Recently on BNC, I ran two guest posts on the economic and technical challenges of supplying an energy-intensive, developed-world market using 100% renewable sources (under a situation where large hydro and/or conventional geothermal can provide little or no contribution). The case study was the national electricity market of Australia, with an average demand of 25-30 GWe.

100% renewable electricity for Australia – the cost

and the response, from one of the authors of the original simulation study:

100% Renewable Electricity for Australia: Response to Lang

Below is a further commentary, by Ted Trainer of UNSW, which focuses particularly on the issues of supplying winter demand, the feasibility of the biomass option for the gas backup, and the “big gaps” problem (i.e., long-run gambler’s ruin). Ted asked me to post it here on BNC to solicit constructive feedback (and has promised me he will be responding to comments!).

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Comments on

Simulations of scenarios with 100% renewable electricity in the Australian National Electricity Market”  Solar 12011, 49th AuSES Annual Conference,  30 Nov – 2 Dec., By Ben Elliston, Mark Diesendorf and Iain Macgill, UNSW.

Ted Trainer; 21.3.2012

The paper outlines a supply pattern whereby it is claimed that 100% of present Australian electricity demand could be provided by renewable energy.

The following notes indicate why I think that although technically this could be done, we could not afford the capital cost.  This is mainly because the analysis seems to significantly underestimate the amount of plant that would be required.

I think this is a valuable contribution to the discussion of the potential and limits of renewable energy.  It takes the kind of approach needed, focusing on the combination of renewable sources that might meet daily demand.  However it is not difficult to set out a scenario whereby this might be done technically; the problems are what quantity of redundant plant would be needed to deal with fluctuations in renewable energy sources, and what might the capital cost of this amount to?

Two of the plots given set out the contributions that might be combined to meet daily demand over about 8 days in 2010, in summer and winter.  It seems to me that when these contributions are added the total capacity needed is much more than the paper states.

Australia's recent history of energy use by source

The task is to supply 31 GW.  The plots given show that at one point in time wind is contributing a maximum of 13.5 GW, but at other times its contribution is close to zero, meaning that other sources are backing up for it.  The corresponding peak inputs from the other sources are, PV 9 GW, solar thermal 27, hydro 5 GW and gas from biomass 24 GW.  Thus the total amount of plant required would be 75.5 GW of peak capacity… to supply an average 31 GW.  (in his response to Peter Lang, Mark Diesendorf says their total requirement is 84.9 GW.) That’s the magnitude of the redundancy problem and this is the major limiting factor for renewables; the need for a lot of back up plant, which will sit idle much of the time.

In Trainer 2012 I derive the capital cost of plant capable of supplying 1 Watt from wind, PV and solar thermal, in winter at distance and net of transmission losses. When these are applied to the above GW supply tasks, the total capital cost is about  $609 billion.  This does not include the cost of the hydro and biomass sectors.  If the biomass 24 GW is costed at the $800/kW Mark claims, this would add another $19 billion.  My PV cost assumes tracking and Central Australian radiation, not fixed flat plate set up on rooftops, mostly located in much poorer sites.

Assuming 25 year plant lifetimes, the ratio of this $628 billion sum to GDP is 2%, which is about 4 times the early 2000s figure for world investment in all form of energy supply. (See appendix below for the basic assumptions and numbers.)

The derivation does not provide for surplus capacity to meet emergencies etc.  The Australian supply system has a capacity of 51 GW, which is about 1.75 times typical daily peak demand.

It is not clear what loss of energy in transmission has been assumed in the paper, if any.  When long distance HVDC plus local distribution are taken into account the loss is likely to be in excess of 15% of the energy generated.  The cost of the lines would add significantly to the overall capital cost. Hearps and McConnell (2011) indicate that Australian capital costs for ST plant are some 35% higher than those overseas.  The AEMO (2011) estimate of a HVDC line from South Australia is three times the international average stated by Harvey (2011.)  The cost reported in the press for the Queensland proposed Copperplate 1000 km HVDC transmission line is 5 times the average figure in the reviews of overseas projects.

The paper’s conclusions on the crucial winter problem are based on an 8 day plot for June 29 to July 6th  2010.  This is the kind of evidence we want, but it is far from the extent required.  The key questions re the limits of renewables are not to do with averages in demand or supply; they are to do with the coincidence of maximum demand and minimum supply.  What matters is how often there would be a period of several days in which there was little or no sun or wind across the whole collection region.  To cope with one such day the biomass plant required in this analysis would have to be more or less that capable of meeting total demand, i.e., about 25% greater than is assumed in the paper. (Hydro can’t be increased as it is already doing all it can in these plots.)

