Critique of the proposal for 100% renewable energy electricity supply in Australia

Below is a new, detailed critique by Dr Ted Trainer of the simulation studies by Elliston, Diesendorf and MacGill on how eastern Australia might be run off 100% renewable energy. The summary:

Three recent papers by Elliston, Diesdendorf and MacGill (2012, 2013a, 2013b) elaborate on a proposal whereby it is claimed that 100% of present Australian electricity demand could be provided by renewable energy. The following notes add considerations arising from the last two papers to those discussed in my initial assessment of the first paper. My general view is that it would be technically possible to meet total Australian electricity demand from renewables but this would be very costly and probably unaffordable, mainly due to the amount of redundant plant needed to cope with intermittency. This draft analysis attempts to show why the cost conclusions EDM arrive at are probably much too low.

Ted has also updated his critique of the Zero Carbon Australia’s report on 100% renewable energy by 2020. The original BNC post is here, and the updated PDF here.

Ted notes the following:

These efforts have taken a huge amount  of time and I am still not clear and confident about my take, mainly because neither party will cooperate or correspond.  Thus I have not been able to deal with any misunderstandings etc. I have made.  Both critiques are strengthened by information I have come across since circulating previous commentaries, but they are essentially elaborations on the general line of argument taken in earlier attempts.

I find this unwillingness to engage on these criticisms by the primary authors disappointing, but typical.


Introduction

I think these three papers are valuable contributions to the considerable advance that has occurred in the discussion of the potential of renewables in the last few years. My understanding of the situation is much improved on what it was three or four years ago and I now think some of my earlier conclusions were unsatisfactory. EDM take the appropriate general approach, which is to look at how renewable technologies might be combined at each point in time to meet demand, or more accurately, to estimate how much capacity of each technology would be required, especially to get through the times when solar and wind input is minimal. EDM put forward a potentially effective way of coping with the problem of gaps in their availability via biomass derived gas for use in gas turbines. My earlier analyses did not consider this.

It is not difficult for an approach of this kind to show that electricity demand can be met, and many impressive 100% renewable energy proposals have been published. (For critical analyses of about a dozen of these see Trainer, 2014), but a great deal of redundant capacity would be needed, and the key questions are, how much, and what would it cost? My present uncertain impression is that Australia might be able to afford to do it, but if it could it would be with significant difficulty, i.e., with major impacts on lifestyles, national systems and priorities, and on society in general.

A major disappointment with the EDM analyses is that for some crucial elements no data, evidence or derivations are given and as a result the proposal can only be taken as a statement of claims. We need to be able to work through the derivations in proposals such as this to see if they are sound or what questionable assumptions might have been made etc. Consequently I have had to spend a lot of time trying to guestimate my way to an assessment of the cost conclusions and it is not possible to confident about the results.

Required capacity?

A merit of the EDM approach is to take as the target the present demand. This avoids the uncertainty introduced when attempting to estimate both future demand and the reduction in demand that conservation effort etc. might make.

Two of the plots given in EDM 1 (Elliston, Diesendorf and MacGill, 2012), set out the contributions that might be combined to meet daily demand over about 8 days in 2010, in summer and winter. In my first discussion of the proposal it seemed to me that when these contributions were added the total capacity needed would be much more than the paper stated. The total amount of plant required to supply an average 31 GW was stated as 75.5 GW of peak capacity. (In his response to Peter Lang, Mark Diesendorf said their total requirement is 84.9 GW.) However in EDM 2 (Elliston, Diesendorf and MacGill, 2013a) the total has been significantly raised, to 104 GW. (The proposal from Hart and Jacobson 2011, for 100% renewable supply in California, also involves a large multiple of average demand, greater than four, and in the proposal by Budischak , et al. 2013 for California it is around 8.) Unfortunately this is one of the crucial numbers and claims in the proposal which it is not possible to assess because the derivation and the necessary background data on weather patterns are not provided.

The following discussion is in terms of present capital costs, as stated by AETA. The figure that seems to me to be of most use is the capital cost of sufficient capacity to deliver I kW, at distance, in winter, net of embodied and other costs and losses. This is much higher than the usual figure for capacity to generate 1 kW in peak conditions.

Wind

EDM assume that wind will meet 58% of demand in one of their scenarios, but there is no discussion about whether this is possible (although there is a sentence recognising that 50% would set significant problems.). Lenzen’s review (2009, p. 19) concluded that the general limit before problems arise is likely to be around 20%, and possibly under 20%. More recently Kuchinski (2013) states 20% as the extreme upper limit and 10% as the norm. It is difficult to generalise as there are studies where higher penetrations have been achieved, but these are typically for unusually favourable regions such as Denmark which is able to export large surpluses easily. (This export capacity also enables Germany to have such a large PV component.) The complicating factor is that higher penetrations bring problems such as grid instability, back-up needed, and power dumping, which “technically” can be solved, but at a significant cost in equipment such as the interconnectors that have to be built to make exporting possible. (South Australia is contemplating the construction of two, at a possible cost of $4 – 10 billion…which would pay for up to 3 coal-fired power stations and these would deliver several times as much power as the whole wind sector in SA. Miskelly, p. 1249.)

This assumption of large dependence on this relatively low cost technology among the renewable options is a major determinant of the questionably low final capital cost sum arrived at by EDM. If the quantity limit is only half that assumed then much more of the more expensive PV and ST plant would have to be used.

It is not possible to assess how adequately EDM deal with the intermittency of wind. The recent CSIRO study of intermittency (Sayeef, 2012) makes clear the magnitude of the integration problem, and the many difficulties it sets, even for penetration levels around 25%. Miskelly’s analysis of Australian wind power around 2010 and 2011 makes the magnitude of the integration problem clear, even for the present Australian situation where penetration is low. In one year output from the whole 1.9 GW peak capacity network was negligible 156 times, for a total of 6.5 days. In May 2010 there was virtually no wind anywhere in Australia for three days.

It is generally assumed that adding widely distributed farms reduces intermittency of aggregate supply but when Miskelly compared the situation before and after the installation of much capacity he found that this did not “smooth” aggregate input. These findings mean that the entire wind capacity has to be backed up by fossil fuelled generation capacity, and almost none of the previously existing fossil fuelled capacity can be retired. As Palmer points out the German PV sector has added some 30% to power generating capacity without adding to power consumed, so this is added capacity that can be substituted for fossil fuelled capacity from time to time, but it is not capacity that adds to power provision.

Even more problematic are the implications of the associated ramp rate problem. Miskelly documents the frequent precipitous rises and falls in total output. He says this means that for a large scale wind sector the back up can’t be the existing coal-fired plant but would have to be newly built gas-fired plant. (The EDM proposal aligns with this conclusion as backup would be provided by the very large biomass-gas-electricity sector they assume.)

As noted above, the estimate of system capital cost offered below will focus on the present capital cost of sufficient plant to send out to the grid (or deliver to users) an average kW in winter conditions. It is not clear what an appropriate winter wind capacity factor would be. AETA (p. 46) assumes 38% as the annual average but inspection of the NEM wind data shows that in July 2010 the average capacity factor was in fact well under 28%. The world annual average is around 25%. The examination of data from the whole Australian wind sector carried out by Miskelly shows that in one winter month in 2010 capacity averaged 24%. Surprisingly for South Australia where wind resources are unusually good, Miskelly and AEMO (2012) both document winter capacity lower than summer, and in some months it is 60% lower. However for working purposes the winter figure assumed below will be a very generous 38%. This would make the capital cost of the capacity to send out 1kW in winter $6,660, based on the AETA present capital cost figure of $2,250/kW(p).. (2012, p. 46.)

Next we need to take into account the assumption that the lifetime for wind turbines is only 20 years compared with 30 assumed for the other renewable technologies involved here, (and 50 for coal, AETA, 2012 p. 27.). Given that the estimation below considers a 30 year period, the assumed lifetime for PV and ST, this makes the 30 year capital cost figure $9,987 for the amount of plant needed to send out a 1 kW flow in winter. (Wind capital cost is not expected to fall much if at all in future; see AETA, 2012, p. 76.)
A thorough analysis would have to increase this figure to take into account the embodied energy costs of wind plant and the “downstream” energy costs and losses. Within the latter would be Jefferson’s recent finding that wind systems operate for fewer hours than has previously been assumed. (Jefferson, 2012.) (Hughes found that UK turbines are lasting only about 12 years, but this could be due to retirement of older units, so will be disregarded here.) Weisbach et al. (2013) and others state an ER of around 16 for wind but do not seem to have taken into account all upstream embodied energy factors or downstream losses (as Pietro and Hall have attempted for PV, below.) However Lenzen and Munksgard (2001) did take at least some of them into account and arrived at an ER of 6. These findings leave the issue unsettled but suggest an all-in embodied energy cost of 6% – 17%. No account of wind embodied energy cost will be included in the estimations below.

The problematic PV component

PV is assumed to contribute c. 17 – 20% of electricity. This seems to be an appropriate assumption. Denholm and Margolis (2007) see 10 – 20% as the limit and believe it is not likely to be more than 15%. This seems to be valid because if in each day PV was to contribute 20% of the average 23 GW then it would have to generate 0.2 x 23 GW x 24 h = 110 GWh/day. But it would have to do this during the c. 7 hours in which there is significant solar energy, so its output then would have to average 16 GW, meaning that the wind, solar thermal and hydro sectors would have to be cut back to only a combined 30% of total output in that period. (Also grids would have to be strengthened to enable 70% of demand to come from PV sites for some hours, then to draw around 100% from other sites. This suggests that PV would not be allowed to contribute more than about 15%.
It is not generally realised that PV can’t make much difference (unless the storage problem is solved.). If it provides 15% of electricity that’s less than 3% of present rich world energy consumption. A related problem is that supply does not align well with demand, indicating that its contribution would be limited without extensive storage capacity. In summer air conditioning use often makes electricity demand peak late in the afternoon. Palmer reports a study in NSW finding PV input to be zero at this time. AEMO reports Victorian PV contributing at a rate of 1% of capacity when power demand peaks in winter. (Below.) Palmer says, “… PV is not suited to taking on a primary network role or delivering sufficient surpluses of energy when a fuller account of embodied energy is included.” ( 2013, p. 1407.)

EDM assumes PV modules on rooftops in Brisbane, Sydney, Canberra and Adelaide, eliminating distribution losses. Their total capacity corresponds to around 2 kW(p) per household, or 15 modules, which would not seem to be plausible. However winter global radiation in these four latitudes averages around only 2 kWh/m2/d in some months. Presumably wind and inland solar thermal sources are to make up for rooftop PV in winter, but we are not able to see how this is to be done or whether there is sufficient capacity assumed to do it, especially through difficult periods.

