates for the renewable technologies.  These generally average about 60 g/kwh generated.  If a 2050 world energy demand of 690 EJ/y (final), i.e., 191 t kWh, was to come from renewables produced by fossil fuels, the annual CO2 emissions from the production and operation of the plant would be 1.15 GT.




In the next ten to twenty years there will certainly be major advances in the development of renewable technologies and in carbon emission abatement.  In the past abundant and cheap fossil fuels led to the neglect of conservation and renewables, and to the development of wasteful ways.  Now that more attention is being given to these tasks spectacular achievements are likely to be made.  Unfortunately however these will reinforce the belief that technical developments can solve the problems – all we have to do is keep up this impressive progress. The argument in this paper has been that the rapid initial progress, made by “picking the low hanging fruit”, will increasingly run into difficulties and limits long before it could become possible for renewables to sustain consumer societies.


An example is the fact that putting PV panels on house roofs is effective while the capacity is small in relation to the coal or nuclear capacity that must also be there to take over when the sun is not shining, but there is a limit to the amount of energy that could come from such a source.




None of these highly influential reports deal with the issues this paper addresses.  That is, they do not consider the difficulties and limits that might be associated with renewables, and proceed as if there will be no difficulty using the vast quantities that would be needed to meet all future demand.  (Detailed critiques are available at Trainer 2007b,  2007c, 2007d, and for the 2011 IPCC report on renewables, Trainer 2011b. These overlap considerably as all involve the same problems; for a combined discussion see 2007e.)




Although in many fields technical advance will reduce the energy needed to do things, there will also be strong tendencies going the other way, due to the increased difficulty of doing various things.  A good example is the greatly increased energy cost of getting water by desalination.  Consider also the need to resort to more technically complex ways of producing food, such as aquaculture or “skyscraper” farms.  Many minerals are becoming more scarce, requiring mining of poorer grades of ores., e.g., for phosphates, zinc, helium (gas), indium, gallium and hafnium, platinum and copper.  There are diminishing returns in many areas (e.g., time and distance travelled as cities become more congested, cost of traffic flow systems).  The fuel and shipping tonnage needed to catch a tonne of fish has escalated. More energy is needed to deal with pollutants, e.g. requiring geo-sequestration to deal with CO2. Global trade is increasing much faster than global GDP, tending to increase the need for energy per unit of economic activity.


Note again that many of these effects multiply with sheer increase in demand, raising supply targets above the levels that might be imagined when one focuses only on  the present supply task.


                                    THE GROWTH COMMITMENT


The above references have been to the difficulty or impossibility of meeting present energy demand from renewables.  That is not the focal problem.  The crucial question is whether renewables can meet the future demand for energy in a society that is committed to limitless increases in “living standards” and economic output.  The magnitude of the implications of this commitment are evident if we consider 9 billion people rising to the “living standards” we in rich countries will have in 2070 given 3% p.a. economic growth.   Total world economic output would be 60 times as great as it is now, and doubling every 23 years thereafter.

The projections given by the Australian Bureau of Agricultural Economics (2006) anticipates a 71% increase in national energy use by 2030, indicating that Australian per capita energy use might be more than 500 GJ by 2050  (alt hough they expect the growth rate to decline to 1.9% p.a. by 2030.).  As has been noted above, if all the world’s expected 9 billion people were to rise to that level of energy use then world energy production would probably have to be 4500 EJ, about 9 times as great as it is now.


 The argument in this paper has been that present levels of energy use are seriously unsustainable and cannot be provided by renewable sources, yet in consumer society there is a strong tendency to assume that there is no need to consider the commitment to limitless growth in production and consumption, and that renewables can provide all the energy this would require.




