RENEWABLE ENERGY – THE ARGUMENT AGAINST ITS CAPACITY TO  SUSTAIN AN ENERGY-INTENSIVE SOCIETY.

       16.2.2013

Web address: http://socialsciences.arts.unsw.edu.au/tsw/RE.html

Ted Trainer

 

This document makes available the key evidence and analysis feeding into my current understanding of the potential and limits of renewable energy.  It is updated from time to time.  It is somewhat rough and ready, being a compilation of important considerations rather than a neat treatise.

There are two earlier analyses that are now not recommended because of the new evidence that has since become available:

·      The book, Renewable Energy Cannot Sustain a Consumer Society, T. Trainer, Springer, 2007.

·      Can the world run on renewable energy? The negative case, Energy Policy, 2010...

The current case that renewable can’t meet global energy demand is at, http://socialsciences.arts.unsw.edu.au/tsw/CANW.htm

An analysis of the Australian situation concluding that Australia could not run on renewables is at... http://socialsciences.arts.unsw.edu.au/tsw/CANA.htm

A two page overview of the case is

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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.  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.

There are now several impressive reports claiming that renewable can meet world energy demand, and almost no literature questioning the claim.  The IPCC repo9rt is over 1000 pages,and the 5.1 kg GEA report is over 1800 pages.  The latter has 27 expert authors and states,

“The renewable resource base is sufficient to meet several times the present world energy demand and potentially even 10 to 100 times this demand.” (GEA, 2012, p. 767.)

Thus the positive case can seem to be overwhelnmingly convincing.  However I have written critiques of many of these reports and these are available at

Most of these claims, including the GEA source, do not even offer a case; they simply detail impressive information on the nature of renewable technologies, some spectacular falling costs, and speculation on future possibilities ... but simply do not deal with the major difficulties, most obviously the problem of integrating highly variable sources to meet demand reliably through protracted periods when sources are negligible.

From The Simpler Way perspective energy is only one of several problems that cannot be solved  by or within consumer-capitalist society.  That society is far beyond sustainable levels  of resource use, it generates catastrophic ecological damage, it deprives most of the world’s people of a fair share of world resources, generates armed conflict, and is lealding to deteriorating social cohesion and quality of life.  We can only solve these huge problems by moving to some kind of Simpler Way, i.e., lifestyles and systems that allow us all to live well in mostly self-sufficient and cooperative local communities in which there is no economic growth and profit and market forces do not determine our fate.  (For the detail see, )

The main argument put against The Simpler Way case is that technical advance will solve aour problems and make such a transition unnecessary.  The main element within the tech-fix faith is the assumption that renewable energy cans save us.  This is why I have put a lot of time into attempting to assess the potential and limits of renewable. The analyses I  have published over about ten years have become more satisfactory, partly as better evidence has become available and partly as I have realised better ways of framing the case.  The current version (Trainer, 2012a) is much better than the 2007  book or the case published in Energy Policy in 2010.

I think the case is now very strong that the world can’t provide high “living standards” for all on renwables.  Some countries might be able to do it, and Australia might be one of them given that it is more favourably situated than almost all others.  However I do not think Australia can do it. (For the detailed case see Trainer 2012b.)

It is important to stress that I have always argued that we must move to full dependence on renewable energy as soon as possible.  This can only be done if we move to lifestyles and systems that require only a small fraction of the present rich world per capita energy consumption.  The document ”How cheaply could we live well?” details how this could easily be done in The Simpler Way.  (This theme is also dealt with in the book,  The Transition... Trainer 2010b.)

                                                ELECTRICITY

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 at all clear (ABARE and the ABS confirm Ayres 2008 on this.)  ZCA (2010) claims that almost the whole economy could be converted.  At present only 20% of Australian final energy use is electricity but most of the 33% used for transport probably could be converted.

Although many renewable sources can provide electricity there are only three worth considering in proposals for very large scale renewable supply, wind, photovoltaic solar, solar thermal and biomass-gas.)   Several other technologies are valuable and/or promising (briefly referred to below) but it is not likely that they will contribute significantly to very large scale electricity production.

       WIND

Quantity.

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. Moiriarty and Honnery (2011, p. 88) report that 5% of people live in areas where half the wind potential esists.

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’s review  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 around 2007 was approximately 18 metres. (Mackay, 2009 gives a similar figure.)  The figure will surely increase and turbines will probably be mounted on floating platforms but the costs will be considerable.

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 2050  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 by 2050 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 have been heading for, 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 capacity or load factor (ratio of average output to peak output) is only .23. (IPCC, 2007, Section 4.3.3.3.  Lenzen’s review, 2009, states .25 for 2008. The figure for off-shore turbines from the House of Lords study, 2007-8, is .28.)  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 could be accessed, but then there would be higher losses in transmission.  Also relevant is the fact that Germany has relatively poor wind resources but has built a lot of trurbines, tending to lower world average output.

Lenzen (2009, p. 97) reports the embodied energy cost of wind (i.e., the energy cost of uilding turbines) 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.  The quoted energy and dollar costs refer to use of relatively shallow sites and deeper sites will have to be used in future.

The intermittency problem.

The major limitation with most renewables is not to do with quantity but with 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 German 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.  Sometimes Danish wind input is 0% of demand.  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 CEPOS 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 go up when wind is high, because their coal-fired electricityhis cheap and it makes sense to sell it, and surplus wind.  I don’t think the issue can be settled easily, if at all. 

The importance iof the issue is that the high proportion of Danish electricity demand met by wind is taken to show that all countries can have wind contributing similar high proportions.  This seems to  be incorrect as Demnmark’s situationis unusually favourable.   It is a very small country (4 million) with very small demand, with large neighbours (Germany around 85 million) close by and able to take surpluses easily, and neighbours with large scale hydro electric capacity that can be switched off when surplus wind energy is available.  This means among other things that Denmark can have a lot of turbines without having to dump energy when the wind is strong.  So if 20% of the electricity they use does in fact come from turbines they could not do this as economically as they can, if they didn’t have neighbours able to keep the turines running profitably during high winds.   Most countries are in conditions like Australia has, isolated and unable to take advantage of very large neighbours and  hydro capacities.

            Evidence on the seriousness of the problem.

The magnitude of the integration problem is made clear in many studies.

o   Oswald, Raine and Ashraf-Ball, (2008) show that for the first 6 days of February 2006 there was almost no wind energy generated from Ireland to Germany, and one of these days was the coldest of the year in the UK.  An earlier study by Oswald Consulting (2006) modelling the typical performance of a system spanning the whole of the UK  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.).

o   Mackay presents a similar picture on pp. of 186 – 187 of Sustainable Energy; Without The Hot Air, (http://www.withouthotair.com/download.html)  Lenzen’s representation of data from Oswald, for the whole of Germany, follows. (To be added.)  Note that at times output is close to zero, for periods of some days.

o   It would be difficult if not impossible to “ramp up” coal or nuclear capacity to fill gaps 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 ramp up more easily, but gas resources are about as limited as oil, and fossil fuel use must be greatly reduced and probably totally eliminated; see below.)  One way they deal with these situations is to keep coal-fired plant idling, using up fuel and lowering system efficiency.  Sayeef, (2012) documents some of the headaches that electricity controllers and despatchers have to deal with as a result of variation in renewable input, especially fluctuations in voltage. The proboems are worst when renewable input rapidly goes down at the same time that demand rapidly goes up, and vici versa.

o   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.

o   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.

o   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.

o   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.

o   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.

o   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. 

o   Lawson (2011) reports data from Australian wind farms showing that output was under 10% of capacity one-third of the time, and under 1.25% one day a month.

o   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.) 

o   There are times when Danish wind system input is zero. (Sayeef, et al., 2012, p. 75.)

o   Modelling for a 300 GW European wind plus solar supply system finds that output would at times be only 30 GW. (Sayeef, 2012.)  Mardon (2011) examined Victorian wind performance and  found that there were periods “...when the total output was zero (or even negative) for periods of 7 to 10 days.” (When there is no wind power needs to be provided to the turbines to maintain their electrical state.)

o   In October 2007 there were 12 days when low wind speeds were recorded at 90% or more  of the 64 British meteorological recording sites at the same time.  On Oct 4^th, 6^th  and 18^th there was just one site.  On the 12^th ether were two sites. (Jefferson, 2008.)

o   Similar evidence on extreme internmittency is given by Sharman, Leyland and Livemore, (2012) for West Denmark, Flocard and Perves (2012), and Bach (2011) for several European nations.

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.  Some claim that introducing renewable enables no reduction in other plant needed to turn to when there is no wind, and that it actually increases total system greenhouse gas emissions.  This is because back up generators might have to be kept idling ready to ramp up, emitting gas.

The following diagrams represent the magnitude of the variability involved in conmining input on good and bad wind plus sun days..  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. (The case against renewable energy being ablt to run everything is that it would be unaffordable; see below.)

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 the whole of 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.” 

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%. Harvey’s figures are higher.  For 2000-3000 km the cost he sates is $460-500/kW (i.e., for a line capable of carrying a kW) (p. 152), and on p. 149 he states$250- 300 million per 1000 km, to which must be added the cost of two terminals costing $250-350 million.  The latter figures indicate that for transmission from the Sahara to Holland or the UK it would cost as much for the lines as for a (coal-fired0 power plant.

            ‘But the wind is always blowing somewhere.”