Embodied energy costs

There is no discussion of embodied energy costs or “downstream” losses or the resulting EROI for PV (or any other of the renewables), yet these are crucial considerations. For PV EROI has been commonly assumed to be around 10 (Fthenakis, undated, says up to 60), but only recently has attention been given to attempting to estimate an all-inclusive value. It is now clear that two major and previously neglected categories of energy cost and loss have to be taken into account. The first is to do with the “upstream” factors, such as the relevant fraction of the energy it took to construct the aluminium plant that made the material for the module frames. A few studies have attempted to do this seem to have arrived at a figure of around 33% for the total energy cost of production for PV. (Crawford, 2011, Crawford, Treloar, and Fuller, 2006, Lenzen, 1999, Palmer, 2013, Prieto and Hall, 2013, and Lenzen, Dey, Hardy and Bilek, 2006.) A recent and detailed study, by Weisbach, et al., (2013) arrives at an ER of 3 to 4.8, and they say that the studies by Battisti et al., (2005), Ito et al., (2008), Meije et al, (2003),Raugeri et al., (2010), and Alsema (2000) are in good agreement. (I’m not sure about this.)
Inquiries to AEMO in 2014 found that it does not have evidence on embodied energy costs of PV and although it discusses the “payback period” this is calculated only in dollar terms, i.e., time to repay the monetary investment. In other words it is surprising and disappointing that AEMO’s statements and statistics do not take embodied energy costs into account.

The “downstream” factors include costs and losses after the plant has been installed and which accumulate over its lifetime, such as losses in wires, connections and inverters, invertor failure and replacement, accidents that damage equipment (e.g., rats or possums that cause shorts), badly aligned panels (which seems to me must be a significant factor, from observation of the many less than ideal rooftop mountings), shading of panels (a tiny amount of shading can cut output dramatically), dust and bird droppings on panels, corrosion at terminals and connections, heating of panels (which can cut midday input by more than 25%), poor maintenance by householders, and deterioration of panel efficiency due to age. Prieto and Hall (2013) list 15 such factors and estimate that these cut output to 65% of rated capacity.

Previous discussion has recognised some of these loss factors and have used the term “performance factor” to refer to the reduction they cause. For PV this has been thought of as around 0.75 – 0.8. What Palmer, Crawford, and Prieto and Hall are saying is that the previously assumed models for ER calculation have not included all relevant factors and have used “boundary” assumptions that have been too narrow, and have therefore produced a performance factor that is too generous,

Power dumping must be accounted as a different kind of energy loss affecting EROI. (My stand alone homestead PV system dumps most of the power it produces in summer, yet is not big enough to meet winter demand reliably, despite 800 ah of battery capacity.) Palmer’s Figure 3 shows that about 10% of German PV output in a summer period was exported. This was possible because neighbouring countries did not have as much PV as Germany and were not experiencing output gluts when Germany wanted to export. If they all had as much PV the Germans would have to dump in summer. Australia could not export.

There is another category of “downstream” costs/losses attributable to PV and most other renewables but not previously subtracted from embodied energy and “downstream” accounts. The recent OECD report (2013) discusses the significant costs of “grid adjustment” to accommodate renewables, including the cost of strengthening grids to be able to cope with variation in amounts of power coming from differing regions. When centralised coal fired sources provide all power relatively simple networks can be built, e.g., to deal with a fairly regular and stable voltage drop from power station to distant consumers. But with renewable sources much power might be coming from one region today and from another tomorrow. This seems to be a factor additional to those Prieto and Hall deal with. It would become more problematic if the contribution of wind to a system is assumed to be high, and again EDM assume up to 58%.

There is not yet agreement about definitions and boundaries in the discussion of EROI (e.g., do you include the energy cost of security services at the PV farm, or of workers travelling to the module factory, or those associated with financing? These are necessary costs; there could be no PV output if they were not paid.) Palmer (2013) and others use the term “extended EROI” when all these upstream and downstream factors are taken into account. For PV systems Palmer arrives at a remarkable 2.1 – 3+ for the extended EROI of rooftop PV systems in Melbourne. This means payback time might be taking 15 of the 30 year lifetime of the system (p. 1434), and in its lifetime a module could only produce enough energy to pay for its own production plus that of one more.

Even more surprisingly a similarly very low figure has also been arrived at by Prieto and Hall (2012) for actually functioning Spanish utility scale systems, where one would assume many of the factors associated with roof top systems would not be problematic, such as quality of maintenance.
This recently opened cluster of issues will take time before confident conclusions emerge. It must be remembered that ER values depend significantly on a particular set of conditions especially the location of the modules and its typical level of solar radiation, and the size of system assumed (e.g., small penetration might involve no backup provision or dumping loss.)

It is very important to recognise that we seem to have no clear idea how rooftop PV is performing, or what contribution to the grid is being made by each kW of installed capacity. The first point that is usually overlooked is that if you install a 3.5 kW capacity system you will almost certainly never get more than about 2.5 kW out of it; even before taking into account all the above “downstream” loss factors. The peak rating refers to ideal conditions and a radiation level few if any house roofs ever get. (See for instance Damn The Matrix, 2013.) My efforts (e.g., via communications with AEMO) to get information on the actual amount being generated by PV in Australia or anywhere else, and the proportion of this that is fed into the grid, have found that no data is available. The relevant data probably cannot be collected because neither the amount of power a household produces nor the amount it uses before sending the surplus to the grid are generally recorded. These would be very difficult factors to get good data on. AEMO admits that it does not know how much power rooftop PV in Australia generates, and that its estimate that 50% of what is generated is fed in is a guess. (Personal communications, Jan. 2014.)

It seems therefore that we actually have little idea what a given amount of rooftop PV capacity will contribute to the grid. AEMO’s lengthy and detailed discussions (2013a, 2013b) are based on assumptions and theoretical models involving highly uncertain estimates for some of the key factors for which there seems to be no evidence, and they completely ignore embodied energy costs and “downstream” losses. AEMO does however state a figure for the amount PV contributes when demand peaks. They say that in winter the 426 MW installed PV capacity in Victoria contributes a mere 4 MW (…and this too seems to be an estimate, not a measured observation.). However this is late in the day and it would be more meaningful to know what PV contributes during the whole of a typical winter day. Unfortunately personal communications found that AEMO does not have this data.

The important point from all this is that we seem to be in no position to make assumptions about what contribution rooftop PV can make at what cost, or how much plant would be needed to achieve a chosen contribution. EDM like AEMO and the rest of us can only deal in terms of peak ratings and thus theoretical outputs in ideal conditions and these are likely to be quite misleading indicators of actual achievements in the field, especially at less than ideal sites in winter. As Palmer, and Hall and Prieto stress, many factors then detract from those theoretical figures, leaving us highly uncertain about how much PV capacity we would have to build and pay for in a proposal designed to deliver a certain net amount to the grid. What we can be sure about is that if we calculate in terms of the commonly stated dollar cost per kW(p) of capacity, and commonly quoted ER figures, we will seriously underestimate the cost.

These considerations make it very difficult to assess the EDM proposal as it is not possible to work out confidently how much PV energy can be sent to the grid net of the above costs and losses, at what capital cost. We won’t know until the new uncertainty over PV embodied costs and other losses is resolved, and until actual input data is available, but given that these factors have previously been ignored it is plausible that the general net ER for PV will be half or less of the value previously assumed, effectively at least doubling previously assumed sector capital costs.

Estimating costs

AETA reports the present capital cost for fully installed PV at $3,800/kW(p) (p. 43, but $3,380 on p. 87?). (However much higher 2010 figures are given by Black and Vetch, 2012. NREL states a much higher figure, $(US)7,690/kW(p) for rooftop and $4,790 for commercial scale.) EDM use the AETA future cost of $1,677, which is one-fifth of the NREL figure for present cost (and it is present cost that matters for affordability; see below.)

Because costs have recently fallen rapidly a confident assumption cannot be made here but the AETA figure will be used below. It is stating what it would cost to have a sufficient area of PV panels etc. to produce 1kW in peak radiation at (I assume) 15% efficiency. If that area received peak radiation for 24 hours, i.e. 24 kWh/m2/d, it would produce a constant 1 kW, but in winter radiation in the Sydney region only totals about 5 kWh/m2. (Melbourne or Tasmanian winter radiation is around half this level.) So we would need 24/5 = 4.8 times as big an area to produce an average 1kW in winter. Therefore the capital cost of sufficient PV panels etc. to produce the equivalent of a constant average 1 kW in winter (i.e., ignoring the storage issue) would be around $18,240. (Wilson, 2011, states the annual average as $20,000, so his winter figure would be considerably higher than $18,240.)

This is a gross output figure and to it we should add the cost added by all the embodied energy costs and the downstream loss factors referred to above. If Hall and Prieto, and Palmer are right in claiming an ER of 2 – 3 these costs and losses add to around half the lifetime energy produced, so would more or less double the above cost figure. It is not possible to make a confident ER assumption so I will assume an ER two to three times as high, i.e., 6. This would seem to be generous compared with the commonly stated ER of about 8 – 10 which does not take in any of the upstream embodied costs or downstream loss factors discussed above. The capital cost figures then become, $21,900 for the capacity to deliver a constant 1 kW in winter. Of course none of these figures take in the cost of the storage (or back up) to enable the 1 kW to be sent constantly, but that is not relevant to the EDM proposal.

The solar thermal component

Output issues

The solar thermal capacity is assumed to be 9.4 to 13.3 GW in the two EDM 2 scenarios, contributing 8.3 – 12.5% of power. Again it is not possible to assess the acceptability of these low percentages (for the most costly sector) but they seem to be much too low given the above points made re wind and PV. If the wind limit is 20% (not 50+%), the PV limit is 15% (not 20%), biogas 7% (as assumed), and hydro 5% (as assumed, plausibly) then the costly solar thermal sector would have to contribute around 53%, which is 4 – 6 times the amount EDM assume. Again this would greatly increase total system capital costs.
Fig 2 in EDM 1 representing combined inputs for each of a number of days enabled some visual confirmation of capacities needed. The ability to see these combinations is crucial in assessing the plausibility of such proposals, but this is not possible with the second and third papers. Thus we can’t check whether the following apparent problem evident in that figure has been resolved. It is stated in the paper that 15.6 GW of solar thermal capacity would be needed, but Fig. 2 seems to show that at times the solar thermal component will be sending out perhaps 27 GW. There would be much worse days than the one represented in Fig. 2, suggesting that on those days the amount would be greater still.

Whether the 9.4 – 13.3 GW of solar thermal capacity stated in EDM 2 would be sufficient would depend on long-term weather patterns, and again we are not given evidence on these. How often would there be no wind or sun for several days in a row, requiring electricity to come mainly from hydro and biomass-gas-generation? (See below.)
My recent attempt (Trainer 2013a) to analyse the AEMO weather data for its implications for solar thermal power has increased my concerns about the potential of solar thermal in less than ideal conditions. I took six widely distributed good sites from central Australia to Mildura and found that in the 92 day period at the end of 2010 there were 12 (non-overlapping) periods each lasting 4 days or more, including 48 days in all, in which DNI averaged across the sites did not reach 500 W/m2 at any time during the day. Reference to power curves (mostly available for dish-Stirling systems but also somewhat evident for central receivers…and apparently much worse for troughs) indicates that almost no power would have been generated on these days. It seems that if daily radiation received is under 6 kWh/m2 day solar thermal output will be poor, and possibly very poor. This is also stated for troughs by Odeh, Behamia and Morrison, 2003, Fig. 14, and is evident in the plot by Elliston et al. (undated), and other sources discussed in Trainer (2013a). In the slides from Elliston (2012) there is considerable evidence on this issue, and it is not clear why this does not seem to have been integrated into the papers. As Elliston 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.

It would seem that energy production from dish-Stirling units in the rather high latitudes ZCA assumes (Wright and Hearps 2010), e.g., Mildura, could be around only 10% of what might be expected given an annual average daily DNI/m2 of 4.3 W/m2. (Central receivers would do somewhat better than dishes, but I cannot get much power curve data for them so can’t say how much better.)