A renewable energy supply system would be very likely to deliver at much higher prices to consumers than they have been used to.  Remember that if wind is to deliver X GW on average then we will need 3-4 X GW of peak capacity at perhaps $1,500/kW.  For PV the multiple is probably 5.6 (average output is around .18  of peak capacity), applied to a capital cost per W that could be 5 times that of coal fired electricity.  Conversion and dumping problems will require much more generating capacity than demand.  We might also have to build almost as much coal/nuclear capacity as would meet demand (for when wind and sun are low).  There will also be geo-sequestration plant, long distance HVDC lines, heat storage, pumped storage, compressed air caverns etc., And as has been noted the increasing scarcities and difficulties (mining poorer ores, desalination of water) will multiply the amount of energy that needs producing to maintain consumer-capitalist society. 


The discussion of renewable energy potential and costs is carried out in terms of the present cost of input materials etc.  This is likely to be seriously misleading.

The conditions under which renewable energy technologies will have to be researched, developed, financed and built on a massive scale are very likely to be far more difficult than at present, imposing significantly higher energy and dollar costs.  Energy, materials and dollar costs estimated at today’s values are therefore not likely to be indicative of future costs.  Note also that the scale/pace of the construction task would have to be extreme, and this alone would raise the prices to be paid for input materials.


 It would seem that these many factors will combine and multiply to produce big increases in the price of energy impacting on consumers.  Is it likely to be affordable, given that at present ordinary people even in rich countries find the cost of energy problematic?  What will the effects be in the Third World where food price rises have already produced riots; we need stability there in order to be able to get hold of their resources.




This document has only been concerned with energy, but this is only one element in the general limits to growth” problem.  As has been noted we are running into accelerating scarcity of most other resources, and serious ecological problems, and increasing social problems, all primarily due to over-consumption, and worsened by the quest for growth.    These considerations would set an intractable limits to growth problem even if there were no energy problems.


In addition, the extreme economic injustice built into the foundations of consumer-capitalist society renders it unacceptable.


Again even if renewables could meet future energy demand for world of 9 billion living affluently, we would still have a critical sustainability problem.  (It is likely that if we did get access to abundant energy, such as via IFBRs, we would accelerate depletion of resources.)


A thorough analysis of the limits to g reed and growth society would also take in the “moral” limits set by a global economy which delivers most of the world’s resources to the rich countries and deprives most people of a fair share.  (See Third World, )  The fact that the global economy is grossly unjust constitutes another case against the acceptability of consumer-capitalist society.




The ultimate worry is that if it did become possible to provide abundant renewable or nuclear energy then energy use would rise dramatically, to produce more products, development, travel, consumption resource depletion and ecological impact.  They’d be able to track and hunt down the last small fish in the ocean.  Yes there would be more energy to deal with the side effects but a) humans will skimp on this, and b) many problems cannot be dealt with just by having a lot more energy; the limits to growth problem includes land shortage, fish depletion, species loss… More poor farmers would get more tractors and push to work more land.  They’d try to solve the water problem by massive desalinisation, meaning a brine problem.  Consider the introduction of the Indian Nano car, which will now mean far more car impact, including road building and repair.  Abundant energy would lower the price of goods, increasing consumption.


.                       WHERE  MIGHT THIS ANALYSIS BE WRONG?


Storage is the main problem for renewables and it could be that some regions have much scope for pumped hydro, e.g., mountainous parts of Europe, Scandanavia. (hydro only provides c. 13% of European electricity), and not all dams could install pumped storage due to absence of scope for a low dam.  Might there be surprising advances in battery technology? 


The most promising strategy for the renewable optimist is solar thermal dishes plus ammonia storage, in deserts, plus huge HVDC grids several thousand km long.


What if they manage to achieve 100% extraction of carbon for geo-sequestration?  This would not help with the 50% of carbon fuel use that is not at stationary sites (light vehicle transport could be electrified, but not trucks, sea or air…)


Oversize components greatly, so that some will still meet demand when sources are low, and dump excess at other times, or store inefficiently.  Very costly, and would reduce but not eliminate periods when there is a gap.


Can Integral Fast Breeders save us, via all electric economies?  Is there time to develop enough of them?