What we need in all regions are analyses of several years of climate data to establish how often wind and sun availability are how low.  Even if periods of negligible wind and sun are quite infrequent, we would need sufficient plant to maintain supply through them.  In other words is quite misleading to base conclusions about required plant and capital costs on an 8 day climate record for a period that is far from the extremes that occur.    For instance the graphs show that all of the 8 days have very good solar radiation…what happens when there’s little for a week?

This is the “big gaps” problem.  There is extensive documentation of large and protracted gaps in wind availability in Europe. For instance Oswald et al. (2008) document several days in February 2006 when solar and wind sources contributed almost no energy from Ireland to Germany, and one of these days was the coldest for the year in the UK, probably meaning that annual demand peaked.

In an accompanying slide set (http://www.ceem.unsw.edu.au/content/userDocs/presentation.pdf) Ben Elliston provides some significant evidence on this issue, and it is not clear why this does not seem to have been integrated into the paper.  As he says the slides document “Some very long low irradiance events.”  Some of these exceed 5 days of negligible radiation.  A 6 day event is noted for Roma in 2000.  A simulated solar thermal plant output for Cobar indicates no output for almost 4 consecutive days.  It is said that in the south of the continent these events are most frequent in winter, which is the time of highest demand.  Another slide states that it would not be economic to attempt solar thermal storage to cope with these periods.  This information seems to clearly and decisively contradict the paper’s essential claim, that demand can be met at all times.

Map of low direct normal irradiance periods in Australia. Longest events typically last 4 to 8 days across Australia. Click to see full slide presentation from Elliston et al.

It is not stated what generating efficiency is being assumed for the biomass-gas-electricity system.  According to Harvey, 2010, and the IPCC, 2010, it is likely to be .28 at best.  In his response to Peter Lang mark says efficiency is high, but this would seem to be a comment on gas generation, not on the whole forest to electricity system.  (Similarly his $800/kW claim used above would not seem to be for the whole system.)  The Grattan Report (Wood et al., 2012) on renewable notes the difficulties in biomass-electricity, for instance the need for large generating plants for efficiency, but these involve very long distance trucking of biomass.  This would involve energy and dollar costs not included in the $5000+/kW biomass-electricity capital cost which Peter Lang seems to be assuming (i.e., again it would mean that the overall biomass-gas system efficiency would be lower than the above efficiency-at-the-generator figure.).

The analysis assumes a very substantial use of biomass, and the implications of this need to be spelled out.  The plot suggests that daily biomass-electricity input would be about 25 GW by 15 hours, or approximately 40% of electricity supply.  This would take about as much biomass p.a. as would produce 300 PJ of ethanol, i.e., c. 50 million tonnes, so it would cut into the biomass available to provide the other c. 75-80% of total energy needed, including at present about 1300 PJ of liquid fuel for transport.

Biomass to electricity - the concept. But how much is really 'waste', and how much can a country like Australia produce?

If ABARE’s projections of population (a 48% population increase by 2030) and their anticipated energy growth rate are taken the total 2050 energy demand would be around twice the present amount.  At the same time the cost of materials and energy to build renewable plant is going to rise sharply from here on.  (See Clugston, 2012.) These considerations will tend to make my above cost conclusions much too low.

Note again that the paper is only concerned with the provision of the present amount of electricity used, and that makes up only 20%+ of total Australian energy use, and this sets the question, from what renewable sources the remaining 80% are to come from.  The analysis in this paper assumes use of considerable biomass, which would be most needed to meet the demand for transport fuel.  If it is assumed that this can be reduced by shifting most transport to electricity, then the plant required and the capital cost would increase accordingly.

Trainer 2012a sets out an easily followed derivation of a world renewable energy budget, assuming a target of twice present supply and future output and cost estimates common in the literature (e.g., Hearps and McConnell, 2010.)  It is concluded that the ratio of investment to GDP would have to be much more than 16 times the present figure.   In other words it would be quite unaffordable.  Note that that target, 1000 EJ/y primary energy, would only give the expected 2050 world population one-third of the present Australian per capita use. (Three strategies were explored; dealing with the gaps via hydrogen storage, electrifying as much as possible and relying mostly on wind, electrifying as much as possible and relying on solar thermal for storage.)