The above study (Trainer 2013a) also explored the possible effects of low DNI on the efficiency of solar thermal power generation. It seemed that as average DNI goes down towards 500 W/m2 or the daily total goes towards 6 kWh/m2/day, efficiency is markedly reduced. For some dish-Stirling systems it is clearly reported that when DNI is down to 400 W/m2 efficiency and output fall to zero. This has profound implications. It seems to mean that although solar thermal systems are excellent contributors in summer they will make little contribution in winter even in ideal regions, and that at other times they will be subject to frequent periods of no output for periods of 3 or more days. It also means that calculations of the embodied energy cost and pay back time for solar thermal need to be rethought, because these have been based on the mistaken assumption that annual average DNI for a site can be multiplied by a single, constant plant efficiency figure (which refers to performance in peak radiation) to yield annual or winter output, when in fact much of the DNI making up that average will be too weak to generate any power. In other words it is a mistake to simply take a DNI/m2 figure for a site and multiply it by a constant efficiency figure (ZCA assumes 17%) to arrive at a figure for power produced, because if the DNI figure is middling to low plant efficiency will be disproportionately lower, and it is possible that in winter in some locations which are satisfactory in summer no power at all will be produced.

For instance ZCA assume solar thermal located at three sites where winter DNI averages under 5 kWh/m2/d. This means that at the Mildura site where DNI is 4.5 kWh/m2/d, about half the time it will range down to well under that value. At 4 kWh/m2 DNI is not likely to rise above 400 W/m2 for more than 2 hours a day, meaning that power generated on that day would be negligible.

More recently I have found that total output from the Australian wind system was close to zero on two occasions within the periods I identified above in which there was negligible solar radiation (i.e., 5th October and 20th November 2010.). Thus for the EDM proposal there would very likely be times when total demand has to be met by biomass-gas-electricity plus hydro, so if EDM are intending to provide for a 37 GW peak demand, the biomass-gas-electricity capacity would have to be much greater than the 23 GW they assume (see below.)

It is stated in EDM 1 but not explained that to use more than 6 hour solar thermal storage would not be viable. However EDM 2 assumes 15 hour storage and why this is now regarded as viable is not explained.

Embodied energy costs for solar thermal do not seem to have been taken into account. I am not aware of any satisfactory studies of this factor to date, dealing with all upstream embodied energy costs, as for PV above. (Dale’s review, 2013, lists only 8 studies, with no reference to upstream or downstream costs and losses.) The few figures in the literature indicate a 6 – 11% cost, and none seem to have included upstream embodied energy costs or possible downstream losses. In my analyses I assume a 10% embodied energy cost but when thorough analyses are available the figure is likely to be higher.

Note that higher Solar Multiples and storage capacities (discussed below) add to embodied costs and reduce ERs, because they do not increase the amount of energy produced, they only increase the delivery period possible. The evidence below suggests that this factor might increase embodied energy costs by more than 50%.
Similarly there seems to have been no study of downstream costs and losses for solar thermal. Many of the 15 factors Prieto and Hall take into account for PV would be relevant, such as losses in connections to the grid, energy used by workers and vehicles, and in plant security and in construction financing.

Capital costs
The Solar Multiple issue

This seems to me to be confused in both the EDM and Zero Carbon Australia (Wright and Hearps, 2010) analyses. EDM assume 15 hour storage and refer to this as a SM of 2.5. ZCA assume 17 hour storage and refer to this as involving a SM of 2.5. However it seems that these figures should be 3.5 and 3.83.
If the SM is 1 there is no storage and the field is just big enough to drive the turbine at more or less full power for the approximately average 6 hours equivalent that the sun is shining at full strength. If the SM is 2 the field is twice as big to enable collection of twice as much energy and thus to store for 6 hours operation, if there is 12 hours storage the SM is 3, and if there is to be 15 hours storage the SM will have to be c. 3.5. This is the usage explicitly discussed in Lovegrove et al., (2012), James and Hayward (2012, p. 12), and Trieb, et al. (2009) who state, correctly it seems to me, 18 hours storage means the SM is 4. The IRENA review of solar thermal power (2012) makes this use at a number of points, e.g., pp. 8, 14, 18 and 30. The US DOE (2012) more or less corresponds, saying that for 11 hour storage the SM would be 2.5; i.e., a little larger than the above references would suggest.

In EDM 2 on p. 8 the apparently correct figure is quoted from AETA: “The AETA provides cost data for CST plants with six hours of thermal storage and a solar multiple of 2.” But the next sentence says, “As the simulations are based on CST plants with 15 hours storage and a solar multiple of 2.5 …the capital cost of the simulated CST plant was derived by scaling the solar multiple by 1.25 and the storage by 2.5.” The ratio seems to have been arrived at by dividing 2.5 by 2 but the ratio of total plant cost is not the same as the ratio of the SMs. It is produced by the costs of the additional field and storage added to the other costs, such as for the tower.

This is not simply a matter of definition; it affects field and storage cost estimates. AETA (2012 p.37) gives cost estimates for central receivers without storage and with 6 hour storage, but not for longer periods. They say that adding field and storage to enable 6 hour operation from storage increases plant cost from $5,900/kW(p) to $8,308, i.e., by 41%. For a plant with 15 hour storage this amount of field and storage would have to be added to the cost of a plant with 6 hour storage another 1.5 times. Thus the total cost would be 60% higher than the cost of the plant with 6 hour storage, a multiple of 1.6 not 1.25.

Lovegrove et al., (2012) give figures for LCOE which seems to imply a higher multiple. They indicate that 15 hour storage would involve raise the LCOE to 1.8 times that for 6 hour storage. Trieb (2010) indicates a similar figure.

It will be assumed below that a SM of 3.5 adds 50% to plant cost.

Capital cost estimation

Following is an imprecise derivation of a figure for the capital cost of sufficient plant to deliver at distance a net 1kW in winter. It will be based on the information given in the NREL (2010, 2011) Solar Advisory Model for a (theoretical/modelled) example 100 MW central receiver. This is located at Blytheside River, Southern California USA, the estimate assumes 6 hour storage and air cooling, and provides for interest charges. The cost estimate is $658 million and therefore is $6,580/kW(e)(peak). (However NREL says this figure has been set at lower than actual present construction costs; Turchi, 2014.) The average annual rate at which power would be sent out is estimated at 40% of peak capacity, and the winter rate is 28 % of peak, indicating that the capital cost for the capacity to send out each 1 kW on average would be $16,250, and to do so in winter it would be $23,214.

A number of considerations would greatly increase this figure.

• The energy loss of 10 – 15% for long distance transmission, e.g., from the Sahara to Northern Europe, or from the distant sites that are ideal in Australia.
• The capacity to collect and store for 15 hours might multiply the cost of the NREL example by 1.5+.
• The embodied energy cost of the plant might take 10% of energy produced.
• The increased cost of construction in remote areas. The best situation for solar thermal plant is in desert areas, especially North Africa for European supply. According to Lovegrove et al. (2012) this might multiply total costs by a factor of 1.3+.

Taking these factors into account (assuming 10% for transmission loss and a factor of only 1.5 for the SM item) would multiply the above figure by 2.4 to $55,900/kW. The figure does not include the energy costs of plant O and M. (Nor does it take in the dollar or embodied energy costs of building, operating and maintaining the long distance transmission lines but these might best be kept separate, as EDM do.).

This cost figure is likely to appear to be extreme, and mistaken. It is not put forward here with great confidence but the above discussion makes the derivation clear, along with the assumptions etc. that would need to be revised if a significantly lower figure is to be established.

The cost of locally sited coal-fired plant capable of delivering 1 kW in mid-winter, and requiring no long distance transmission lines, assuming a .8 capacity factor, would be c. $3,700. (AETA, 2012). Adding fuel costs might bring the total to $5.7 billion, which is around one tenth of the above solar thermal cost. (This does not include an embodied energy cost for coal-fired plant but this would be relatively low as the 50 year life AETA assumes makes the ER for coal-fired power generators high.) Gas fuelled costs would be significantly lower.

Gemasolar

However the capital cost reported for the recently completed Gemasolar plant in Spain are far higher than the commonly stated solar thermal cost estimates, such as those given by NREL’s SAM. This 20 MW plant has 15 hour storage capacity, which the EDM proposal assumes. It has been reported as having a capital cost of $(A)548 million, which is $(A)27,400 /kW(p). (Solar Australia, 2011.) Some sources state 200+ million euro, including AETA. The plant is claimed to send out 110 million kWh/y, so the capital cost per annual average kWh sent out (as distinct from peak) could be around $41,000, whereas for coal-fired capacity it would be $3,100 according to AETA. If a 50 year plant life for coal fired power is assumed, as AETA does, p. 27, the annual capital cost per kW sent out for Gemasolar would be around 20 times that for coal. (Figures on what Gemasolar actually does send out are not made public. NREL publishes a graph but it does not enable monthly figures to be derived, and personal communications with NREL confirm that data is not released.) Taking into account embodied energy costs would raise these numbers further. Above all, these are average annual figures –what it sends out in winter, and the capital cost of sufficient plant to send 1 kW then, would be significantly lower.

Of course Gemasolar is the first of its kind with 15 hour storage, so the cost is likely to fall significantly eventually. However estimates of future capital costs generally assume only a 33% reduction for solar thermal units built in Australia (the expectation in AETA, (2012, p. 71), and AETA expects Gemasolar capital cost to only fall by 20% (p. 37.)
Also relevant is the fact that 15 hour storage does not mean approximately 24 hour supply or 100% capacity. Gemasolar’s capacity factor has been reported as 63%. (Wilson, 2011.)

Solar Thermal Conclusions?

It would not seem to be possible to state confident conclusions regarding capital costs for the actual amount of power delivered by the solar thermal sector. No large commercial scale central receivers have been built. NREL and all other sources approached confirm that operators will not release performance data. We do not know whether real world costs will be close to the theoretical estimates such as those given by NREL. More importantly we do not know what delivered figures would be, net of embodied, upstream and downstream costs and losses. And we do not know what these values would be in winter when it seems that for solar thermal power annual average values for efficiency and output do not apply.

Note also that not all cost estimates are as low as those from AETA and it should not be confidently assumed that costs will fall. The most quoted of the (few) estimates ventured expect falls, but some do not. (Guielen, 2011, Hayward, 2012.) Indeed it is likely that energy and materials costs will rise steeply in future. Lovegrove et al. note the recent jump in the price of steel. (2012, p. 190.) (The NREL cost is lower than the AETA cost but NREL points out that the SAM statements deliberately under-state present costs. Turchi, 2014.)

Another cost concern is that the value of the Australian dollar has been falling since the minerals boom. When the main capital cost estimates quoted at present were made it was around equal to the US dollar but early in 2014 it had fallen to around 80 US cents. If this is a return towards the long term level of around 70+ US cents, the cost of imported elements (all wind turbines, PV modules, and solar thermal turbines) might have to be multiplied by 1.4.

The efficiency of plant with SMs above 2 also needs to be considered. Some believe a solar multiple of 2.5 is about the limit because of the distance to outer reflectors (increasing the “cosine effect” loss as the average angle between mirrors and sun increases, and increasing heliostat spacing due to increased shading.) It would be interesting to know how the efficiency of Gemasolar is affected by these factors.