Thus it should be clear that the common statement, “...the wind is always blowing somewhere...” fails to grasp the problem.  Firstly, to quote Hayden again, “There are times when the wind is calm everywhere.”  More inmportantly, 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.

            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.

            Costs.

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 prices for materials and energy are likely to have a major effect. (Harvey reports a 74% price increase in the US around 2007, due he says to rising materials prices; 2011, 153.)

In the early 2000s wind farm costs were usually 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 4.3.3.2).  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. (2008), Coelingh (), and Davey and Coppin (2003) 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). 

            Lifetime?

It is commonly assumed that turbines will last 20 -25 years, considerablyles than PV or solar thermal plant, because of the stresses towers and blades are subject to.  However there is recent evidence that they are lasting only half as long, with deteriorating performance over that time. (G. Hughes, Edinburgh Univ,  reported by R. Mendick, Telegraph.co.uk, 28 Jan, 2013.)

PHOTOVOLTAIC SOLAR.

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 on a hot and clear summer day PV provides no energy for up to 15 hours.  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 wind, but it seems to me that 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. 9.am 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, i.e., that the embodied energy cost is c. 10% of lifetime output.  However  Lenzen et al. (2006) find that when all relevant factors are taken into account the ratio of input energy to energy produced is a surprising 33%.  Hall and Pietro (2011) claim an even worse figure for PV in Spain; 2.7/1.)

These good ratios and pay back periods are due to the fact that 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. (See Lenzen and Taylor (2003.)

The discussion of life cycle embodied 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.  See further below on solar thermal.

Can’t be 30%  can only input 10 hours; others turned off then??

SOLAR THERMAL ELECTRICITY

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, of in less than ideal regions and little attention seems to have been given to its lower limits. (The focus in Trainer 2013.) 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.)

Most discussion focuses on performance in very high radiation but this does not tell us what the magnitude of the overall contribution ST can make to a renewsable energy world.  What matters is the extent to which it can meet demand in less than ideal conditions and at other than mid summer.  The evidence below indicates that the potential contribution of ST falls rapidly with declining radiation and will be disappointingly low in less than ideal regions and in other than summer.

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.

            The intermittency problem for solar thermal.

Because solar thermal systems will be routinely equipped with capacity to store heat, probably for 18 hours enabling continuous supply most of the time, it tends to be assumed that the intermittency of sunshine will not be a problem.  This is far from the case as the sun does not always shine the next day.  In fact sometimes the sun does not shine for several days in a row, anywhere in the likely region in which the solar thermal farms would be located.  So the crucial issue is,what is the pattern of intermittency in solar radiation in the region and at the time you are interested in.  Even in the best Australian locations the answer sets serious problems for solar thermal power.

Trainer 2013 reports on an examination of austbralian Bureau of Meteorology  hourly DNI data over 8 years.  Four sites in central AustraliaIt  and one in Whyalla (where a ST plant is being built) and one at Mildura (which BZE proposes for a site) were selected and the radiation data for these sites was examined.  It was found that that there are many periods of three or more days in which the combined radiation at these sites would have been vedry low or negligible.  The following table indicates the magnitude of the pro blem over a period of three months late in 2010.  (This was not a typical period; it was unusually bad but this is what a renewable system heavily dependent on ST would have to deal with from time to time.) 

                                                            Table 1.

Length of low DNI period                          Average DNI per day             

                                                                               over the period(KWh)                   

3  consecutive days                                                 3.8                                                         

                          “           “                                                    2.6                                                         

                          “           “                                                    2.9                                                          

                                                                                           2.9                                                                                                       

4              “            “                                                  2.8                                                         

                “           “                                                     .17                                                        

                “            “                                                    .15                                                       

                “            “                                                  3.4                                                         

 5             “             “                                                 1.5                                                              

                                                                                1.4                                                                                                                 

6              “           “                                                   2.7                                                                                                   

Table 1 shows that in the four month period from September to December 2010 (inclusive) there were 12 periods of very low DNI for three or more days, one being as long as 8 days.  These periods totalled 48 days.  Periods of two days were not included in the tally.  Over these 48 days the average DNI per day was 2.3 KWh/m2/day.  The periods are non-overlapping; e.g., the 8 day period does not include any of the shorter periods.

This seems to mean that a solar thermal system located in possibly the best Australian regions (the extrenme NW coast could be better re radiation, but it is a long way fronm denand) would from time to time make little or no contribution to national electricity supply,evenif equipped with 18 hour storage.

Note that in these periods PV power plant at these sites would be similarly affected  PV can use more than direct normal radiation, but utility scale plant typically uses fixed modules and this collects less of the available radiation compared with central receivers which track the sun.

            The effect of low DNI on efficiency.

It seems that the way low DNI reduces solar thermal efficiency has typically been overlooked, and that this has significant implications.  It is usually assumed that a device has a set efficiency, and this is applied to various levels of radiation, e.g., a winter average at a particular site, to estimate output.  But in winter much radiation received even at a good site is under the threshold necessary for generation by dish-stirling units; i.e., efficiency is zero.  This means that it is a serious mistake to take the daily or monthly average DNI for a site, and multiply it by a given efficiency figure and assume that the result indicates power that will be generated.  This will overestimate power output, and increasingly so as DNI falls. 

There is not much evidence published on the issue, except some power curves for Dish-Stirling systems, which is clear and decisive.  These show that there is a significant deterioration in efficiency as DNI falls.  For the system described  by Magette et al., at 800 W/m2 efficiency is 83% of peak, at 700 it is 68%, at 600, 47%, at 500 29%.  These are big falls.  At 400 W/m2 there is no output at all. They are partly due to the need to draw poser for “parasitic” purposes, i.e., running the system, and this need is fairly constant as output falls.  Because troughs and central receivers involve the pumping of fluids it might be suspected that the situation for them is worse than for dishes.

Trainer (2013) presents some (but little) evidence on troughs and dishes, indicating a significant effect, and for troughs a cut off or threshold just under  6 kWh/m2/day.

What does not seem to have been considered is the possibility that a fairly good daily total DNI /m2 might be made up of many hours of DNI too low to generate any power.  My study looked into this and found that the daily total has to be fairly high, maybe over 6 kWhm2/day, before there are many hours with DNI over 500 or 600 W/m2.  A sample from the bureau data showed that even at 6 kWh/m2/day no hour had radiation over 465 W/m2, which the foregoing evidence indicates would be  too low for significant generation.

There is also evidence that it takes some time, e.g., 40 minutes, for a system to come back up to full generation after the passing of even brief cloud cover.  So on a hot and sunny day in which cloud frequently passes over the site output is likely to be well down.

Thus to know that a site has a reasonable annual, or monthly, average amount of radiation does not mean we can be sure a solar thermal plant will function well there; maybe none of the radiation received is strong enough to generate.

This recovery effect is related to another finding from my examination of the BOM data; viz., the patternor distribution of DNI over each hour in the day makes a difference.  (Chhatbar and Meyer, undated, noted this but didn’t analyse it.)  On a day in which DNI totals a respectable 6+kWh/m2 every hour might have a low average DNI, meaning that little or no power might be generated in each of those hours.  This means it is quite misleading jut to take daily total radiation and multiply it by the peak efficiency figure for the plant to arrive at an estimate of power that will be generated.

The effect of storage:  For troughs and central receivers the decline dishes suffer can be considerably reduced if there is heat storage, as is normal.  If at a pointin time tDNI is low the rate at which heat carrying fluid is pumped through the receiver can be slowed enabling the fluid to always be raised to high temperature for storage.  This means that it isn’t so important to think about the power curve for troughs and CRs; yes output when DNI is low will be low if the turbine is generating from that heat input, but if there is storage all heat going to the turbine can be at high temperature.

 However an examination of NRELs SAM cases with storage shows that efficiency still falls with reduced daily total DNI.  NREL says (personal communication) that this is largely due to the fact that parasitic losses (according to SAM 10% of electricity generated goes into running pumps, heliostats etc.) are mostly constant, taking much the same amount of energy from the lower gross production from lower radiation.  But my examination of SAM examples seems to show that this does note explain all of the effect.  The fall is evident in terms of heat energy received, i.e., before turbine effects.

Summary of findings re DNI and efficiency..

·      Central receiver efficiency falls significantly, like dish-Stirling, withfalling DNI, despite storage capacity, although not as markedly. For instance the Blythe Riversice example produces c. 54 W/m2 (24 average flow) at 9 kWh/m2 DNI (summer average), but on the winter average DNI of 5.2 kWh/m2  it produces 20 W/m2...meaning output efficiency falls 29%.

·      In general a region with a annual average radiation total of around 7+ kWh/m2/day is probably at the borderline of economic viability.  Under this level net output and LCOE cost seem to deteriorate rapidly.  This is supported by the IRENA cost review (Golem, 2012, p. 19), which found that the levelised cost of electricity in a region with an annual average of 5.8 kWh/m2/day is four times that for a region in which it averages 7.2 kWh/m2 day.  This is very important for renewable energy policy and proposals for large scale dependence on renewables.  It seems to mean that solar thermal will be confined to the very best regions and times of the year, and that it will not be a significant contributor in  other regions or through the rest of the year. This means that 100% renewable proposals will have to depend on wind and PV. (It is annoying that refusal of commercial operators to releae performance data prevents us from settling this important issue.)