Even if we found a way of meeting future demand easily, it would take a long time to build enough plant.  If the target is 1000 EJ (or much more taking in conversion losses) to provide for 9 billion affluent people by 2050, we would have to add 25 EJ of capacity p.a.  This is equivalent to about 1000 power stations every year.  That is the world would have to build as many power stations as there are now in the world, every 2.5 years.  Australia would have to build the equivalent of more than half its present power stations every year, for 40 years (i.e., to build c 11 EJ of renewable energy capacity, not just electrical capacity.)    Given that we are not likely to begin building alternatives for some time, and that plant built in 2010 would have to be replaced before 2035, the rate would have to be much higher.




Foran and Crane (2002) argue that Australia could meet energy demand from renewables.  I think Foran agrees that the world can’t do this.  Australia is probably in the best position of any country, with x 2 US good land area per capita, x 5 the European figure, mild climate, good wind and solar resources.  But Australia is highly dependent on the global economy, exporting resources in order to be able to import all the goods, services, IT etc. that it doesn’t produce, so it could not survive as a consumer-capitalist society if the many/all other nations could not maintain the affluence and growth party, using much energy to transport things internationally.  They can’t do that on renewables.


 Also the scenario Foran and Crane (2002) put forward, which includes harvesting 37 million ha for biomass, and much use of high-tech windmills, would require a lot of trucks, machinery, road maintenance equipment, etc.  At present we import almost all of this, so again if the rest of the world could not maintain the business as usual global economy we could not operate on our own the infrastructure required by a renewable energy system.





The energy and greenhouse problems are only two of the increasingly serious problems consumer society is running into. In Chapter 10 of Trainer 2007 it is argued that it will not be possible to solve these unless the commitment to affluence and growth is abandoned.  (The analysis is detailed at The Simpler Way website,  A much earlier statement of the case was given in Trainer, 1985.)  Consumer-capitalist society is described as irredeemably unsustainable and unjust.  It involves rates of resource use and environmental impact that are far beyond sustainable levels and could never be extended to all the world’s people.  Present affluent “living standards” would not be possible for the rich countries if these countries were not taking most of the world’s resource output, thereby condemning the Third World majority to far less than their fair share. 


It is argued that the commitment to affluent “living standards” and limitless growth is the predominant cause of the multi-faceted global predicament.  This inevitably generates problems of ecological destruction, resource depletion, Third World deprivation and geopolitical conflict and war.  In addition it is argued that the obsession with growth and affluence is damaging the quality of life and social cohesion in even the richest societies.  The present levels of production and consumption are the basic cause of these many alarming problems, yet the top priority is economic growth, and therefore the magnitude of the problems will inevitably be multiplied in coming decades.


In other word it is not just that consumer society is unsustainable -- it cannot be made sustainable.  Chapter 10 argues that huge and radical system change is clearly needed. The problems cannot be solved by technical advance or more conservation effort on the part of individuals, firms and governments within a consumer-capitalist society.  They are being caused by an overshoot that is far too great for that, and they are being caused by the fundamental structures and commitments in consumer-capitalist society.  The necessary vast reductions in energy and resource use and environmental impact cannot be made without dramatically reducing the volume of production and consumption and therefore without changing from a society in which the top priority is increasing hem without limit.


Chapter 11 of Trainer 2007 argues that the solution must be thought of in terms of a transition to some kind of Simpler Way (detailed in The Simpler Way website.)  This must involve non-affluent (but sufficient) material living standards, mostly small and highly self-sufficient local economies (and therefore localization as distinct from globalization), zero-growth economic systems under social control and driven by need and not by market forces or the profit motive (although there might be a place for markets and private firms), and highly cooperative and participatory systems.  Obviously such radical system transition could not be made without profound change in values and world view, away from competitive, acquisitive individualism.


There are good reasons for thinking that changes of this magnitude will not be made, especially given that the need for them is not on the agenda of official or public discussion.  A major factor that has kept them off the agenda has been the strength of the assumption that renewable energy sources can substitute for fossil fuels.





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