Again unfortunately the picture is obscure. The $55,900/kW figure above is at first site difficult to believe, and critical revisions of the derivation are invited, but there would seem to be reason to assume that present capital cost of delivering a net 1kW in winter would be a significant multiple of the figure EDM assume for future cost.

The biomass-gas-electricity sector

One of the significant recent advances in the discussion of renewable energy and the storage problem seems to have been the realisation that this might best be done by use of biomass to produce gas that can be delivered and stored via the existing gas supply system, and used to generate electricity when needed. Discussion of this option is a major merit of the EDM proposal, but again the quantities assumed cannot be verified, and sector costs assumed seem to be much too low. In addition it is not clear that the technology is viable in view of the difficulties it involved.

The proposal is intended to cope with a 37 GW peak demand. Given the above discussion of big gaps there would be periods in which the biomass-gas-electricity sector would have to provide total demand minus the hydro component which is assumed to be a maximum of c. 7 GW. Therefore it seems there would have to be at least 30 GW of biomass-gas-electricity generating capacity on hand, not the 23 GW stated.

Very few biomass-gas-electricity systems have been built and the viability of the technology has not been established. Significant uncertainties are expressed in the literature.

The Grattan Report (Wood et al., 2012) on renewables notes the problems. Lenzen (2009) and other technical discussions say that cleaning several kinds of impurities out of the gas sets a “major technical difficulty”. The gas is at low pressure and has to be compressed, which would affect net energy output. One source says “…no viable technology has been available to produce refinery grade syngas from biomass.” (Syngas Technology, 2013.) EDM use the conclusions on various renewable technologies from the AETA review but that source reinforces doubts about the viability of the biomass-gas-electricity path and does not attempt to estimate capital costs. It gives only seven lines to the technology, including the words, “No significant progress has been made on full scale development of such plants and none is anticipated in Australia in the near future.” (p. 53.) Weisbach et al. say, biogas-fired plant are “…clearly below the economic limit with no potential of improvements in reach.” (2013, p. 24.)

It seems clear that the proposal takes into account only the (very low) capital cost of the gas turbines. (They state c. $730/kW, which is the approximate figure AETA gives on p. 34 in the section on gas generation. This is not a section on the complete biomass-gas-electricity generation process or its costs.) But biomass-gas-electricity capital costs would add to the turbine cost the costs for the gas producing plant, including removing impurities and compressing and pumping, and all the machinery going into biomass production, harvesting, drying, and transportation. Kendry (2002) says biomass-gas producing plant capital costs are around 2/3 those of gas-electricity generating plant but Worley and Yale from NREL (2012) state higher figures for gas production than for gas turbines. Their biomass input and plant cost figures mean that plant capable of producing gas for a 1000 MW gas turbine would cost $1,005 million, 50% more than the cost EDM state for the gas turbine, assuming 60% efficiency for both gas production and electricity generation. It is not possible to state a confident figure here.

Biogas backup

Depending on how often how much gas would be required for back up, it could be that relatively little gas producing plant would be needed because it could be continually restocking storage at a constant rate. Again the amount can’t be determined without detailed analysis of weather patterns and gaps. However the EDM proposal does involve a considerable use of gas, generating up to 7.1% of power supplied. This suggests that the gas production rate would have to be sufficient to average an electrical output of 7.1% x 23 GW = 1.63 GW and therefore that the relevant capital cost figure would be for plant and other equipment capable of providing biomass at a rate of greater than 3.26 GW (if conversion efficiency via gas turbines is 50%, but more than twice as much if steam via biomass burning has to be used). This means the energy content of the biomass input flow would have to be at least 103 PJ/y corresponding to c. 5.7 million tonnes p.a. (None of this includes embodied energy etc. costs.)

Estimates of biomass potential vary greatly but Australia would have no great difficulty providing the amount needed according to this estimate. AETA’s figures on available landfill, sugar and other woody waste biomass material indicate that these could generate around 5% of present electrical energy used, i.e., 34 PJ/y (pp. 50 – 51), corresponding to a biomass input flow of c. 100 PJ/y. Milibrandt and Overend (2008) state a higher figure; all collectable waste might produce 293 PJ/y in fuel corresponding to 36% of Australian petrol consumption. If necessary a relatively small amount of plantation biomass could be used, but it must be kept in mind that to meet transport demand via ethanol or methanol would draw heavily on his potential. ABARE and Geoscience Australia say our total biomass potential is only c. 480 PJ/y. Transport now takes over c. 1,800 PJ/y of fuel, and if all this was to be provided in the form of ethanol c. 4,000 – 5,500 PJ/y of biomass would have to be going into its production. The lower figure would require a daunting 250 million tonnes p.a., from perhaps 35 million ha.

(These numbers rule out meeting global transport demand via biomass; around 16 billion ha of plantations would be needed…on a planet with only about 10 billion ha of productive land. The IPCC, 2011, estimates total plantation plus waste potential at c. 420 EJ/y, which would give 9 billion people an average liquid fuel budged around 20% of the present Australian figure…and there are several reasons for thinking the IPCC figure is too high; see Trainer 2012a. The 2014 IPCC Working Group 3 report states a much lower global potential, up to 270 EJ/y of primary energy. Lang points out that the availability of biomass year after year in a land prone to severe and protracted droughts, and floods, is highly variable and uncertain.)

Given AETA’s above doubts about producing gas by pyrolysis the system might have to be based on biomass burning to generate power via steam, which is the only path AETA discusses. Crawford (undated) reports the capital cost of biomass CHP at $5,500/kW, and AETA (p. 52) states $5,000/kW. In other words if gas generation is not feasible the capital cost of the generation link alone might be almost 7+ times that which EDM seem to be assuming for the whole sector. In addition this approach would have slower ramp rates than a gas system and would therefore be less adept at plugging sudden gaps.

Then there are energy efficiency considerations. Gas turbines can be quite efficient but when the efficiency of the gas production system (potentially 67% at best, according to Van der Meiden, Veringa and Rabou, 2010, and Mardon, 2012), and the energy costs/losses in producing the biomass, trucking it, drying, and returning ash to the fields, and in producing, cleaning and compressing the gas are all taken into account the overall energy efficiency of biomass-gas-electricity component is likely to be well under 30%. In their CSIRO study for AEMO James and Hayward (2012) say the energy efficiency of gas production from biomass is under 50%, If this is so the biomass-to-gas efficiency would be around 25%. However Thodey (2013) says the yield is only 0.7 – 1 kWh of gas per kg of woody biomass, i.e., an energy efficiency of biomass-to-gas conversion of around 13 – 20%. He also says that because of the difficulty of removing the tars etc. mixed in the gas it can be preferable to produce gas by fermentation at even lower yield.
Thodey also raises the issue of plant size. He says generators running on biogas have to be large to be efficient. If they are in the 2 – 5 MW range efficiency is only c. 20 – 25%. Because of the problem of trucking distance it is generally assumed that biomass fuelled operations would have to be small and numerous, distributed throughout biomass producing areas.

These figures probably refer to within-plant efficiencies and are very unlikely to have subtracted embodied figures, or other energy losses and costs such as for producing and trucking the biomass. It seems therefore that the overall sector energy efficiency would probably be no higher than around 20%. This low figure would mean that a lot of plant and equipment would be required to produce the amount of biomass and gas needed. The low efficiency would also increase the amount of biomass required. All this would also have a cost in embodied energy. It might be preferable to store via hydrogen, which has low overall efficiency..

Again confident conclusions are elusive, mainly because we can’t be clear about the amount of gap-filling power that would be needed, nor about the efficiency and cost, or indeed the viability, of plugging gaps by biomass-gas-electricity. It would seem however that the sector’s capital cost would be much greater than is assumed by EDM 2.

Hydroelectricity

It should not be assumed that there are no problems or limits regarding use of hydroelectric generating capacity and pumped storage capacity to plug gaps. Lang (2009) discusses these, including the limit that might exist on the amount of water that can be released into a river over a short period. EDM assume c.12 TWh, 5.9% of demand, from 7.1 GW of capacity. Using surplus wind and solar energy for pumped hydro storage involves the problem of whether the surplus rates are sufficient, continuous and lasting. Lang points out that pumps getting large volumes to start moving long distances might have to run for three hours to be efficient.

The dumping issue

It is puzzling that the amounts of plant stated in EDM Table 5 would generate only and no more than (approximately) the amount of power stated in column 3, which adds to the actual 200 TWh annual Australian demand. That is there seems to be no need to dump any surplus generated because when normal capacity assumptions are applied to those amounts of plant we arrive at the quantities of power listed in the relevant column of the table.

For instance Table 5 says that 34.1 GW of wind plant is going to contribute 94.8 TWh/y. But for that much plant to provide that much useable power over a year it would have to achieve an average capacity factor of 31.7% (a plausible annual average figure), provided that every Watt produced was used.

Similarly the 29.6 GW PV sector is assumed to provide 41 TWh of useable power. It could produce this amount if its capacity factor was 15.8%. This is about the generally accepted figure for PV, meaning that in a year that much PV plant would indeed have an accumulated output of 41 TWh, but it is very likely that much of it would be produced when it was not needed.

Thus the assumption seems to be that almost all power generated can be used when it is being generated. The gaps left by wind and solar will be filled by the large biogas component. (It has capacity equal to total average power demand, 23 GW.) This could well be a sound strategy, but the lack of dumped wind energy in particular is confusing.

Whether these claims are sound cannot be seen without access to the weather patterns assumed. However I one scenario it is claimed that the biomass-gas-electricity sector will only need to contribute 2.6% of total power demanded. This means that the four sources are being claimed to be capable of combination throughout varying weather patterns and demand patterns to almost always provide almost exactly the amount of power needed.

Table 5 EDM 2, (p. 23) states that only 4% of energy produced would have to be dumped. This is a surprisingly low figure. Huva, Dargaville and Caine’s exploration of renewable supply for Victoria (2013) found that for almost half of the time shown in their Fig. 7 the amount of wind capacity needed for wind to contribute its share would be putting out around two and a half times the total amount of power needed at those times. Only about 65% of power produced by wind could be used. (This is only an exploratory study indicating the approach being taken by a more detailed analysis that is underway, so its findings can’t be taken as conclusive. However the weather assumptions it is based on are highly favourable to renewables, involving a 20 day average, not winter, period containing only one difficult half day.) In the ZCA proposal it appears that almost half of the solar thermal output is to be dumped.

Remember that one of the EDM scenarios assumes that more than 50% of power is assumed to come from the highly variable wind sector. If at times this 34.1GW of capacity was running at 80% of peak it would be generating 27.3 GW… which is considerably more than total demand. (In the 10% discount scenario wind capacity is 47.1 GW and at 80% this would be generating 38 GW.) Clearly much of the time 34.1GW of wind capacity could be expected to be generating much more power than is needed given that the other 42.9 GW of solar would also be contributing.

To summarise, the claim seems to be that almost all power generated by wind, sun and hydro can be used, and almost never will their combined output fall short of demand. From the numbers given this does not seem to be possible, but the information given does not seem to enable the situation to be understood. Perhaps judgment should be reserved until the derivation from underlying weather data is made available.

Transmission losses and costs

EDM 2 advances on EDM 1 by including an estimate for transmission line costs, but again this is presented to the reader as a bald statement and despite lengthy and obscure discussion (of “genetic algorithms”) it is not shown how the figure is derived or that it is plausible. It is said that a simplified system is assumed and actual costs would probably be higher. Again this would require detailed access to weather patterns and the occurrence of low inputs and gaps, enabling assessment of the sufficiency of the transmission infrastructure claimed.