·      It is not clear to me whether SAM is misleading regarding performance in low DNI, i.e., whether/how the model’s assumptions take into account the effect of differing patterns  of hourly DNI on efficiency etc.  Output conclusions do show marked falls in efficiency with reduced DNI, but whether the underlying reasoning is satisfactory is not evident.

The importance of this is not for an operator thinking about setting up a plant.  He can take SAM’s prediction of annual output and decide that it would be profitable, ignoring the fact that there would be days when it produced little or nothing.  But for an energy planner trying to work out how greatly to rely on solar thermal farms the gaps are crucial.  In the Auistralian case they indicate that there will often be periods in which we would need back up plant of a non-solar kind to substitute for upwards of all our solar thermal plant.

An illustrative case? The BZE Mildura assumption.

BZE proposes locating solar thermal farms at Mildura and similar rather high latitude sites.  The BOM dlimate region data enabled examination of likely output from Mildura taking into account only the above relation between kWh/m2/day and hourly average DN I (i.e., ignoring big gaps.)   The winter average DNI, 4.23 kWh/m2/day might suggest that .77 kWh/m2/day would be generated (i.e., at BZE’s assumed 17.8% efficiency), but when the diminished efficiency with lower DNI is taken into account a dish-Stirling unit at Mildura would generate only .077kWh/m2/day, one-tenth as much. However BZE assumes central receivers with storage.  Nevertheless CR efficiency at this low DNI level, and the much lower levels documented inthe above table, would be far below 17.8.

Note that Table 1 above does not take into account any effect of low DNI on output. It might give the impression that throughout a 4 day period in which radiation received averages 2.8 kWh/m2 day, electricity generated would be 2.8 kWh/m2 x (peak plant efficiency, ie., 14%?) = .39 kWh/m2/d or 16 W/m2.  But the above evidence on declining efficiency with DNI indicates that it would probably be at best around  half this level.  It is more likely that during this 4 day period few of the hourly DNI levels reached the minimum threshold for generation to commence.

Troughs.

Several sources show that the winter performance of troughs falls a long way below summer performance, to c. 14 - 40% of it.  (Odeh, Behnia and Morrison (2003, Fig. 2.) show c . 14% for the SEGS site.) This is due to unavoidable geometry given 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).  With a N – S layout annual output is maximised, which is what companies want.  An E – W layout raises winter performance, but not to a high value.

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.

In view of estimated global gas resources, troughs are 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 or no gas will be used.  In any case little gas is likely to be left late in this century.  The consequences of limited capacity to boost generation are likely to be greatest in winter.  However some propose use of biomass to produce the gas to fuel solar thermal turbines. (BZE, 2010, Elliston Diesendorf and MacGill, 2010.)  This makes sense but see below in the biomass discussion re problems, e.g., to do with efficiency, transport, quantities needed.

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.

The Australian National University “Big Dish”.

Lovegrove, Zawedsky and Coventry (2006) claim that big 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.

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.  Wizard Power is constructing a big dish plant in Whyalla, so figures on some of these themes could be available before long, (although companies tend not to release them.)

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.  Nevertheless Kaneff thinks storage via piping of heat from large scale dish systems is feasible.  However he reports (1991, Fig. 78) that at the White Cliffs 14 dish project when DNI was 700 W/m2 a surprising 34% of heat energy absorbed was lost between absorber and the nearby engine.  At peak insolation the loss  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. (…again 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, and the pipe used for storage would also transport the energy to the power block from dishes in a large field. 

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. 

This “Big Dish with ammonia storage” approach seemed to me to be the best until the NREL SAM package became available in 2010, and the recent Dunn, Lovegrove and Burgess (2011) paper seems to clearly rule it out.  The SAM examples give clear estimates of large scale central receiver solar thermal plant performance (athough we do not know if these will be accurate when large plants are constructed).   These figures seem to put central receivers ahead of dishes, and in addition the very substantial embodied energy cost involved in the ammonia storage proposal has only recently become evident.  In their  account Dunn, Lovegrove and Burgess state that to store the output of a 10 MW big dish plant for 28 hours via Ammonia would require 162 km of 30 cm diameter pipe  of 12.7 mm thickness, capable of taking the high pressure.  My personal communications confirmed the main figures and found that it would be more appropriate to assume 24 hour storage and thicker pipe in view of the likely corrosion caused by the gases.  The embodied energy cost of such a big amount of steel pipe would seem to clearly disqualify this approach.  It would amount to some 40% of total lifetime plant energy output.   It would seem that tank storage via salt or oil is clearly the best option.

                                                Central receivers.

Unfortunately little or no evidence is publicly available on the actual performance of central receiver systems. Around 2012 only two plants are in commercial operation, in Spain, and the owners will not release performance information.  Helyer, Mancini, 2010.)  However estimates of the likely performance  of large scale plant (200 MW) are given by Sargent and Lundy (2003) and more recently the NREL (2010, 2011) SAM packages, and by 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 2010) provides two examples stating that winter monthly output from a central receiver at a site (with 5/.2 kWh/m2/day radiation) would correspond to a continuous gross flow of  28 – 32 W/m2  .  When losses in long distance transmission losses, an assumed 10% embodied energy cost, and a 10 % energy cost for dry cooling (i.e., to save water) are taken into account the delivered figure would be around a net 21 W/m2.

It is not clear whether SAM takes into account the way low DNI reduces efficiency and output.  One would expect that it does but my attempts to get information from the modellers has not been successful.  It could be that they have because if  output inwinter is 28 W/.m2 and DNI is 5.2 kWhm2, then efficiency of generationis onlyh 5.6%, i.e., very low and in the region expected from the above discussion (...but maybe it is still too high because if daily DNI totals 5.2 kWhm2 not much of it would be over 400 W/m2 ... so maybe they haven’t taken the effect into account??)

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.

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 are few in number and 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 actually trebles the commonly accepted future. No approach to solar thermal plant along these “full accounting” lines seems to have been carried out.  (Personal communications with Manfred Lenzen and Robert Crawford.)  In general I have assumed a 10% embodied energy cost for solar thermal in the budget estimating below, which is probably too low.

Note also that net energy return ratios, payback periods and embodied energy costs must be estinmated in relation to a lifetime energy output figure, and the above discussion of the effect of DNI on efficiency significantly affects this.  It seems that unsually lifetime output is simply based on an annual average DNI figure for the site munltiplied by a single efficiency figure, when we saw above that if you take into account the fact that much DNI is well under the average value and sonme of it would be too low for anyh generation, lifetinme output would be significantly less than might have been thought.

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.

c)    Plant operating and management dollar and energy costs would have to be deducted from gross output.  I have not attended to these much and do not have confident general figures. 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 a systems embodied energy costs.

e)  “Transients.”  When clouds pass over a dish it can take 40 minutes for output to rise to previous levels.  (See the plots inSiangsikone and Lovegrove, ) 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 by Lovegrove 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 Lovegrove eta al have assumed in deriving the future estrimated  .19 annual solar-electricity efficiency figure.) 

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, due to the quantities to be stored as well as the time period.  (Although very big tanks have smaller surface area to volume ratios.).

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 possible, and opted for by BZE, but at an energy penalty variously stated as 7 – 10% of output for troughs. (IEA, 2009 says 7%.  Harvey, 2011, p. 5012, assumes 10%.  BZE assume  much lower dollar and energy cost figures.)

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 is important; 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.

Capital 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.  The main view seems to be that long term future costs will fall .by 50%, and 33% inAustralia, but some projections foresee rises in future costs (e.g., the CSIRO study by Hayward, Graham and Campbell, 2011.)

Predictions 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.

Easily overlooked is the fact that all the cost estimates for future renewable energy technologies 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, c. 2012.) 

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.

Dish-Stirling units are considerably more expensive than troughs or central receivers at present, 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.

It does not seem possible to be at all confident re Big Dish costs. Luzzi (2000) states that the cost of a Big Dish would be $440,000 but in future could fall to 33% of this figure.  However Hearps and McConnell report estimates of overseas future costs for solar thermal power plants are likely to fall by 50%, and that for Australian solar thermal construction the reduction would only be c. 35%. This aligns with Lenzen’s review (2009, Fig. 8.3.4, p. 119), but Hayward 2012 expects a cost increase for general solar thermal.  Unfortunately in view of exchange rate changes and inflation since 2000m, and lack of detailed support for Luzzi’s figure, it does not seem sensible to estimate a probable future figure, for the dishes, let alone the as yet undeveloped Ammonia process.   It seems that the very high embodied energy cost of the process (above) means that the best solar thermal option involving storage will be central receivers.

Central receiver costs.

Unfortunately the probable central receive future cost situation is not very 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 2020 figure becomes $6,072. 

The NREL SAM packages (2010, 2011) 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 well 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 2010, 2011 SAM packages.  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.  This is the figue I have used. However Hayward, Graham and Campbell, 2011 foresee cost rises in the long termfuture.

                        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 is usually done can be quite misleading.  What matters is variation in DNI about the mean, and therefore the minimum levels that will occur, and the magnitude of periods of low and very low radiation.  The latter is the problem of “big gap” weather events which the wind section above showed can be very problematic.   

Firstly, regarding simple variation, 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.  

The problem of big gap events for solar thermal systems seems to have been neglected, and it seems to be significant.  Even at the best sites there can be several days in a row of cloud.  Following is some relevant evidence.

·      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. 