ANU 'big dish' technology

(In 2010 I published an early attempt to apply this approach to budget estimation, which arrived at a higher estimate of capital cost, but I now see that as being too high.   At that stage, before the availability of the NREL SAM package providing estimates of solar thermal output and cost, 2010, 2011, it seemed that Big Dishes with ammonia storage would be the best solar thermal strategy.  It now seems clear that central receivers are preferable, and there is much better evidence re probable future costs.)

It therefore seems to me that the paper falls far short of establishing its basic claim.  Trainer 2012b applies my approach to the Australian situation, again making all assumptions and derivations transparent.  Australia is more favourably endowed with renewable resources than most if not all other countries, especially re potential biomass.  However the conclusion I arrive at is that the ratio of energy investment to GDP would have to be much more than 9 times the rich world average, and thus would be unaffordable.  Note that this is assuming use of 35 million ha for biomass production, almost twice the cropland area, which is far more than Farine et al. (2011) are willing to assume.

I would welcome critical feedback on my world and Australian analyses.   (F.Trainer@unsw.edu.au)

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Appendix: Basic assumptions and derivation for the above capital conclusions. 

Note the capital cost estimates are for future cost, not present, and generally assume 50% reductions from present for PV and solar thermal and 20% for wind. (…following Hearps and McConnell, 2010.)

Wind: Future cost of capacity to supply 1 Watt in winter, assuming capacity factor of .38, 4% embodied energy cost, 10% loss in long distance transmission plus local distribution…$4.62.

PV: Future cost of capacity to supply 1 Watt in winter, assuming 10% embodied energy cost, 15% loss in long distance transmission plus local distribution…$12.81.

Solar Thermal: Future cost of capacity to supply 1 Watt in winter, assuming 10% embodied energy cost, 15% loss in long distance transmission plus local distribution…$16.

Thus capital costs for the EDM scheme:

Wind, 13.5 GW x $4.61/W = $62.4 billion

PV, 9 GW x $12.81/W = $115.3 billion

Solar Thermal, 27 GW x $16/W = $432 billion

Biomass, 24 GW x $.8/W* = $19 billion

Total = $628 billion

*This is a common figure for a large and therefore maximally efficient generating plant and probably does not include reduction due to embodied energy cost of the plant, or due to the long transport distance large plant would require.  It is also likely that the biomass-gas-electricity generation efficiency assumed in this figure is much higher than the maximum .28 Harvey reports. (2011).

References

AEMO (2011), South Australian Interconnector Feasibility Study: http://www.electranet.com.au/assets/Uploads/interconnectorfeasibilitystudyfinalnetworkmodellingreport.pdf

Clugston, C., (2012). “Ever increasing non-renewable natural resource scarcity”,  Email circular. 19th Jan. 2012. (See also Clugston, C., (2010), Increasing Global Nonrenewable Natural Resource Scarcity—An Analysis, The Oil Drum,  Apr. 6.)

Farine, D. et al., 2011. “An assessment of biomass for bioelectricty and biofuel and for greenhouse gas emission reduction in Australia”, Bioenergy, doii:  10.111/j.1757-1707.2011.o1115/x

Harvey, L.D., 2010. Caron Free Energy Supply, London, Earthscan.

Hearps, P. and D. McConnell, (2011), Renewable Energy Technology Cost Review, University of Melbourne. http://energy.unimelb.edu.au/index.php?page=technical-publication-series

Intergovernmental Panel on Climate Change, Working Group 111, Mitigation of Climate Change, Special Report on Renewable Energy Sources and Climate Mitigation. June, 2011.  http:www.srren.ipcc-wg3.de/report

NREL, (2010, 2011), System Advisor Model, (SAM), https://www.nrel.gov/analysis/sam/

Oswald, J.K., M. Raine, H.J. Ashraf-Ball, (2008), “Will British weather provide reliable electricity?”, Energy Policy, 36,  3202 – 3215.

Trainer, T., (2010), “Can renewables etc. solve the greenhouse problem? The negative case”, Energy Policy, 38, 8, August, 4107 – 4114. http://dx.doi.org/10.1016/j.enpol.2010.03.037

Trainer, T., (2012a), “Can the world run on renewable energy? A revised negative case.” http://socialsciences.arts.unsw.edu.au/tsw/CANW.htm

Trainer, T., (2012b), “Can Australia run on renewable energy? The negative case.”  http://socialsciences.arts.unsw.edu.au/tsw/CANA.htm

Wood, A, T. Ellis, D. Mulloworth, and H. Morrow, (2012), No Easy Choices: Which Way to Australia’s Energy Future.  Technical Analyses. Grattan Institute