The total system cost?

Following is a rough attempt to compare only the capital cost sum (for the EDM 2 “least cost” and 5% discount rate scenario), with alternative conclusions derived from the above figures. The exercise is not precise or confident but it is a transparent indication that the capital cost sum for the amount of plant to deliver the power EDM assume would probably be several times that arrived at by EDM.

Table 1a sets out the capital costs for the amount of plant EDM 2 says is required in GW.

This seems to align with EDM estimates (they do not give separate figures for capital costs.) Their lowest cost total, $19 billion p.a., adds O and M costs and a 5% discount rate.
Because we cannot see whether the EDM conclusions re the amount of plant needed are sound, the alternative capital cost estimate in Table 1b is derived from the percentages of power contributed, as stated by EDM 2. It sets out the costs of these amounts of plant derived from the above conclusions re the amount of plant and capital required to deliver I kW at distance in winter.

N.B. EDM use estimated future capital costs whereas the alternative cost estimates in Table 1b use AETA’s estimated present costs. As will be discussed the crucial issue for renewables is affordability and in the early decades of the build-up period present costs will have to be paid, not the costs to which plant are predicted to fall by 2030 or 2050.

The difference is considerable. For Wind the ratio is 1.4, for PV it is 2, and for Solar thermal 1.5.

The above EDM sum arrived at in Table 1a does not include the transmission cost. The alternative table 1b below (unrealistically) assumes a transmission cost only for solar thermal.

This annual sum is around 2+% of Australian GDP. Present world investment in electricity supply, including distribution, is around .28% of GDP. (McCollum et al., 2012, , Rahai, et al., 2012, IEA, 2011, IPCC, 2014,Ch. 16.)

There are several reasons why the real world multiple would be much higher than this $32 billion figure.

  1. As discussed re dumping above, Table 1 b assumes that the power can be produced when it is needed and there will be no dumping. But to deliver the quantities in column 1 of the table there would probably have to be much more generating capacity than would produce these amounts, because much of the output would not be being produced when it was needed. If significant dumping would occur this would affect sector ER and thus raise the capital cost per delivered kW assumed in Table 1b.
  2. The PV, wind and solar thermal capital costs assumed in the above alternative derivation are likely to be much lower than those that will eventually be arrived at following thorough accounting of embodied and downstream costs and losses, and of the solar multiple and low DNI/efficiency issues. EDM do not include or discuss these factors. (Note again the high Gemasolar cost from the real world, as distinct from predictions from theoretical modelling, and the fact that the NREL rooftop PV cost estimate is double AETA’s figure, which is double the figure EDM use.)

  3. We cannot assess whether the amount of plant assumed is sufficient to cope with gaps in the wind and solar resource, and there are reasons for thinking that it is not.

  4. The winter wind capacity factor assumed, 38%, could be 60% higher than it should be.

  5. In the alternative costing the embodied energy costs of the long distance transmission systems have not been included. These must be deducted from system output.

  6. A realistic cost for the biomass-gas-electricity sector would include all the elements in addition to the turbines, and none of these have been included in the alternative costing. If the biomass has to be burned the capital cost for generation would probably be 6 – 7 times as high as EDM assume.

  7. No account has been taken of the energy costs of O and M within the various sectors, including for the transmission system. These reduce power delivered and thus raise the capital cost per kW delivered.

  8. Energy is a major input into the production of energy producing plant. If its price rises significantly then this will multiply the dollar cost of all inputs into the building of renewable plant. In addition the cost of raw material inputs will probably rise greatly in future, due to increasing scarcity, especially of rare materials for wind generators and PV modules. Lower ore grades will require greater quantities of energy to process. Some analysts do not believe there are sufficient crucial materials for renewables to scale up significantly. These many interactions and positive feedback loops will surely play havoc with the common expectations and “learning curves” re the future capital cost of renewable energy plant.

EDM say the cost of the renewable system would be lower than the cost of a fossil fuelled generating system. It is difficult to see how this makes sense. Their EDM 2 Table 5 states that the lowest annual cost estimate is $19 billion, but taking the AETA cost figure for coal-fired plant, (beginning at c.$3,100/kW p), the annual capital cost of 37 GW of coal-fired plant, lasting 50 years, would be about $2.3 billion. The fuel cost for a 23 GW average supply would add perhaps $1.6 billion p.a., and adding the O and M cost estimate from AETA would bring the production cost for power sent out to around $5+ billion p.a., which is approximately only 25% of the lowest stated EDM 2 cost for a renewable system (although no discount rate has been included in this fossil fuel cost estimate.)

EDM do not point out that their lowest cost figure, $19 billion p.a., is about twice the wholesale amount Australians pay to purchase power from the generating companies at present. Their figure does not include several items such as company taxes, insurance, profits, and energy use by the generating company. This aligns with the above indication that at present production costs are a small fraction of what they would be from the EDM proposal, even taking their capital cost conclusions.

Note also that there is the big difference between the wholesale cost of power and the price we end up paying for it. The wholesale price of power at present is only about one-fifth of the price purchasers pay. What would the retail price be derived from a production cost several times those which EDM claim?

“But all this has been in terms of present capital costs. These will fall.” Reasons for caution about this have been noted. Wind costs are not likely to fall. PV cost is assumed to go on falling but this is questionable if Chinese subsidies to the industry cease. Solar thermal costs are likely to fall but the commonly quoted Australian estimate for the latter is only about one-third. Much more importantly, the falls are expected by 2030 to 2050, and during the first decade of the building period present costs would have to be met.

That is why this analysis has been carried out in terms of present capital costs, because these will determine whether it is affordable to make the very large financial commitment to 100% renewable supply..

As has been stressed there can be little confidence in the alternative cost numbers arrived at here, and the solar thermal figure is especially uncertain. The annual $32 billion investment cost is not to be taken as a realistic estimate. The point is only to show that this approach to the issue provides grounds for thinking that the cost conclusions EDM arrive at are probably a small fraction of what the costs would be. It cannot be concluded here that the cost will be greater than Australia can afford, but if some of the above possibilities become realities, at best paying the price is likely to be very difficult and disruptive.

What about the remaining 80% of energy demand?

Electricity makes up only one-fifth of energy used in Australia. From where and in what form will the other 80% come in a 100% renewable economy? Especially problematic is where will the one-third of energy going into transport come from. Australia is highly atypical in having much land that could be put into plantation biomass production (Europe has relatively little) so ethanol/methanol might be the most promising solution here. However this would require a lot of land, and ERs for biofuel production are low (Weisbach, et al., 2013, rate these as well under the ER of 7 they think is needed for viability.) If transport and all other possible functions were to be converted to electricity then some of the above problems would be intensified. For instance how much storage or biomass back up would be required to deal with big gaps if 80% of energy is to be supplied in the form of electricity?

Conclusions

These have been very rough and uncertain figures but they indicate the magnitude of the challenge which this proposal seems to face. The general EDM approach seems to be the right one, e.g., combining renewable technologies at every point in time and attempting to solve the storage problem via biomass, and it represents significant progress in our understanding of the issue. Grappling with it has helped me to a better grasp of important issues (and of where some of my previous analyses can be improved on), but I think the account falls a long way short of showing that 100% renewable power supply is achievable at an affordable cost.

This has been an attempt to make some progress on the 100% renewable issue and I am not confident it is correct in all major detail. Critical feedback is being requested. I add my usual note that this is not an argument against the need for rapid transition to full dependence on renewables; it supports the view that energy-intensive consumer-capitalist society cannot be run on them.

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29 Comments

  1. Ted,

    Well done. Below are a few quick first thoughts. I haven’t kept up with EDM’s recent papers, so some of these comments may not be appropriate.

    It is not difficult for an approach of this kind to show that electricity demand can be met, and many impressive 100% renewable energy proposals have been published. (For critical analyses of about a dozen of these see Trainer, 2014), but a great deal of redundant capacity would be needed, and the key questions are, how much, and what would it cost? My present uncertain impression is that Australia might be able to afford to do it, but if it could it would be with significant difficulty, i.e., with major impacts on lifestyles, national systems and priorities, and on society in general.

    1. I am not persuaded that biomass generation can provide reliable back up. The reason is the logistics of storage, transport and contracting for near 100% reliable supply to nearly every biomass power station through all conditions of drought, flood, fire, etc. CSIRO’s report to the AEMO study on 100% renewable generation excluded logistic constraints from consideration. So did the AEMO report. See my Feb 2012 comments on the issues with biomass for reliable back up here:

    http://bravenewclimate.com/2012/02/27/100-renewable-electricity-for-australia-response-to-lang/#comment-151865

    http://bravenewclimate.com/2012/02/27/100-renewable-electricity-for-australia-response-to-lang/#comment-152532

    1. Why should we consider a high proportion of renewables generation given that the nuclear option is so much cheaper. My paper “Renewables or Nuclear Electricity for Australia –
      the Costs
      ” estimated the cost of the nuclear option to provide 90% emissions reductions from NEM electricity generation would be 1/3 the captiatl cost, 1/2 the cost of electricity and 1/3 the CO2 abatement cost. See Figure 6 here: http://oznucforum.customer.netspace.net.au/TP4PLang.pdf
      It should be noted that the AEMO analysis is far more sophisticated than my simple spreadsheet analysis. My cost estimates for the additional transmission are probably too high, but AEMO admits that the costs would be higher than they have estimated.
    2. CSIRO’s calculators ‘MyPower’ and ‘efuture’ show that nuclear is significantly cheaper option than renewables.

    Nuclear cheaper and lower emissions than renewables
    Renewables v Nuclear: Electricity Bills and Emissions reductions by technology proportions to 2050

    The CSIRO ‘MyPower’ calculator shows that, even in Australia where we have cheap, high quality coal close to the main population centres and where nuclear power is strongly opposed, nuclear power would be the cheapest way to reduce emissions: http://www.csiro.au/Outcomes/Energy/MyPower.aspx

    “MyPower is an online tool created by CSIRO that allows you to see the effect of changing the national ‘electricity mix’ (technologies that generate Australia’s electricity) on future electricity costs and Australia’s carbon emissions.”

    Below is a comparison of options with different proportions of electricity generation technologies (move the sliders to change the proportions of each technology). The results below show the change in real electricity prices and CO2 emissions in 2050 compared with now.

    1. 80% coal, 10% gas, 10% renewables, 0% nuclear:
      electricity bills increase = 15% and emissions increase = 21%
  2. 0% coal, 50% gas, 50% renewables, 0% nuclear:
    electricity bills increase = 19% and emissions decrease = 62%.

  3. 0% coal, 30% gas, 10% renewables, 60% nuclear:
    electricity bills increase = 15% and emissions decrease = 77%.

  4. 0% coal, 20% gas, 10% renewables, 70% nuclear:
    electricity bills increase = 17% and emissions decrease = 84%.

  5. 0% coal, 10% gas, 10% renewables, 80% nuclear:
    electricity bills increase = 20% and emissions decrease = 91%.

  6. Points to note:

    • For the same real cost increase to 2050 (i.e. 15%), BAU gives a 21% increase in emissions and the nuclear option a 77% decrease in emissions (compare scenarios 1 and 3)

    • For a ~20% real cost increase, the renewables option gives 62% decrease and nuclear 91% decrease.

    • These costs do not include the additional transmission and grid costs. If they did, the cost of renewables would be substantially higher.