·      Elliston, Diesendorf and MacGill (2012) report occurrence of periods lasting up to 9 days with very low DNI, at Australia’s best solar thermal sites.

·      My examination of Bureau of Meteorology weather data on hourly DNI for the eastern one-third +  of Australia (Trainer 2013) selected 6 good sites and tallied radiation received. To summarise, in the especially bad 92 day period from Sept. to Dec 2010 there were 12 occasions with negligible radiation for 3 or more days, totalling 48 days. The average DNI per day over these 48 days was only 2.3 kWh/m2.  If the very low efficiency of power generation at low DNI levels discussed above was added to the analysis it is probable that there could have been no output from the whoe six site system on any of these days.

·      A plot by AEMO (2012, p. 117, Fig 7 – 11) shows the problem for PV and solar thermal power.  At a solar thermal site that would average 40 MW in the long run, and peak at 76 MW, weekly output  over 8 years is estimated and represented, based onDNI data.  Output would often fall below 50% of the average 40 MW, and  on one occasion it was 2.6 MW.  This means that over a whole week the average output was only 6.5% of long term average system output, and 3.4% of its peak output.  Thus, for much of the time within that week output would have been well below 2.6 MW, and therefore negligible if not zero.

The AEMO 2012, Fig 7-10 plot for PV is better but similar, showing many weeks over that 8 years when output from the sector would have averaged around 35% of its peak weekly average output. Again these lows are weekly averages so had minute to minute output been plotted this would probably have shown periods  of hours or days when PV output was always much lower.

Even if gaps are small and infrequent theyseem to  mean that almost no “capacity credit” could be given for solar thermal plant.  There would be times when the total solar thermal input would have to be made up from some other source, so for every solar thermal plant built there would have tobe built capacity of some other kind to make its contrtibution when it could not do so.

Storage implications?

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.  The same conclusion is indicated by Foran’s (2009 p. 107) statement that the embodied energy cost of storage (presumably7 hr) is 1/7 that of the rest of the 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 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.

Troughs seem to be disqualified as major long term winter sources due to their poor performance in winter.  The performance of dishes storing heat via ammonia is not known yet, but the energy cost of the storage system seems to  be prohibitively high.

The best option would seem to be central receivers.  The winter rate of electricity production net of long distance transmission and embodied energy costs seems to be in the region of 20 - 23 W/m2, at a good site.     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.  Note that the Australian cost would be c. 50% higher.assumning the cost falls Hearps and McConnell report. 

Theser figures are not given with much confidence, but they do derive from the above output and cost evidence.

HYDROELECTRICITY.

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.

GEOTHERMAL ELECTRICITY

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. (http://www.greenhouse.gov.au/renewable/recp/hotdryrock/two/html)  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?)  Moriarty and Honnery 2011, p. 180) report the estimate that by 2050 geothermal sources might provide 10 EJ, possibly around 1- 2% of 2050 global energy demand.

In 2013 the prospects for hot rock geothermal eolectricity do not appear promising.  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 operating power station in Australia is at Birdsville.  The temperature is only 98 degerees C, and efficiency of generation is reported to be 6%. (Kimble, 2011.)

WAVE POWER

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 a mere  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.

                                                            TIDAL POWER

Harvey (2011, p. 317) reports global, tidal power potential at 239 GW, i.e., only 7 EJ/y, or about 1% of present world energy use.

                                    BIOMASS-GAS GENERATION OF ELECTRICITY.

Somer optimistic proposals assume that gaps in wind and solar energy can be filled by using biomass to generate electricity during those periods.  Briefly the problems are

·      Low gebneration efficiency.   El Bassam, 1998, reports the average efficiency of biomass electricity generation via steam turbines in the US at 18%.  The IPCC, 2011 Annex III gives four estimates, averaging around 30%. Harvey says efficiency is 14-28%, 2011, p. 202.  Farine, 2011, reports 27%, as does Foran, 2009.)

These figures only apply to the genetrating plant and to them must be added the other energy costs in the full process, including the energy needed to grow, fertilize, harvest, and especially to store and dry the biomass, and then to truck it to the generators, and finally to return ash to the fields.  This total would be considerable and would need to be subtracted from electricity produced. 

·      Generating electricity using gas turbines running on gas produced from biomass is probably considerably more efficient than burning the biomass to produce steam.  Diesendorf (2007, p. 144) refers to a 40% figure but this would only refer to the turbines and the energy costs of the full cycle are not known.  Especially problematic here is the relatively energy-costly process of producing the gas fromthe biomass.  This has been reported to have an energy efficiency of under 60%.

·      The difficulty of transporting and drying large quantities of biomass to generators. What quantities would be required? Biomass would be the major source of liquid fuel in  arenewable energy economy, and the discussion of biomass below shows that there would be far too little to run transport on it at anything like rich world levels.

            “BUNDLING INPUTS”.

The way to try to deal with intermnittent and variable inputs is to combine those that are available at each moment in  order to make up sufficient input into the supply system.  For instance as PV fades out in the evening hydro might be turned up.  The major problem here is that in order to be able to switch from one to the other source you need  a great deal of all sources.  When PV is contributing nothing at night, then some other source must be there in sufficient quantity to substitute for it.  When there is no wind you have had to pay for all those windmills PLUS enough generating capacity of sonme other kind to provide the energy the turbines were producing.  Thus at any one time you will probably have a lot of idle turbines, a lot of idle PV panels, a lot of idle hydro generators, etc.  These proposals usually show that there will be times when all of the above are still insufficient and you need to draw on biomass generated electricity, which is relatively inefficient, so there is a need for another large generating capacity, that will sit idle most of the time.  The 100% renewable supply system will include the capital cost of all this generating cacpacity that is not being used to its full capacity and will sit idle much of the time.

            The implications for redundant plant and total system capital cost.

An indication of the magnitude and seriousness of the this problem can be given by reference to two recent analyses put forward by groups who claim that 100% renewable supply is achievable. The study by Elliston, Diesendorf and MacGill (2012) claims to show how 100% of Australian electricity demand could be met by combining varying inputs from renewable.  The study is valuable in exploring the way renewable sources might be combined from hour to hour in an effort to meet demand, as for instance PV fades out in the evening and hydroelectric supply can be phased up. The study concludez that in order to meet an average 25 GW demand the amount of renewable capacity required would be 84 GW, 3.3 times as much coal, gas or nuclear capacity as would suffice. 

The second illustration is the modelling study by Hart and Jacobson, (2011) claiming to show that almost all of Californian delivered energy could be produced from renewable sources.  However Table 2 on p. 2283 reveals that to meet a 66 GW demand with low carbon emissions no less than 281 GW of capacity would be needed.  This would include 75 GW of gas generating capacity which would be required to plug gaps in renewable availability.  It would function a mere 2.6% of the time (p. 2283) and it will provide only 5% of annual demand.  This means 75 power stations would sit idle almost all the time.

Neither of these two analyses show that big gap events have been adequately provided for.  Elliston, Diesendorf and MacGill include a diagram indicating how renewable sources could be combined to meet demand through several days, but all of these days have considerable wind and solar energy input.  An accompanying slide report refers  to gaps of four to nine days in solar radiation at the best Australian solar thermal sites.

NREL (2012, 2 – 17) also reveal the magnitude of the problem.  Their high demand 2050 scenario for high penetration renewable electricity supply would require 16% of supply to come from gas.  The capacity to do this would have to be 360 GW, which would  be 42% of total capacity.   Evenif renewable were to provide only 30% of demand over time, there would still be a need for 360 GW of gas generation, which would be 35% of total capacity.  These are amazingly high figures.  In other words although gas would be supplying only a snmall proportion of electricity, this would be done in those periods when sun and wind were down and gas had to meet a large fraction of demand, meaning that many generators would then be needed, but would sit idle the rest of the time.

Note that these figures refer to the amount of plant needed to meet demand, but in the real world the amount of plant in a supply systemis much more than this, because a margin is needed to make sure that breakdowns and other problems can be coped with.  The Australian peak demand is about 34 GW, but total generating capacity is 51 GW.  (This is probably more than would be necessary.)

Any claim for high penetration renewable supply wishing to be taken seriously must base its provision on detailed long run information on wind and solar energy conditions, making clear the frequency and magnitude of big gap (and lesser) events.  It needs to show how much redundant back up plant would have to be built to enable supply to be maintained through these periods.

It is recognised that to go from say 80 or 90% renewable supply to 100% would be very costly.  A considerable fraction of the plant in a supply system is used very infrequently, just to meat seasonal peak demand, e.g., for air conditioning on the hottest few days, or to meet heating demand in mid winter.  Thus to cover the peak demand on one day of the year (i.e., .4% of demand) by renewables might require construction of 10% more plant than is required to meet the other 99.6% of it (approximate illustrative numbers only.)

“Well then, just use fossil fuel to meet those peaks.”  The problem with this is that the “carfbon budget” approach to the climate problem indicates that we must completely avoid all emissions, by 2050. (See Meinshausen, et al., 2008.)

The above situation means that in a system with high penetration levels much power would have to be dumped.  If for instance on average PV panels and wind turbines can provide 60% of electricity, then through hot windy days they will be providing much more than is needed.  Dumping lowers long term capacity factors and efficiency, and means less energy delivered for the capital cost.

            Levelised cost calculations can be quite misleading. 

