Emissions Policy Renewables

100% renewable electricity for Australia – the cost

Download the printable 33-page PDF (includes two appendices, on scenario assumptions and transmission cost estimates) HERE.

For an Excel workbook that includes all calculations (and can be used for sensitivity analysis), click HERE.

By Peter Lang. Peter is a retired geologist and engineer with 40 years experience on a wide range of energy projects throughout the world, including managing energy R&D and providing policy advice for government and opposition. His experience includes: hydro, geothermal, nuclear, coal, oil, and gas plants and a wide range of energy end use management projects.


Here I review the paper “Simulations of Scenarios with 100% Renewable Electricity in the Australian National Electricity Market” by Elliston et al. (2011a) (henceforth EDM-2011).  That paper does not analyse costs, so I have also made a crude estimate of the cost of the scenario simulated and three variants of it.

For the EDM-2011 baseline simulation, and using costs derived for the Federal Department of Resources, Energy and Tourism (DRET, 2011b), the costs are estimated to be: $568 billion capital cost, $336/MWh cost of electricity and $290/tonne CO2 abatement cost.

That is, the wholesale cost of electricity for the simulated system would be seven times more than now, with an abatement cost that is 13 times the starting price of the Australian carbon tax and 30 times the European carbon price.  (This cost of electricity does not include costs for the existing electricity network).

Although it ignores costings, the EDM-2011 study is a useful contribution.  It demonstrates that, even with highly optimistic assumptions, renewable energy cannot realistically provide 100% ofAustralia’s electricity generation.  Their scenario does not have sufficient capacity to meet peak winter demand, has no capacity reserve and is dependent on a technology – ‘gas turbines running on biofuels’ – that exist only at small scale and at high cost.

Map of Australia's transmission lines. There are no transmissions lines to any of the proposed CSP sites, and the best solar areas are far removed from the existing transmissions infrastructure.Source: Grattan Institute, Figure 10.1 (attributed to DRET (2010), Grattan Institute)


I have reviewed and critiqued the paper “Simulations of Scenarios with 100% Renewable Electricity in the Australian National Electricity Market” by Elliston et al. (2011a) (henceforth EDM-2011).

This paper comments on the key assumptions in the EDM-2011 study.  It then goes beyond that work to estimate the cost for the baseline scenario and three variants of it and compares these four scenarios on the basis of CO2 emissions intensity, capital cost, cost of electricity and CO2 abatement cost.

Comments on the EDM-2011 study

The objective of the desktop study by EDM-2011 was to investigate whether renewable energy generation alone could meet the year 2010 electricity demand of the National Electricity Market (NEM).  Costs were not considered.  The study used computer simulation to match estimated energy generation by various renewable sources to the known hourly average demand in 2010.  This simulation, referred to here as the “baseline simulation” proposed a system comprising:

  • 15.6 GW (nameplate generation capacity) of parabolic trough concentrating solar thermal (CST) plants with 15 hours thermal storage, located at six remote sites far from the major demand centres;
  • 23.2 GW of wind farms at the existingNEMwind farm locations – scaled up in capacity from 1.5 GW existing in 2010;
  • 14.6 GW of roof-top solar photovoltaic (PV) inBrisbane,Sydney,Canberra,MelbourneandAdelaide;
  • 7.1 GW of existing hydro and pumped hydro;
  • 24 GW of gas turbines running on biofuels;
  • A transmission system where “power can flow unconstrained from any generation site to any demand site” – this theoretical construct is termed a “copperplate” transmission system.

The accompanying slide presentation by Elliston et al. (2011b), particularly slides 5 to 12, provides a succinct summary of the objective, scope for their simulation study, the exclusions from the scope, the assumptions and the results.

The results of the baseline simulation show that there are six hours during the year 2010 when demand is not met, with a maximum power supply shortfall of 1.33 GW.  It should be noted that the supply shortfall would be significantly greater with higher time resolutions, e.g. 5 minute data rather than the 1 hour increments used, but this limitation is not addressed by EDM-2011.

The EDM-2011 approach is more realistic than Beyond Zero Emissions (2010)Zero Carbon Australia – Stationary Energy Plan” (critiqued by Nicholson and Lang (2010), Diesendorf (2010), Trainer (2010) and others), especially because EDM-2011’s approach, as they say, “is limited to the electricity sector in a recent year, providing a more straight forward basis for exploring this question of matching variable renewable energy sources to demand.”  As the authors say, “this approach minimises the number of working assumptions”.