    Conclusion: nuclear is the least cost way to make significant reductions in the emissions intensity of electricity.

    The difference is stark. Nuclear is far better.

    But progress to reduce emissions at least cost is being thwarted by the anti-nuclear activists.

    I have some other points to add later, but this is already a long a comment.

  7. Engaging with EDM regarding their publications is no more productive than arguing with someone who denies that the globe is warming. In both cases, the adversary chooses to rely on discredited data.

    Hence, the discussion leads nowhere.

    While I very much appreciate this article, it is beyond disappointing to know that EDM re not going to listen, respond or cease their politicking about the cost and achievability of 100% renewables. That they have maintained this incommunicative stance for 3 or 4 years is incredible.

    If this site was to decline discussion of this topic unless and until the proponents demonstrate academic honesty by responding rationally to criticisms, then that would be entirely understandable.

  8. Ted, excellent analysis.

    I think this sort of analysis draws out some of the overlooked issues of 100% renewable plans. As you note, this is not an argument for abandoning renewables but a need for more rigorous assessments. The overlooked difficulty with EDM (and other) plans is that they are really just extensions of the fossil fuelled enterprise, yet they claim to be able to replace the fossil fuelled system – a fundamental contradiction. Many other macroeconomic impacts, such as the resulting decline in labour and capital productivity of the energy supply industry, are simply not canvassed.

    A typical case in point is steel production – the sort of Australian plan EDM envisages would require tens of millions of tonnes of steel for wind and CST – equivalent to some years of Australian steel demand. Yet there is no practical large-scale alternative to metallurgical coal for smelting the 1.5 billion tonnes of iron that is produced globally each year. A partial reversion to charcoal-based steel smelting could be theoretically possible with a high enough carbon price, but the subsequent competition for the limited “sustainable” forestry biomass would be intense; charcoal production would be competing with biofuels, paper pulp, greater use of sawn timber for construction, and firewood.

  9. Graham, I agree with you regarding embodied energy in materials of construction, but with one caveat.

    Concrete has been eliminated from construction of solar thermal arrays by at least one supplier, Novatech, by use of soil nails (screws).

    This supplier also has developed very lightweight designs and modern fabrication methods for panels and frames.

    The caveat is that we must take care when we are examining others’ proposals to use current best practice figures and ensure that older less efficient designs are avoided. Estimates of the tonnes of glass, aluminium, steel and concrete which are more than a few years old, 5 at the maximum, are probably out of date.

    This is good news but in no way does it justify Elliston, Diesendorf and MacGill’s silence in the face of rational critism.

  10. singletonengineer, good point re establishing the most recent data.

    I note that the Novatech system is fresnel, which is similar to the parabolic trough that EDM have assumed, and less demanding than central receiver structurally. The main problem with these is that they are really only useful outside winter – below an insolation threshold no electricity is produced. On the other hand, central receiver use large mirror assemblies on twin axis drives and require precision tracking and more structural rigidity, and these are relatively better in winter.

    Your point on recent information is good, but it’s also interesting to see how some things haven’t changed. A paper in Energy Policy by David Mills et al from 1994 is a case in point, where it is stated in the abstract:

    … such price and availability could make solar thermal technology highly competitive for new electricity supply, possibly before the year 2000.

    Mills, David R., Anthony Monger, and Bill Keepin. “Cleaning up the grid Solar thermal electricity development in Australia.” Energy policy 22.4 (1994): 297-308.

  11. I worked on two of David Mills’s early SHP jobs and subsequently supervised demolition of the first, which was a proof-of-concept test unit.

    At Liddell Power Station in NSW the remaining SHP array sits alongside the more recent and far more elegant Novatech example. SHP uses heaps more metal plus hundreds of tonnes of concrete as against the other’s nil concrete and probably 1/3rd the mass of metal per square metre of reflector (mirror).

    When last I saw them, late last year, neither was in service although I understand that technically they were both available for service.

  12. While not yet actually available as utility scale batteries, at least two companies are trying:
    http://bravenewclimate.proboards.com/thread/386/utility-scale-batteries
    The EOS unit will, perhaps, provide electricity for up to 6 hours after charging; they claim a 30 year life for the battery. This might resolve the power dumping issue for solar PV by providing the power for afternoon air conditioning.

    From my own efforts, I agree that biomass can only ever be a niche player for electricity generation.

  13. When will the definitive analysis be written which shows conclusively what we’re already arguing on this site which is that the nuclear option is the only one that can do the job in a timely manner without breaking the bank?

    We have to stop struggling to analyze the unworkable arguments for wind, solar, and whatever.

  14. If neither the original proposal nor this critique consider vehicle-to-grid storage, then none of the people involved have used their noggins very well. It’s not a particularly new or novel idea– just a good one.

    “Even if a large EV fleet couldn’t handle the full extent of a 50-percent wind power penetration in a country like Denmark, which could be fossil fuel-free by mid-century, it could clearly make a dent. And Denmark has already gone beyond the theoretical, with a V2G project called EDISON running on the small island of Bornholm. The goal is to use the storage capacity of EVs to bring the island’s wind power capacity up to 50 percent of the total demand.”
    Electric Cars
    Can Play a Key Role on the Grid

    “The advantage of using car batteries that consumers are buying anyway is undeniable.”

    So how about that? Maybe consumerism isn’t necessarily evil after all. With a vehicle-to-grid system, the more electric cars people buy, the more stable the grid becomes. Think about it… with millions of vehicles participating… you can’t design centralized energy storage to compete with that kind of capacity and resilience.

    A little creative thinking is in order: take advantage of synergies. Need to convert excess energy? You can make liquid hydrocarbon fuels out of biomass, municiple waste, or directly out of the air. Liquid hydrocarbons are an incredible means of energy storage.

    One thing is perfectly clear. If you are arguing for 100% reliance on wind and solar, then coal and natural gas are going to make up the difference. Since energy needs are ever-increasing, the 100% renewables scenario basically means business as usual: increasing carbon dioxide levels in the atmosphere.

    Creative thinking implies reasoning unclouded by faulty assumptions. I don’t even know where to begin with the faulty assumptions clouding Ted Trainer’s reasoning. Here’s one that might cut right to the heart of it: you can’t use Marx’s criticism of capiltalism and discard the politics. Those are intertwined and inseparable. Calling for the radical restructuring of society and the economy is a non-starter, full stop. That should be obvious.

    Protecting biodiversity is being done on the largest scale, and in the most effective ways, in the nations which are the most consumerist, technologically advanced on Earth. For many good reasons, and I’m not going to get into them here– use your noggin– the best way to “save the planet” is 1) bring the entire world up to modern education and living standards and 2) start building modern generation III+ nuclear plants.

    If anyone wants to contact me personally to argue or cuss me out or whatever, contact Barry and he can give you my email address.

  15. The Australians must hate nuclear if the costs and problems are as stated or they believe nuclear will cost more with uranium going up higher then the $140 before 311, the yearly cost for fuel may more then double or quadruple and then storage and permanent storage has to be handled, after seeing WIPP with a unlimited budget of tax dollars screwed up by cat litter makes one wonder about the future storage. Also has nuclear ever built a plant any where near estimated price. We also know for sure the nuclear industry gouge the public, how much profit did they make at $140 when later selling for $40, I will be viewing the Saskatchewan earnings closely.

  16. Thanks for the thorough review and many good arguments. A few comments from Germany:

    1. cheap nuclear:
      a) take real costs of new nuclear power plants and you end up with costs per kWh higher than PV (e.g. look at pricing agreements for Hinkley Point C in the UK which exceed the PV feed-in tariff for PV in Germany)
      b) base load plants are less and less useful in a world with more renewables, so the argument of “dispatchability” counts less and less in favor of nukes, and more an more against them. The export capacity from Germany you mentioned is now mainly needed because nuclear and lignite baseload cannot react to low residual demand. We had 75% renewables in the system at midday on a Sunday a few weeks ago, with negative prices at the power exchange because baseload was not (could not be?) cut back sufficiently.
      c) add to that the real cost of insurance including full coverage of large mishaps, which is a huge hidden subsidy right now. Just approach a commercial insurance company and ask for a quote for a fully comprehensive 3rd party coverage for a nuclear power plant. The insurance mathematicians will put a pricetag on the risk that boggles the mind.
      d) German utility companies are imho essentially bankrupt (even though they do not admit to that yet) facing the decommissioning costs of the 17 German nukes. They have just offered to hand all nukes to the government including a payment of 30 bln Euro, if the government takes the decommissioning costs and risks.
      One could argue that the nukes are shut down prematurely because of Fukushima and had a few more years in them, but after 35 to 40 years they would have been up for decommissioning soon anyway.
      e) Nobody yet knows were to go with the waste. We can keep ignoring that argument, but it does not go away, just because we cannot find a safe solution to the problem.
      In Germany we now need to remove the waste from a nuclear storage site in a salt dome (Asse) because the impossible water entry has now happened afterall. Unfortunately nobody knows how to remove the waste, so it has been declared a problem for the coming generations, with the start of waste removal now planned beyond 2030.
    2. Cost of PV:
      For calibration with real prices: I sell and build rooftop PV at around 1300 to 1500 Euro/kWp for plants of 5 to 30 kWp (= 1750 to 2000 US$/kWp). Some competitors even sell at 1100 to 1300 Euro/kW. Utility scale PV goes for 1000 Euro/kWp (1350 US$/kWp). Fully installed.

    3. Contribution of rooftop PV unknowable?
      With many small scale installations the contribution cannot be measured completely accurately, but there are ways to calibrate the models. In Germany the leading inverter manufacturer SMA has access to the data of most SMA monitoring systems covering a large proportion of German PV installations. These are extrapolated to get the contribution of all PV installations. Real time data can be seen here http://www.sma.de/unternehmen/pv-leistung-in-deutschland.html
      Not perfect, but pretty good.

    4. Storage and excess capacity
      Vehicle to Grid was already mentioned and first vehicles with that ability will be presented by Mitsubishi at the InterSolar exhibition this week.
      The other (under-appreciated) path is Power to Heat. As long as gas is burnt for heating, hot water or industrial processes we have an easy 1:1 storage scheme. Substitute gas with electricity using a dead cheap resistance heater and you get 1 kWh of (saved) storable gas for every kWh of renewable electricity. Use a heat pump and you look at 3 to 1. Similar for cooling applications. Heat and coolth are more easily stored, so this offers a huge buffer for the power system.

    5. Cost of back-up
      Worst case you need a kW of cheap gas turbine per kW of peak demand at 300 to 500 US$/kW. Efficiency is not important if they only run for few hundred hours a year, so no need for expensive combined cycle plants. If you include emergency generation capacity that already exists for other purposes, the need will be much less. If you let V2G develop a bit further you’ll need hardly any dedicated back-up capacity at all. Plug-in hybrids with V2G can make good emergency power plants. The 40 mln passenger vehicles in Germany have a combined power rating of around 3000 GW. A 3% market penetration with V2G Plug-ins would cover the entire German peak demand.