The “levellised cost” of electricity production is the cost of producing each kWh taking into account all production costs and lifetinme output.  This is often used as if it settles the viability of a technology, but this fails to take into account the amount of redundant plant that might be needed to meet demand at all times, especially when there is no wind or sun for days.  To do this a system would need far more renewable plant than would be needed in the form of coal-fired or nuclear plant.  When there was no wind or sun all that plant would sit by idle while their contribution was made up by biomass-gas generation perhaps.   Thus total system cost might be veryhigh even though any of the technologies within it might be able to produce one kWh cheaply.  

GENERAL CONCLUSIONS ON ELECTRICITY

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.   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.

In the late 2000s electricity demand suddenly stabilised and fell, probably due largely to the GFC and rising prices.  Projections are therefore now uncertain.

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LIQUID FUELS

Only about 20+% of rich world final energy use is in the form of electricity; the biggest problem is how to provide liquid fuels from renewable sources.  Note that almost all renewable energy sources only produce electricity.  Biomass is thus the major option for the provision of liquid fuel, and the core argument below is that there would be far too little for the world to rise to rich world liquid fuel consumption levels.

There is a strong case that biomass cannot and should not 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 as a source of liquid fuel 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, a figure which is under 2% of the former “theoretical potential” figure.  As has  been made clear in the above section on technical potential, the high estimates are not intended to be realistic guides to what is likely to be achieved.  (Smil, 2011, p.111, regards these high figures as meaningless.)

            Plantations.

The IPCC 2011 says the average estimate for possible yield from biomass-energy plantations is c. 250 EJ/y. Harvey says the figure is typically 250 – 500 EJ/y. (2011, p. 256.)  The larg-scale review GEA, 2012, concludes that just over 200 EJ/y is likely from all sources, that is including fiorest and urban waste etc. as well as from energy crop plantations.  The 250 EJ/y figure is a huge amount, some 14 times more than all the energy in products humans are taking from the earth. (IPCC, p. 18.)

 Again considerable uncertainty surrounds these figures.  Harvey reports a study in which 535 million ha were found to be available for plantation biomass in Latin America, but only 41 million ha were judged to be “suitable”.  For Africa the figures were 740 and 27, for Asia 162 and 29.  Harvey says the total, 97 million ha,  is “...dramatically less than the plantation area assumed to be available in any of the studies that he lists in his p. 264 table. (See section above on the different terms used when discussing potential.)

The IPCC is referring to “technical potential” (i.e,., not including ecological and social factors) and makes the crucial assumption that no more forest, cropland or grazing land will be needed to meet food etc. demand. (This is said on p.13 of Ch.2.) This is almost certain to be wrong, given the present and increasing food crisis and the need to double production.  The IPCC reports studies concluding that under plausible conditions that could emerge there would be no biomass at all available for energy production.. 

The 250 EJ/y average figure the IPCC reports involves an extremely large land area, just over 1 billion ha. (all cropland is only 1.4 billion ha.) assuming 13 t/ha/y yield as they do.  That yield is probably double a realistic figure given that very large areas of marginal land are to be used.

Thus it would seem to be highly implausible that anything like 250 EJ/y can be produced by biomass energy plantations.

Residues and wastes.

The global estimates the IPCC reports for crop wastes, forest wastes and urban waste that could be harvested for biomass energy production lie between 40 and 157 EJ/y. Again it is not clear whether the rough average, 100 EJ/y, refers to theoretical, technical or economic potential, but it is likely that the achievable figure is considerably lower.

Diesendorf (2007, c. p. 140) reports a study estimating that Australia could collect 24 million tonnes p.a. (dry weight), which might generate 150 PJ/y or one-fifth of electricity (he says one-third.)  However this assumes taking two-thirds of crop wastes and leaving 1 t/ha (i.e., .5 t/ha dry weight), in addition to removing the weight of the crop. Again some people insist that no carbon should be removed from our carbon-depleted soils but this strategy would be removing c. 80+% of annyual growth.

Yield limitations.

Following are the main reasons for thinking that a realistic biomass energy yield will and should 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. More importantly, in the growth phase much water would be transpired. Trees are used to lower water tables in salty regions.  The IPCC (p. 24) reports studies finding that stream flow can be cut by 50%.
• 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.
• Crutzen et al. (2008) argue that deriving energy from biomass plantations will actually increase adverse climate effects by the release of N2, a previously overlooked factor.
• If an area of trees are cut periodically and regrown this means that the average amount of carbon that area has removed from the atmosphere over time would be half tha amount it would remove if left as mature forest.
• 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.  Biomass plantations would tend to use a few high yielding species, thus significantly reducing bio-diversity of original grasslands or forests.
• 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 serving needs 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 c.  350 EJ/y the IPCC reports as the average of the plantation plus residues estimates it reports. 

The common biomass yield per ha assumption of 13+ t/ha/y, made (reported) by the IPCC (Ch. 2, p.  23) also seems to be quite unrealistic.  It is easily achieved in good conditions, such as willows on cropland, and with 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.  Smil (2011, p. 114) points out that a 15 t/y yield would require 100 kg of nitrogen fertilizer per ha, and this would impose a very big global energy cost if  biomass was to be a major contributor.  A more biomass-energy realistic yield figure might be 7 t/ha/y.  Foran and Crane, 2002, appear to assume 6 t/ha/y.   Foran 2009 p. 57, says 7 – 9t/ha come from the fertile Illawarra region of NSW but 4 – 5 t/ha/y is more likely from the sheep and wool regions where large scale biomass energy production would centre.  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.

            Liquid fuel yields?

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 I have assumed in my analyses 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.  To provide the 9+ billion people we will probably have on earth by 2060 we would therefore need 24 billion ha of biomass plantations...on a planet with only about 8 –10 billion ha of productive land, most of it presently overstressed.

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.

            Algae?

The potential in the harvest of algae has often been raised, given the very rapid growth rates some of them have.  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.  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. (“Closed loop” systems taking power house gases into algae ponds to produce fuel to generate power would be different; see difficulties in algae below.  Not all CO2 created can be extracted from gases, so there would be emissions, and the “carfbon budget” approach now indicates that all emissions must be ceased by 2050; see  below, and Mienshausen et al, 2008.)

Chris Mardon who worked on biomass energy at the CSIRO says a major problem with the processing of algae is how to get the water out of the biomass.  Another is that they need nutrients in addition to carbon; where do you get the large quantities of nitrogen and phosphorus they wold need?

            Australia’s situation?

The Australian renewable energy situation differs from most countries  because we have much more sun, good wind and around 5+ times the amount of useful land per person than the world average.  However Trainer 2012b 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.

Our prospects would depend considerably on how much biomass we could use for energy production, (especially as back-up for electricity generation during periods of poor wind and sun),  and the estimates seem to be very unsettled.  The following extract from Trainer 2012b summarises estimates found.

 The highly unsettled state of the field is noted by Farine et al.,

(2011) and is evident in the range of estimates given. (IPCC, 2011, Harvey,

2010.) For example, Smeets and Faiij, (2007), arrive at 1,500 EJ/ for the global

“technical” potential”, whereas at the other extreme Field, Campbell and Lobel

(2007) conclude that when social, economic, moral/justice and ecological

considerations are taken into account the figure is only 27 EJ/y. An examination

of such analyses reveals the large difference there can be between “technical

potential” and plausible harvest in view of the combined limiting factors. The

World Wildlife Fund’s Energy Report, (2010), refers to a number of studies in

which the ratio is 1/5.  Although Australia is much more favourably situated regarding potential biomass energy resources than most countries, having around 5 times the world averageamount of productive land per capita, the little evidence available does not seemto yield a clear or agreed figure for possible Australian celulosic yield. Stewart et al. (1979, 1982) estimated that 26 million ha might be available for biomassplantations. Foran (2008) discusses ethanol and methanol produced on 30 – 45 million ha with average yields of 6 – 7 t/ha, and Foran (2011) assumes harvesting 58 million ha., but the availability of such areas is not established in these papers. The former area indicates a yield of up to 300 million tonnes, while the latter indicates 380 million tonnes. Foran (2008, p.57) notes that the fertile Illawarra region can average 7-9 t/ha/y yield but for the wheat and sheep zone (where large biomass production would have to mostly be located) the average is 4 - 5 t/ha/y. Diesendorf (2007) states a yield of 292 million tonnes (although he seems to rely on Foran’s data so this is probably not an independent estimate.).  Moghtaderi, Sheng and Wall (2006) estimate a 160 million tonnes harvest.  O’Connell et al. (2007) estimate 220 million tonnes p.a. Farine et al., (2011) arrive at 97 million tonnes p.a.  AEMO (2012a, p. 5) give 96 million tonnes as the 2050 potentially abailable quantity.

AEMO notes the high variability of  biomass yield from season to season; often grass harvest for biomass energy production would be zero.

These reports include little or no evidence or derivations in support of the areas or yields stated. The areas are large, compared with Australia’s c. 22 million ha of cropland, approximately 50 million ha of cleared agricultural land (Foran, 2011), and 2002 total coal production including exports of around 300 million tonnes. (Foran and Crane, 2002, p. 107.)

Conclusions?

Given that world primary energy demand has been heading towards 800-1000 EJ/y by 2050, even 400 EJ/y from biomass 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, and the figure is likely to be much lower than this. Note that the 400 EJ/y figure is for primary energy and this would yield only around 130 EJ/y of ethanol (or electricity.) 

Sun and wind only produce electricity, which is only 62/3500 or around  a mere 2% of world final energy used today.  This means that the vast bulk of energy needed is not in the form of electricity, and biomass is (almost) the only renewable energy source that can provide non-electrical energy.  Even in Australia electricity is only 20% of final energy used (700PJ/3500PJ/y).  Biomas is not going to provide anywhere near 80% of the present c. 350 EJ/y world final energy demand, let alone 80% of the 2050 demand we are heacing for, let alone the 3,500 EJ/y demand that wouold exist if 9 billion people nloived on the use levels Australians were recently heading for (twice early 200s levels.)

   ------------------------------------------------------------------------------------------------------------------

                                                            CAPITAL COST SUMMARY.

Estimates can vary considerably unfortunately.

Present cost.                    2050 cost.                       Fall or rise expected.        Source.

Wind.

Onshore  2579           2600 (but also says 1813?)          increase? *                        1

                 1980           1980                                               no fall                              2 (A-9)

                                                                                                                                                                             1980               1776 at the best, class 7, US sites                                        2 (F – 8,

                                                                                                                                  p. 367.          

Offshore 4538,           4574 (but also says 4040?)             no fall                            1.

                 3640           2990                                                                                       2 (A-9)                       

PV

Utility 3822                 1584,1544                                     60% fall                            1

                                    1690                                                                                      2 (A-9)

          4790                  2620                                                                                      2 (A–1)

            Solar thermal.

          8282                  3811, 4414                            average of these is.

                                                                                  a 50% fall                             1

                                                                                  33% fall (but ref. to

       a 64% fall estimate)             2 (A-9)

            7060                4700                                       33% fall

            6300 – 7,500 (6 hr storage)                            no fall in capital cost ,         3

       Fuig. 6.1, but 50%+ fall

       in LCOE (??)                                                                      

            9,000 – 10,500 (12 15 hr storage)                                                               3

There has been only a slow

fall with trebling of global

cumulative  production.       4

Biomass electricity.

5123                 5527                                       increase.                             1

            3830                 3830                                       no fall                                   2 (A-9)

            Pumped storage, incl. regeneration.

            2100 (5595 in one quoted estimate                 no fall                                  2 (12- 22)                                                 

            (12-17, 12 - 22)                             

           1500 – 2000 (stated 12 – 22)

            Compressed air.

            900                                                                  no fall                                   2.

                                                            ---------------------------------------------

·      It is stated (11–6) that the cost rose by one-third between 200 and 2010, and that offshore costs rose  by 67%

Sources:

1.    AEMO, 2012, Table 5.

2.    NREL, 2012, Table A – 1, p.169.

3.    S. Guilen, 2012,  Renewable Energy technology – Cost Analysis Series. , June.IRENA.

4.    Hayward, J.A, Paul W. Graham and Peter K. Campbell, 2011.

OPERATIONS AND MANAGEMENT COSTS.

Wind

O and M costs add to 20-25% of  total lifetime cost.  (NREL, 2012, 11 - 15.)

GEO-SEQUESTRATION OF CO2.

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 probably be the only fossil fuel available in significant quantity after 2050, although some think it might not be available before then.  Recent gas discoveries cloud the picture.)

Geosequestration can only be applied to stationary sources (so not to vehicles), and only about 50% of emissions p.a. come from stationary sources, e.g.,power stations. 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%.

Thus if we took the greenhouse problem seriousoly we would eliminate all burning of fossil fuels as quickly as possible.

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 years since the report the observed warming effects have been much greater than was expected.  All trends seem to be 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 and others 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 totally eliminated by 2050.  This means that if geosequestration cannot cvapture and store 100% of emissions from a power station then it cannot be used at all.

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%

             “Safe”

Emission

Quantity.

           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.  But 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 only 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%, Foran , 2009, reports 39%. .)

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.   Harvey (2011, p. 422) completely rules out deep ocean storage, saying that in time significant quantities would find their way into the atmosphere.  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.

Harvey says the limit would be c. 500 GT of carbon, meaning that at the present rate of emission capacity would be used up in 60 years. (2011, p, 422.)  Moriarty and Honnery, (2011, p. 154) say estimates of useful sites are declining. 

Other sequestration options?  Morarty and Honnery, (2011 p. 152) say that capturing CO2 from air would take much more energy than was produced by the creation of the associated amount of carbon.

It would seem therefore that CCS is not likely to be a major contributor if strict greenhouse limikts are observed.

THE ENERGY STORAGE PROBLEM.

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.)

The more a system involves renewables the greater will be the need for storage, and the increase can be steep. (NREL, 2012, xxxix)

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

Pumped water storage.

This is the technology that sets the  main challenge to my positon on renewable energy...could  it be implemented on a sufficient scale to solve the intermittency problem?

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 major limit is to do with the potential capacity compared with demand.  World hydro-electric generation meets only about 15% of electricity demand, and the  present 10.7 EJ/y 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 short period in Australia. 

Mackay (2008, p. 232) reports European capacity at 67 GW, which is remarkably small for a hilly and wet region, and nowhere near sufficient to get Europe through days without sun or wind. However this does not indicate how much pumped capacity might  be  buildable. 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.

NREL (2012, 12 – 22) states a surprisingly low potential for the US, 35 GW (electricity consumption in the US is c. 500 GW), at a cost of $5595/kW. (Their discussion seems somewhat confusing, probably due to variation in estimates.)

Reference to hydro electric capacity 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.  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.  Nevertheless Seligman (2012) argues for the construction of many new sea water systems around the coast, and AEMO (2012) lists 68 sites as having “technical potential”.  This is not very meaningful; see below on the many considerations that typically greatly reduce what’s technically doable to what makes sense after all social, ecological, cost etc.  factors have been tgaken into account.  The capital cost Seligman arrives at is not high, to provide the equivalent of all 25 GW average national demand for 20 hours. Europe can have no sun or wind for a week or two.

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

W.  He points to the many conditions that must apply for a site to be feasible, including short distance between high and low dams, a high upper dam site, the lack of sites, and the high cost.  He regards Seligman’s proposal highly unrealistic, to put it politely.  He points to the conditions needed for a viable plant, which would be rare in Australia.

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; i.e., to it habving been kept too full.   The subsequent inquiry ruled that it should be kept at 85% 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. 

Another problem is that input from sun and wind varies considerably most of the time, and this is not good for pumps and systems, and lowers their efficiency. 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.

Note that the cost includes constructing a dam and a power station, which is added to the cost of generating the electricity in the first place, e.g., by wind.

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 www.vrbpower.com.)   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...early 2000s figures, more now.)

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.  NREL (2012, 12-19) say it is unproven on a larger scale and research into cavern properties is needed, and they state capacity at (only) 120 GW x 15 hours (12-25), which is equivalent to US demand for only 3.6 hours.    This would make a significant contribution to the integration  task, but would not get supply through a continent wide big gap event.

NREL say the cost would be $800 - $1200 per kW, which means that adding it to a wind farm would increase its cost by 50%.  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.) These are big volumes.   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 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.

The gas could be produced from biomass, but this involves problems discussed in the liquid fuels section above, especially re quantities.

Ammonia dissociation.

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 was explained above that this approach would involve very high plant embodied energy costs for the high pressure containing pipe, for 24 hour storage, let alone 4 day storage.  

            Flywheels

These seem to be  a very long way from being able to store the quantities required to back up renewable sources.  ? et al. report 100Wh/kg, and a loss of 20% at least of energy per hour Hadjipaschalis et al, 2009.

            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 then 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. (Bryce, 2011, p. 195 says 4 hours to charge 53 kWh in a Telsa, i.e., equivalent to only 4 litres of petrol. Battery swap systems would avoid the recharge delay...but double amount of battery material needed.)

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 quickly  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 when he provides electricity to the grid from his battery is he to be paid the same as suppliers such as power stations,  4 c kWh,?  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.

          Capacitors.

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.

Super capacitors have very low power density and deliver high power for only a very short time, and must be very bulky. They are very costly; $20,000/kWh. (Hadjipaschalis, et al, 2009.)

            Hydrogen.

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 valves 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 road 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 4.3.3.2.)

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.

The AEMO (2012, 12 - 7) study of renewable potential assumed that  hydrogen was too costly to consier. They noted that efficiency might only  be 28%, and regeneration of electricity after storage as hydrogen is very costly.

CONVERSION LOSSES

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 2000 PJ and when this is combined with the 700

PJ 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 still 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.

TRANSMISSION LOSSES AND COSTS.

For very large scale production of renewable energy solar thermal and PV farms will have to be located at the most favourable regions which will be deserts and thus will involve long distance transmission.  European supply from solar thermal fields will probably have to be via several thousand kilometre long HVDC lines from North Africa and the Middle East.  Losses in the vicinity of 15% are likely, along with another c. 7% for local distribution.  (Mackay 2008, Czisch, 2004, Breyer and Knies, 2009, NEEDS, 2008, Ummel and Wheeler, 2008, and Jacobson and Delucci, 2011.)  My cost estinmates assume a 15% loss for long distance plus local distribution.

RENEWABLES ARE ALTERNATIVE NOT ADDITIVE.

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.

                                                            PLANT LIFE TIME.

The most common assumption for the lifetime of renewable plant seems to be 25%.  Sometimes 30% is assumed, and sometimes 20%, which is the IEAs (2008) figure, and that given in the IPCC 2011 Working Group 11 report on renewable energy, Annex 111, p. ). For hydroelectric plant a 70 year lifetime is commonly assumed.