    6. Overall system
      All studies of 100% renewable power are in the end just scenarios highlighting possible pathways and potential problems, not execution plans for a huge transition project. In the overall system a good mix of different kinds of renewables together with a link of power and heat markets and a link of power and mobility offers a lot of tools to balance the system. Who knows what the mix will be in the end, guess we will find out by learning as we go.

    best regards
    Jochen

  17. Scenario for a largely Nuclear powered future:
    Mass production of inexpensive reactors
    Thorough consumption of existing stocks of nuclear waste
    Hydrogen powered transportation
    As much sea water to fresh as needed
    Reclamation of previously unusable trash into useful material through high temperature conversion
    Upgrade of the third world to western levels
    Production of fertilizer for farming
    Eventual entry of Fusion generation
    Repair of environmental degradation with geo-level projects possible
    The list is endless…

  18. @ Jochen:
    1a. While you are looking at Hinkley Point, consider that its power is available all day, every day. PV is not unless and until you find a way to make the sun shine at night through a rain cloud. You have conveniently forgotten to include the cost of connection to the grid, of the backup plant and anything else that does not come out of the boxes which you sell. That is dishonest.

    1b. Base load plant, eg nuclear, is capable of being ramped up and down – the misnomer “base load plant”, as used by you, is a deception used to draw attention away from the unreliability of so-called renewables, which in practice are often really “replaceables”. By this I mean that they work when new, the sun is shining and the wind is blowing (but not too hard). When these conditions are not met, then they have to be replaced by other electrical sources, either fossil fuelled or nuclear. Further, when they wear out, they are not “renewed”, but are “replaced” every 15 years or so. There are old PV, Solar thermal and wind installations across the globe that have not been recycled or renewed, but simply abandoned, as any Google search using the terms “abandoned wind turbines” or “abandoned solar power” will demonstrate. Your costs per kW installed do not include for this, yet you have the affrontery to state that dismantling of nuclear power stations is not costed.

    1c. Insurance and related. It is not enough to simply say that “insurance costs will … boggle your mind” for nuclear options, without first considering the safety record of nuclear Vs other options. Nuclear is far and away safer than even the product which you sell on a cradle-to-grave basis, so why do you say that it is dearer to insure? Sure that you are not imagining things? I am not imagining the impost in your country of a charge on nuclear power which goes straight to the government’s fund for wind and solar. This is an artificial, unfair and just plain silly way to run a country and its energy supplies, but that is the type of thing that happens when politicians make decisions about other people’s money.

    The simple, fairest question to ask is whether your business could survive without government’s legislative and financial support.

    1d. Costs of decommissioning nuclear installations have been wildly inflated by over the top legislation. I have already stated that nuclear power is much safer than any other form of new electrical power supply on a cradle to grave basis. Over-regulation by governments adds very substantially to the cost of maintenance, decommissioning and eventual demolition of nuclear power plant, so why should not the added costs be handed back to the politicians to deal with? I have a close friend who was almost killed while maintaining his PV system. Where does this appear in your calculations? And when was the last time that you heard of a nuclear power plant worker being injured or killed during maintenance?

    1e. “Nobody knows where to go with the waste … or how to remove it”. That is simply not true. What is true is that you and others, with either personal agendas or even financial conflicts of interest, pretend that there are problems where they don’t exist. Where do you tell your customers they should go with the waste from their PV installations? How do you tell them to finally store that fraction of the waste that is (chemically or physically) hazardous? Where do your dead and dying PV cells go to – landfill?

    1. Cost of PV needs to be on a cradle to grave basis. The figures you quoted are only part of the story, and a small part at that. Just because you have access to BNC through the internet does not justify coming here and trying to perpetuate the myth that the landed cost of PV components is the first, last and only cost of PV. That is not only dishonest, it is damaging to the serious attempts by others who are trying to develop viable responses to the real and pressing problems caused by anthropogenic climate change.
    2. Correlation of PV input Vs demand on the grid has been discussed many times,including via peer reviewed publications. The purpose of this article was to demonstrate the impossibility of dealing with Australia’s leading proponents of myths and undefended claims that in the Australian context, renewables can achieve 100% penetration. Three leading proponents of this 100% nonsense have refused to respond to criticism of their claims. It is their claims that have not been answered. Your citation of a one-off study in a German context does not address that lack of academic candor or rigor.

    3. Storage and excess. If only Diesendorf and others could make the numbers work, I am sure that they would expose their full calculations to public scrutiny. They have not done so. Adding a bit of electrical resistance heating to the mix does nothing to let E,D&M off the hook.

    4. EDM made no reference to GT backup, whether open cycle or combined, apart from in the context of biofuels. Your suggestion that GT’s are needed to support PV is absolutely correct, but as noted above, you have failed to include this in your costing. You have failed also to include for the impossible cost of 100% CCS for your preferred and inefficient OCGT’s. EDM also did not base their costings on battery storage, whether via vehicles or otherwise. Indeed, EDM’s costings, such as they are known, are secret, known only to them. It is up to the person making the claim to complete the financial evaluation.

    5. No, this is not a question of “Who knows the costs?” or “We will find out as we go.” EDM have made unjustified statements about the cost and practicality of 100% renewable power supply for Australia. The whole point of this article is not to re-start the discussion of PV, etc, on a blank page and using cherry-picked data provided by a commercially conflicted source in a foreign context. Ted was trying, as he and others have done repeatedly over three or four years, to highlight some of the inadequacies of EDM’s published work. EDM, as academics, should either withdraw their publications on this subject or respond to rational, specific criticism. Until they do so, then they are exposed as publicists for a cause, rather than as professionals, but Ted is too much a gentleman to use the words I have just used.

    So, Joken, what do you have to say about Ted’s article, if anything?

  19. @singletonengineer,
    sorry that I confused a personal vendetta against EDM for an attempt to discuss the content ;-)

    And do you feel threatened by my points that you have to be so personal in your response? That was certainly not my intention.

    To clear up my financial conflictedness:
    a) I cannot see how I would possibly derive personal wealth from participating in this discussion. Can you?
    b) I have given up a VERY well paid job in the oil industry to now do what I believe in. I do what I do because I am convinced that working towards 100% renewables is a good thing, rather than the other way around.

    Could my business survive without policy support? No-one in the energy business survives without regulatory support like the right to feed into the grid, market rules, etc. And it did need the learning investment provided by past high feed-in tariffs to get to a point where we have blown past grid parity in Germany, approach wholesale parity in the US and fuel parity in the Middle East (same as the nuclear industry could only start with government support). Economically PV is now competitive in many places, certainly against true full cost of fossil and nuclear power.
    The power markets here are geared towards Merrit-Order based on marginal costs and do not include external costs (risks borne by the people, costs of climate change, effects of extraction of fossil fuels such as lignite mining, pollution for example with 6+ metric tonnes of Mercury that German coal plants spread over the country every year, etc.)
    This market model will have to eventually change if more and more capacity with 0 marginal cost comes into the market, and as external costs are valued more by society.
    Macro-economically it makes a lot of sense anyways as it keeps more and more of the 90 bln Euro per year in the country that Germany currently spends on energy imports.

    But let’s bring this back to content and rational discussion:
    1. The cost of nuclear energy is low ONLY if the plants run 8000+ hours per year*, i.e. if they get priority in the grid with other generator types filling in the peaks.
    Once you start to regularly ramp nukes down to do load following the economics really suck. So technically you are right, they could be ramped down, economically they remain base load plants.
    * and if insurance and 100 000 year waste disposal is carried by the people.

    The cost of insurance: just try! I have talked to someone at Munich Re on the subject. Point is, they won’t insure the full risk, even in a consortium of the largest re-insurers, because the consequences of a large accident are just so insanely high, that the risk is uninsurable. Consequently the insurance sum of the employees cars parked in front of a German nuclear power plant exceeds the insurance sum for the nuke itself.

    When have I last heard of a worker injured in nuclear maintenance? 9th May 2014, when 10 workers were contaminated with radiation at the Catenom nuclear plant in France (less than 100 miles from my home).

    Waste disposal: you seem to know where to go with the waste. I’d appreciate if you could point me to a disposal site for highly radioactive waste that is operating right now and can be considered safe to keep the waste contained for 100 000+ years.

    1. It was not my intention to state that the initial cost of PV is the only cost (nor “to perpetuate a myth”), merely to provide a real world calibration point for those initial costs.

    As to the dismantling costs for PV. I can assure you that I can carry those costs for my own plants (same as I carry the costs of 3rd party liability insurance for my PV plants) and that they are included in my economic decisions for my own plants and the advice I give to customers. I will also be able to dispose off my panels safely (they will be mostly recycled, what residual waste is left is inert and can be stored without risk). The nuclear operators do not seem to be able to carry the full costs of dismantling their operations as the developments in Germany start to show. No wonder, as those costs occur after the cash cow is switched off. To think that the nuclear operators will be able to cater for the 1000s of years of keeping the waste stored and guarded safely is just silly. Of course these costs and risks will be borne by the people.

    1. Power to heat: also here my intention was not to let EDM “off the hook” but to provide an insight that is growing here, where penetration with intermittent renewables is relatively high (ca. 20% average, over 70% at peak times). If you can “dump” the occasional excess in the heat market, substituting gas that would otherwise be burned, excess renewable electricity has at least the fuel value of gas until BOTH markets are saturated at any one time. Since heat storage within a day or two is trivial this takes some of the intermittency issues away at very low costs. This then allows more peak capacity to be built and makes it a lot easier to achieve 100% renewables in the power sector.
      For not including this effect EDM should be criticized. Unfortunately this criticism goes in the other direction as it makes 100% renewables in the power sector easier, not more difficult. Not sure though whether you are looking for criticism in that direction … .

    best regards
    Jochen

  20. @Jochen Marwede,

    You say “Once you start to regularly ramp nukes down to do load following the economics really suck.”.

    However if the output of renewables is curtailed and they run at reduced load factor, the economics suck just as badly or worse. The economics is very sensitive to load factor. A situation compounded by the correlation of output between generators. No such correlation exists in general for nuclear generators.

    This is a really tired anti-nuclear argument advanced because it is just that – an argument – and not part of a serious analysis. Very one-eyed.

    Meanwhile in the real world the recent IEA report says that Europe needs 100 GWe of new thermal capacity by 2025. You can it from fossil fuels, or at a really big stretch biomass or nuclear. Solar and wind are not a substitute. I’d go for least environmental impact – nuclear.

  21. @quoka,
    a key question is which generators get priority and which carry the “additional cost” of back-up or load following*.

    This has traditionally been resolved by marginal operating costs. On this basis the nuclear operators got used to the idea that they get first dips on the Merrit Order Curve, straight after must run hydro power. Against this history we get the call that the cost for back-up and load following services must be borne by renewables as the newcomer.

    Unfortunately many renewables have marginal costs of zero or near zero and get first dips on the Merrit Order Curve now. So unless you are saying that we do not want ANY renewables in the system, nuclear power plants will lose their priority access and will have to start reacting to residual demand. There is no room anymore for base load plants running 8000+ h/a.

    Same by the way in a 100% nuclear scenario. where nukes would have to follow the overall demand curve and could economically not cope with the fact that you need to keep capacity for the worst day in 20 years, but only run the last few GW for a few days a year.

    Under both those circumstances nuclear plants (with high capital and high fixed operating costs) do become more and more expensive per kWh. Not “just an argument”, but economic reality.

    Good luck justifying 100 GWe of thermal power plants in Europe before 2025. The IEA clearly haven’t heard the shot yet. A bit like Mr. Grossmann, CEO of one of the big 4 utilities in Germany, who even 5 years ago tried to ridicule PV as “just good enough to charge an iPad”. Now his company is struggling with the realities of a changing system.

    best regards
    Jochen

    *More rationally one would of course ask, which overall system does the job best in the balance of affordability, security of supply and (environmental) risks, rather than pinning the problem on individual power generation methods.