                        CAPITAL  COSTS  per  DELIVERED  VS  per  PEAK  WATT.

It is easy to overlook the significant difference between peak and average delivered output from renewable sources.  Over a year a coal-fired power station will deliver at around .85 of its peak rating, but even in good locations, for wind the figure is around .3 (the world average is .23), for PV about .2. and for solar thermal about .2.  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 for the plant needed to deliver a  kW delivered throughout its lifetime.  But if you build a windmill knowing that the capital cost is $2,000 per kW(p) you will actually be paying $2000/.33 = $6,000 for the amount of plant needed to deliver a  kW throughout its lifetime.

In addition it is important to work with net output, i.e., gross generation minus the energy costs of transmission losses and theenergy needed to construct the plant.

Most important is the fact that the levelised cost of energy from a technology tells us nothing about the amount of redundant plant needed in the system to cover gaps in the availability of renewable energy.  Wind has a relatively low levelised cost, but the system of which it is part could be very expensive if it must include enough biomass-gas-electricityh plant to cover for wind when it is negligible.  What mattersis total system cost

NUCLEAR ENERGY?

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, again 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 and others argue that the energy cost of retrieval would be greater than the energy contained.

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.  (Abbott analyses materials problems for nuclear energy persuasively.)

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.  The case seems to be inmpressive and I can’t assess its plausibility but following are some of the issues on which we would need clear and convincing explanations  and very high agreement among the experts.

·      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.

·      What is the energy cost of plant, including the IFBR, 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.

·      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??)

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

·      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.)

·      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?

·      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.

·      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.

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

·      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.

CAN IMPROVED ENERGY CONSERVATION AND EFFICENCY SOLVE THE PROBLEM?

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 and cooling.  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. Moriarty and Honnery (2011) think a trebling is possible.

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.

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.

A  CAUTION  ON  ‘TECHNICAL  POTENTIAL/ADVANCE’  CLAIMS.

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.  In addition enthusiastic claims about technical potential typically confuse the following factors, which are kept clear in engineering and economic literature. (See Diesendorf, 2007, IPCC, 2011, Ch. 2.)  These distinctions indicate that there can be an enormous difference between what might be do-able, and what it will be sensible to do in the real worlde.

• “Theoretical potential”, which refers to what could be produced or done without regard to any other considerations such as cost, other uses, social or environmental constraints, etc.  For example, the theoretical potential global biomass-energy yield is about 160 EJ/y, because that is the total amount of plant growth on land.  Obviously the amount that could be harvested for energy production at an acceptable monetary, energy and environmental cost would be a very small fraction of this.

• “Technical potential”; i.e., what might be achieved allowing for the fact that there are other demands on the theoretical potential; e.g., much land is used to grow food and timber. Future possible demands from other sources need to be considered  here; e.g., the IPCC notes that the  biomass-energy technical potential assumes no increase in demand for land for agriculture etc., which is certainly not going to be true.

• “Economic potential”; i.e., what could  be  done within technical potential at an affordable cost.

·      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. 

• “Ecological potential”.  Then there will be reductions in what might be achieved due to provision for environmental  effects, e.g., leaving land for nature rather than taking it for biomass energy production. For instance the WWF estimates the environmentally acceptable area would be about 250 million ha, and the IPCC (2011) assumes 780 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. Compare these figures with the theoretical potential figure from Smeets and others which is around 4+ billion ha, and the technical potential for is 1400 million ha.  Field, Campbell and Lobel (2007) argue that when all the above factors are taken into account world biomass energy production could only be 27 EJ/y...a very long way from 160 EJ/y.

• The socially acceptable achievement.  This is another significant reducing factor. For instance 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 achieve. Claims are usually about theoretical potential and often this is far higher than a realistic achievement when all complicating factors are taken into account. For biomass-energy the ranges for estimates are very big.  For instance the yield which Field, Campbell and Lobel arrive at is 58 times as big as the Smeets and Faiij figure for the theoretical potential.

A similar note of caution attaches to ‘learning curves”; i.e., claims about the rate at which costs will fall in future, due to mass production and technical advance.  As Harvey says, for renewable these can only be “highly speculative.” (2011, p. 153.)  This is specially so for solar thermal where the best systems have not be decided yet, and will involve far bigger capacity than present systems. Note that claims about future reduc tions in cost refer onhly to technical advances and do not take into account likely significant future rises in materials and energy costs of production.

ATTEMPTING A GLOBAL ENERGY BUDGET

My view that the world cannot  be run on renewable energy is based on the conclusion that the capital costs would be much too high.  Following is the kind of numerical case that seems to me to be the most valuable in sorting the issue out.  The figures and assumptions used here are somewhat crude and simplified and the exercise is only meant to be indicative of the magnitude of the problem.  .  A more careful analysis can be found in http://socialsciences.arts.unsw.edu.au/tsw/CANW.htm

. 

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                                                                    

           *   (Estimates seem to average a little below this figure; Money and Honnery,

                2012.  The IPCC estimates 1000 EJ/y, 2011.)

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 4.3.3.2), 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 $658 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 renewables, e.g, IPCC, 2011, Annex 111, p. 11, IEA, 2010. My more recent attempts assume 30 years.)

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 early 2000s amount of world annual energy investment, $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 arrived at via the above table.

            THE EFFECT OF CAPITAL COST ON RETAIL PRICE.

The main concern above has been with the capital cost of renewable, and whole systems (with their large amount of redundant plant.)  This does not make clear the effect of higher capital costs on the price paid at the retail end.  This would include the effects of factors such as profit, insurance, transmission and distribution costs, and plant operations and management.  I am not in apposition to estimate what retail prices might be in renewable energysupply systems,  but there is reason to suspect that they would be much higher than might be thought in view of the increased capital costs.

The retail cost of electricity in Australian in 2012 is around 22+ c/kWh.  The capital cost of plant plus fuel comes to about 2 cents (AETA, 2012, p.17) and distribution accounts for around half of the retail price.  Thus factors such as profit, insurance, taxes and interest charges more or less multiply the capital plus fuel cost of the production of electricity by 6.  Expenditure on energy in rich countries comes to about 6 – 9% of GDP, and Murphy (2010) reports that when energy expenditure rises to 10% of GDP recessions occur. The above derivation found that the capital (plus fuel) cost of renewable supply might be 10 times the 2000s cost even though many factors that would multiply this figure several times were not included.  If factors such as profit, insurance and taxes further multiplied the figure by 6, the retail price of electricity would be far beyond affordable, and energy would be accounting for far more than 10 % of GDP. 

This is why, as noted above, the ”levelised cost” of renewable eneergy can be highly misleading.  Yes each average  kWh from a windmill averaged over its lifetime will cost very little, but the capital cost of a system in which there are enough windmills, etc.,, and other plant to back them up when there is no sun or wind for a week, will be very high, and when other factors such as grids, insurance, O and M, profit and distribution costs are added to (or multiplied by) that initial plant capital cost, the total system cost per kWh actually delivered will be far higher.

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” or suppoy side 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.

AIM  ONLY  FOR  80%  RENEWABLE  SUPPLY?

A suprising amount of generating plant is needed to ensure that demand can be met at those few hours in the year when demand peaks.  Would it therefore make sense to design a much less costly renewable system capable of meeting demand 80% of the time, and resort to some other sources for the rest?

The first problem here is that we are very likely going to have to totally eliminate  all carbon emissions, and if so renewables will have to provide 100% of supply.

A related suggestion has been that we should not insist on 100% reliable supply.  Third World countries get by without it, accepting blackouts for some hours now and then.  The problem with this is that the intermittency of wind and sun means that although your annual supply of renewable energy might be 80-90% of what you’d like, the gap will include times when there is no energy at all, because there’s no wind or sun in your region.  To cope  with those gaps you would need a great deal of redundant or bakcd up plant.

INCREASED DIFFICULTIES WILL INCREASE ENERGY NEEDED PER UNIT OF OUTPUT.

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, 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 increase in demand, raising future supply targets above the levels that might be imagined when one focuses only on  the present supply task.

THE “EROI” FOR RENEWABLES WILL FALL IN FUTURE?

Moriarty and Honnery (2012) make the important point that efficiencies for renewable energy systems assumed today will fall in the longer term as output is scaled up dramatically, because less favourable regions and sources will have to be used as the best ones are taken first.  In other words, the energy return on energy invested in enewable technologies will fall.  In addition scaling up will put pressure on resources and costs. For instance if the probable future 1000EJ/y energy demand was to be met by renewables we would need about 100 times the present amount of non-biomass plant.  Moriarty and Honnery also point out that deteriorating environmental conditions will reduce renewable output, e.g., a reduced temperature gradient between poles and equator will weaken wind speeds,  extreme weather events will curb wind output, hotter conditions will affect biomass production.

                                    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  (although 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 fundamental “limits to growth” point is 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.

                        THE MORE GENERAL LIMITS TO GROWTH PROBLEM.

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, especially biological resources such as fish.)

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.

IF THEY GET ABUNDANT ENERGY THEY WILL USE IT.

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.  However Seligman argues that Australia could develop huge pumped sea water storage capacity and this claim  needs to be assessed thoroughly; if valid it would invalidate my analysis of the Australian situation.  Might there be surprising advances in battery technology? 

The most promising strategy for the renewable optimist is solar thermal central receivers in deserts with heat storage tanks, plus huge HVDC grids several thousand km long. The DESERTEC and MENA proposals consider huge solar  thermal and PV farms in North Africa and the Middle east (see above.)  However in the solar thermal discussion above it seemed that evenin the best regions wint4r supply will be problematic for solar thermal.  Possibly more importantly if these farms are to be capable of maintaining Eyuropean electricity supply through one or two weeks of cloudy and calm and extrenmely cold weather, the storage capacity would have to be tens of times greater than currently envisaged for ST (see above re ST internmittency)….and the supply grids would have to be very large.

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…)  And then there is still the the problem of where to get the c. 80% of energy that is not in electrical form.

Oversize components greatly, so that some will still meet demand when sources are low, and dump excess at other times, or store inefficiently…?  Some oversizing makes sense, but is capital-costly, and would reduce but not eliminate periods when there is a gap, (unless the oversizing is enormous).

The best option for those who wish to keep the party going is to believe that the Integral Fast Breeders can provide abundant energy, for all-electric economies?  See above for problems that would have to be solved.

THE REQUIRED RATE OF DEVELOPMENT?    THERE ISN’T TIME.

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.  The capital investment cost derived via the above budget discussion would be perhaps 40 times current world energy investment p.a., during the building period. (i.e., assuming $20 billion per solar thermal power plant capable of 1000 MW continuous winter output.)

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.

ONE NATION CAN’T DO IT ON ITS OWN.

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.

OTHER CRITICAL ANALYSES.

There have been remarkably few critical analyses of the potential of renewable energy.  I am aware of;

• Bryce, R., (2010), Power Hungry, Public Affairs, New York.
• Hayden, H., The Solar Fraud, 2004. Second, edition.
• Mackay, D., Renewable Energy Without the Hot Air.  This is a very valuable review of technologies, not primarily focused on potential, but at the end he discusses 5 scenarios for Europe, conclding that renewable energy can’t provide enough energy, unless solar thermal in North Africa is used.  The discussion of solar thermal is not detailed and does not go into the problems.
• Moriarty, P.,  and D.  Honery, The Rise and Fall of Carbon Civilization. 2011 Springer. (Valuable lengthy discussion of difficulties; clear statement p. 80.)  See also their short paper, 2012.

                                    THE MANY CHALLENGEABLE CLAIMS.

There are many claims that renewale energy can power the world, including some impressive lengthy reports from prestigesus agencies.  I have examined several of these and found them to be unsatisfactory.  Critiques can be found under Renewable Energy in the alphabetical list at http://socialsciences.arts.unsw.edu.au,/tsw/ The reports considered are, briefly, Greenpeace, ZCA, ZCB, Jacobson and Delluchi, Elliston, Diesendorf and MaGill, IPCC 2011, and Global Energy Assessment.

THE ANSWER?

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 in my  2010 book The Transition to a Sustainable and Just World, Envirobook, and at The Simpler Way website, http://socialsciences.arts.unsw.edu.au/tsw/.  A much earlier statement of the case was given in Trainer, 1985.)

These analyses show consumer-capitalist society to be 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.

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.

WE  MUST  SWITCH  TO 100% DEPENDENCE  ON  RENEWABLE ENERGY

 AS QUICKLY AS  POSSIBLE!!

The foregoing has not been anarguent against transition to renewable energy; it has been an argument that we cannot run energy-intensive societies on it.

The focal concern in The Simpler Way project is to move to ways, values, institutions, economies, settlements etc in which we can live well with  extremely low resource and ecological impacts.  Only by dramatically reducing demand can we hope to defuse global problems.  The Simpler Way would enable energy needs to be met by renewable sources.

                                                -----------------------------------------

Appendix; Critiques of renewable energy claims:

Papers I have written critical of reports claiming the world can run on renewable energy.

A critique of the IPCC on the capacity of renewable energy to mitigate the greenhouse problem, published as Trainer, T., (2010), “A critical discussion of the Stern and IPCC analyses of carbon emission mitigation possibilities and costs, “ Energy & Environment, Vol. 21, No. 2, 49 – 73.

Critical comments on Zero Carbon Australia, M. Wrignt and G. Hearps, Melbourne Energy Institute, 2020. This report argued that Australia could be converted to run entirely on renewable energy by 2020. The critical 5 page commentary argues that the report is a valuable contribution to the discussion but its assumptions are highly challengeable and its conclusion is not valid. (2010.)

Critical Comments on The Energy Report by WWF and Ecofys.

GREENPEACE Energy (R)evolution Report; A Critique. This report has been influential, being the core reference in the IPCC's 2011 report which is being taken to show that renewable energy can meet most of the world's 2050 demand for energy. This critique details reasons for regarding the Greenpeace report as making little or no contribution to the issue, not establishing its claims, and of giving a mistaken impression re the potential of renewables.

A critical analysis of the 2011 IPCC Working Group 3 report on the potential of renewable energy. This report is being quoted as establishing that renewables couldmeet most of the world's energy demand in 20-50. This critique agrgues that the report does not establish this, and is quite unsatisfactory for a number of other reasons.

"A critique of the proposals by Jacobson and Delucchi for world renewable energy supply", (Published in Energy Policy, 2011, 44 (2012) 476–48.1

Jacobson and Delucchi replied to this critique. For a reply to their reply see "100% renewable supply? Comments on the reply by Jacobson and Delucchi to the critique by Trainer.", Energy Policy, (detail?) 2012.

Critical comments on the Elliston, Diesendorf and MacGill paper, 2012, arguing that renewables could provide Australian electricity.

Some critical notes on the Global Energy Assessment’s Renewable Energy chapter.

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AEMO, (2012a), 100 per cent Renewabledsd Study. Modelling Assumptions and Inputs.

Alpert, J. L., and G. Kolb, (1988),  Performance of the Solar One Power Plant As  Simulated  by the SOLENERGY Computer Code, Sandia National Laboratoreis, Alberquerque.

Australian Solar Radiation Data Handbook, (ARDHB, 2006), ANZ Solar Energy Society, April, Energy Partners.

Augenstein, D. and J. Benemann, (2007), The Cellulosic Ethanol Delusion, http://www.aiche-norcal.org/.Symposium/Symposium2006/pdfs/EnergySolutions.pdf

Australian Bureau of Agricultural Economics, (ABARE), (2006), Technological Development and Economic Growth, Jan. 12.

ABARE, 2010 lang

Bach, D. F., 2011.  Wind power in Denmark, Germany, Ireland, Great Britain and France, Statistical Survey.

Baer, P, and M. Mastrandrea, (2006), High Stakes; Designing Emissions Pathways to Reduce the Risk of Dangerous Climate Change, Institute of Public Policy Research, Nov.  www.ippr.olrg. See Rising Tide Australia; 2007,  http://risingtide.org.au/cleancoal

Barker, T., et al.,( 2007), Working group 111 Contribution to the Intergovernmental Panel on Climate Change Fourth Assessment Report, Climate Change 2007: Mitigation of Climate Change, Summary for Policy Makers.

Barry, P., (2008), “Carbon sequestration frustration”, Science News, Aug. 13th.

Black, R., (2006), “Sea energy could help power UK”. http://news.bbc.co.uk/2/hi/science/nature/4645452.stm

Blanco, J., 2010, Head of Environmental Applications of Solar Energy, Platforma Sollar de, Almera, Spain.  Personal communication.

Bossel, U., (2003), “Efficiency of hydrogen fuel cell, diesel-SOFC-hybrid and battery electric vehicles”, European Fuel Cell Forum, Morgenazvcherstrasse2F, CH-5452 Oberrohrdorf.

Bossel, U., (2004) “The hydrogen illusion; why electrons are a better energy carrier,” Cogeneration and On-Site Power Production, March – April, 55 – 59.

Bossel, U., (Undated), “Towards a sustainable energy future”, www.efcf.com

Breyer, C and G. Knies, (2009), ‘Global energy supply of concentrating solar power”, Proceedings of  Solar PACES, Berkeley, Sept, pp. 15 – 18.

Coppin, P., (2008), Wind energy, in P. Newman, Ed., Transitions, CSIRO Publishing, Canberra

Coelingh, J. P., 1999, Geographical dispersion of wind power output in Ireland,

Ecofys, P.O. Box 8408, NL – 3503 RK Utrecht, The Netherlands. www.ecofys.com.

Coppin, P., (2008), Wind energy, in P. Newman, Ed., Transitions, CSIRO Publishing, Canberra.

Crea, D., 2004, “Twenty hydrogen myths; a Physicist’s Review”, http://www.theraht.info/archive/001289.html

Crutzen, P. J., A.R;. Mosier, K. Smith, and Winiwarter, (2008), “N2 production from biomass negate release from agro-fuel production negates golobal warming reduction by replacing fossil .fuels”, Atmospheric Chemistry and Physics, 8, 389-395.

Czisch, G., (2001), Global Renewable energy potential; approaches to its use, http://www.iset.uni-kassel.de/abt/w3-w/folien/magdeb0030901/

Czisch, G., (2004), Least-cost European/Transeuropean electricity supply entirely with renewable energies”, www.iset.uni-kassel.de/abt/w3-w/project/Eur-Transeur-El-Sup.pdf

Czisch, G. and B. Ernst, (2003),"High wind power penetration by the systematic use of smoothing effects within huge catchment areas shown in a European example", gazisch@iset.uni-kasel.de

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