  22. What shows up in the background of Jochen’s remarks is reminiscent of other anti-nuclear commentary. None of them speak of new nuclear technologies, none of them seem to recognize how much “juice” we’re still getting out of older reactors. None of them seem to realized that uranium is, in fact, a very cheap fuel and abundant as well. You rarely hear about Thorium or IFR’s except to point out “problems” they have had.

    What’s clearer is the real difficulty of explaining how a “renewables” economy would work. It’s as if none of them understand the extreme difficulty of networking the transmission of power from 10’s of thousands of low power nodes (wind and solar generators) into a grid and the impossibly complex job of switching these loads when needed. (Just think of some of the huge power outages we’ve had just working with our much simpler existing grids). The vast amount of earthwork need to underground these units is a huge endeavor I’m sure is disruptive to ground water issues, not to mention he short life span of wind turbines and PV panesl which are subject to sand storms, high winds, and lightning.

    Nuclear plants live in a strong protected environment. And as in the case with all our existing units, they are constantly being upgraded to higher safety standards. We’re finding that many are likely to last 50 to 60 years or so such that the last thirty is mostly gravy.

    Given the phenomenal (present) reliability of nuclear and the emergence of generation IIII technology, it’s astounding that people are still standing in the way of some of the most promising technology imaginable.

    It seems they are missing the “sky is falling” quality of their message and tone.

  23. When the time for restrospection arrives, the real miracle of Fukushima will be how well the structure stood up in spite of the tsunami and design defects, and how locallized the radiological impact will be found to be.

  24. @ Jochen:

    Hypothetical discussion of present and potential nuclear power options is off-thread. As I said in an earlier post, the issue is Deisedorf et al’s failure to man up and defend their work.

    Jochen and other PV, ST and wind afficionardos should agree with Ted Trainer that their own cause is weakened by the very public sideshow which has been run for a handful of years by Elliston, Diesdendorf and MacGill.

    If I recall correctly, Barry Brook’s stated position, which I share, is that all low- and no-carbon energy options must be considered on their merits. Elsewhere on BNC you will find discussions of demand management, load shifting, battery storage, pumped hydoro and Jochen’s recommendation of electricity-to-heat options. All cards are on the table. This site is not anti-renewables, but it does try to get to the facts.

    What I object to very strongly is:
    1. Commercial/financial. The magical notion that, somehow, “renewables” (actually, “unreliable disposables”) are special cases and thus need/warrant support above and beyond that which is available to their commercial competitors; and

    1. Safety. The imaginary notion that safety statistics for nuclear power options can and should be dreamed up, rather than based on the same parameters that apply across all trechnologies and indutries. Hazards and risks must be compared on the same terms. Jochen no doubt understands that workers who are subjected to low levels of radiation have not yet suffered injury or loss and that they may never do so. The example cited, “9th May 2014, when 10 workers were contaminated with radiation at the Catenom” is essentially meaningless unless all exposure to carcinogens in all industries is assessed using the same statistical methods. Exposure due to ingestion of meat? To sunlight while working on roofs or outdoors? To chemicals such as solvents and hardeners used in the workplace? The farce which is nuclear safety regulation is in need of review for the same reasons that ED&M’s methodology and findings are in need of review – they lack rational foundation, but this is also discussed elsewhere on the BNC site and is off-topic here.

    ED&M’s continuing failure to respond to criticism in the manner that every other academic on the globe must. is the issue which Dr Ted Trainer has raised here. Why should a subset of three academics be able to claim academic authority while simultaneously avoiding public scrutiny of their claims? Their universities have serious unaddressed professional standards issues to attend to, however that is a matter for their own consideration and action. If any university or group of universities’ reputations are damaged thereby, then so be it.

    ED&M’s silence is better understood as a Religion Vs Science discussion, with themselves as the high priests. Any attempt to deflect discussion of 100% renewables along an anti-nuclear path or to base it on an assumption that Germany’s “energiewende” is successful irrelevant, although in relation to this, see http://notrickszone.com/2014/04/27/angela-merkels-vice-chancellor-stuns-declares-germanys-energiewende-to-be-on-the-verge-of-failure/ for Germany’s political #2, the Economics Minister’s very recent announcement that the Energiewende is a failure on all fronts. There is little doubt that he knows very well what he is talking about.

    Ted stated the case. There has been no rebuttal. ED&M’s position, though comforting to some, lacks foundation.

  25. World Bank recently published a report: ”Agreeing on Robust Decisions: New Process for Decision Making Under Deep Uncertainty” http://documents.worldbank.org/curated/en/2014/06/19616379/agreeing-robust-decisions-new-processes-decision-making-under-deep-uncertainty

    The engineers and objective, rational thinkers will probably appreciate this.
    [I haven’t read the report yet].

    I’d like to discuss formal decision analysis for climate mitigation policy advice with others on BNC if that is an allowable topic for discussion.
    BNCMODERATOR
    Please start a topic of your own choice on BNC Discussion Forum. http://bravenewclimate.proboards.com/
    Links to CC denier website have been removed.

  26. Hi, Peter and others.

    My apologies for not having the tools at my disposal to check as deeply as I would like – I am sending this from a basement in Jekabpils, Latvia, where I am holidaying.

    Re the World Bank’s publications, Kalra Nidhi’s paper which was the basis for Peter Lang’s comment, WPS690, June 1, 2014, is no longer able to be found on the World Bank’s site. Neither is its predecessor, a somewhat shorter working paper, WPS6765, 1 Feb 2014. It is not reasonable to proceed far without a copy of these. I note also that Peter Lang states that he has not read the primary work.

    Bonsantino, the co-lead author, is also listed on the WB’s site in respect of WPS6765, which as stated above is not available.

    Has the WB withdrawn these publications?

    I have checked out Judith Curry’s site as referenced by Peter Lang.
    Its gist seems to be: “Assuming that climate change and other deep uncertainties cannot be eliminated over the short term (and probably even over the longer term), the conventional decision-making methodologies that are used to assess projects that may be affected by climate-related uncertainty, namely cost-benefit analysis under uncertainty, cost-benefit analysis with real options, robust decision making, and climate informed decision analysis, are inadequate.” It uses but fails to define a new term “deep uncertainty” to characterise climate change-related proposals and projects.

    Sensitivity analysis is a traditional tool which has been widely used to evaluate uncertain outcomes. One aspect of this is the adoption of a known starting point, commonly, the preferred/recommended option, when presenting a range of studies which examine those parameters which are considered to be uncertain. Statisticians, economists and accountants have their specialised roles to play, long after engineers and quantity surveyors have completed their work.

    The first step, however, is to agree the bounds of the study. A specific and agreed scenario or scientific analysis must be agreed before commencing the CBA. Of course, reviewers will deal with as many unknowns as possible before determining the “base case”, without which the IMPRESSION of uncertainty becomes an APPEARANCE of uncertainty, which to some is a CONFIRMED REALITY of uncertainty, no matter how small the probabilities that may apply to those uncertainties. For example, political and funding decisions may be locked in in advance, as well as portions of the approval process, for example, planning approvals, or technical approval of specialist components of a project, or portions of the environmental framework which may govern final design.

    Eventually, in order to ride a horse, we need to choose a saddle and a bridle – we need to determine where we sit and how we are going to steer the beast.

    The saddle, in this case, is the initial set of assumptions and approvals on which the project will be based. These cannot be arbitrarily altered, but they do leave questions, each with its own uncertainties, about the project or policy.

    Then, the bridle is selected; the agreed means by which changes of direction are determined and managed. In other words, the variables are agreed, and their ranges are identified, if not agreed. Indeed, the tools which will be used to steer future actions will be agreed at this stage as far as is reasonable.

    Then, sensitivity studies will lead to sound quantitative estimates of the variability of outcomes which are in play – cost, financial risk, sovereign risk, regulatory risk, time, environmental, health, etc. Whatever is of interest, the discussion starts from an agreed point, the saddle and follows an agreed methodology.

    I do not understand why there is a need to introduce new concepts such as “deep uncertainty”, which are meaningless until redefined using current English terminology and clearly distinguished from existing risk-related terminology.

    It is probable that the World Bank, Judith Curry and David Roberts have impressed themselves with their own erudition while concurrently leaving the remainder of the world behind… or that they are playing with themselves.

    I am not familiar with Judith Curry’s websites, but a 15-minute scan leads me to suggest that this site is not the place to start for those who are here, ie at BNC.

    If this discussion is to be fruitful and hosted by BNC, then I suggest that the starting point, the saddle, must be agreed in advance. I further suggest that the saddle should be the largest, most recent and most widely circulated review in its field – which is, warts and all, the IPCC’s AR5.

    Oliver K Campbell said in the comments: “Unfortunately a lot of innocent folks may suffer before world leaders recognize the inescapable consequences of karma.”

    There is a world of difference between an impartial, unbiased assessment and an impassioned argument. I consider, based on first reading, that Judith Curry and others are presenting an argument which is clouded by passion. Perhaps we should start with the IPCC material and then setting aside that which is agreed to be clouded by passion and adopt that which is left as the saddle on which we sit. What we cannot do is to permit financiers, economists and those whose primary goals have nothing to do with climate but which assume ongoing operation of the status quo of the world’s precarious and, arguably, deeply flawed financial systems.

    The world’s future climate options should not and will not be determined by financiers, no matter how loudly their money talks.

    To the MODERATOR, I am happy to take part in the suggested discussion, but not without both a saddle and reins.
    BNC MODERATOR
    Thanks for pointing this out. As per BNC Comments Policy, links to CC deniers websites must not be posted and if so, will be deleted.

  27. My thanks to Ted Trainer for doing the hard slog in this report. It is really pointing to the bleeding obvious, at least for those who have some notion of practicality.

    The authors of the EDM document and similar exercises in wishful thinking can’t be included in that cohort.Unfortunately, the renewables enthusiasts,the religiously anti – nuclear movement and the climate change deniers/sceptics/ignorers are in the drivers seat at present and for the foreseeable future.

    The only beneficiary of this madness is the fossil fuel industry.

    This is really a political problem.Given the state of Australian politics now and in the foreseeable future this will not end well.

  28. There is one major problem with Robust Decision Making and the like,no matter how valid they may be for rational and relatively sane people.

    The problem is that the lunatics are running the asylum,therefore any decision made will have a strong probability of being wrong.

  29. Aren’t you guys falling for a salesmen’s trick? You know and they know that wind-and-solar will only ever be installed to 20% or so of consumption, once the gesture has been made. The other 80% will be supplied with – according to the scheme – biogas.

    In the process of installing wind-and-solar-and-biogas, everyone will be told (to our astonishment, of course) that supply is a wee bit tight for biogas, because it turns out that there is just not enough land on the planet to produce it. Don’t worry, our trusted leaders will say, until that extra planet materialises, we will just have to use natural gas during the “transition period”.

    Everyone breathes a sigh of relief. Ethical concerns are satisfied. Green events will continue to get funding from a thriving gas industry. All of us with superannuation policies will get fatter for the same reason. And of course, trusting souls feel completely innocent of failing to act against fossil carbon. After all, we did make a reduction.

  30. Pingback: EROI and the limits of conventional feasibility assessment—Part 3: Intermittency & seasonal variation | Beyond this Brief Anomaly

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