Despite the lack of costings, the EDM-2011 study is a useful contribution.  It demonstrates that, even with highly optimistic assumptions, renewable energy cannot realistically provide 100% of our electricity generation.  The baseline simulation does not have sufficient capacity to meet peak winter demand, has no capacity reserve, and is dependent on a technology – gas turbines running on biofuels – that currently exist only at small scale and at high cost.

The study is based on a number of assumptions that I argue are unacceptable:

  1. a system with insufficient capacity to meet the winter peak demand and no capacity reserve margin would violate Australian Energy Regulator (AER) requirements;
  1. the assumed capacity factors for the renewable energy generators are too high to be credible for the average plant life in a 100% renewable energy system;
  1. the assumptions about the way the existing hydro and pumped hydro facilities can be used are not practical;
  1. the assumptions about pumping and generating capacity of the pumped hydro plants are unjustified;
  1. the practicable capacity of gas generators running on biofuels (and the capability of the biofuel system to provide the fuel and store it until needed) has not been demonstrated and critical details are glossed over;
  1. the assumptions about a ‘copper-plate’ transmission system is unrealistic;
  1. the assumptions about reducing winter peak demand is highly optimistic and not borne out by recent experience.

These assumptions, and the cost of the system simulated are discussed in the following sections.

Comments on the technologies and assumptions

Gas turbines running on biofuels

Gas turbines running on biofuels are not a proven, commercially viable electricity generation technology at the scale required (IEA, 2007).

Although some countries, e.g. those quoted by EDM-2011, do have some electricity generated by biomass, there are a wide variety of technologies used, and very little of it is gas turbines running on biofuels.  Much of it is in small plants, such as combined heat and power (CHP) fuelled by wood waste, chicken litter and other waste products.  Most of it is in thermal plants, not gas turbines.  IEA/OECD (2010), Table 3.7 lists four countries with some biogas capacity but this is mostly as reciprocating engine generators on waste dumps, sewage plants and the like.  According to Energy in Australia 2011 (DRET, 2011a),Australia has 231 MW of biogas generating capacity.

The land area that would be required for the required biofuel production would be unacceptable (1.6 million hectares of prime agricultural land in good years (Electropaedia); far more in droughts; this represents 74% of Australia’s irrigated agricultural land and 4% of all arable land (ARNA, 2009)).  The water requirements would also be unacceptable.  As would the truck movements required to collect the biomass.  A large commercial plant would need 100 to 200 truck movements per day and night collecting biomass from an area of 100 km radius (Simms et al., 2009)

The existing biomass electricity generation plants tend to be baseload or intermediate load plants.  Some of the European biogas systems, which use a biomass feed, take around 30 days to make the biogas from the biomass feed.  Such plants cannot be used for just the few days a year in winter when the CST, PV and Wind plants are unable to supply enough power to meet the demand.  The biogas plants listed in IEA (2010) Projected cost of electricity generation, Table 3.7 have assumed capacity factors of 80%, 85% and 90%.  These types of plants are not suited to the peaking plant role envisaged by EDM-2011.

Grattan Institute (2012) gives cost estimates for biofuel electricity generation inAustralia; however, the costs are based on a capacity factor of 70%. The report makes no mention of “gas turbines running on biofuels”.  The technologies mentioned are steam plants and reciprocating engines.  Following are three quotes from the report (Section 8):

For Bioenergy to provide 10% or more of Australia’s electricity needs it will have to use the large amounts of energy embodied within cereal crop residues

Even at 20 to 30 megawatts such plants require large amounts of biomass fuel to realise good capacity factors that are essential to offsetting the high upfront capital costs.

For a 30MW power plant at a 70% capacity factor the land area would be around 240,000 hectares and involve nearly 500 average sized wheat farms.

Note, these plants have to be run with capacity factors of around 70% to be economically viable.  They are certainly not the sort of ‘peaker’ plants envisaged by EDM-2011.

For the gas turbines running on biofuels to work as envisaged by EDM-2011, I envisage biogas would have to be produced throughout the year and stored for use during the few days in winter at the times when the remainder of the renewable energy generators cannot provide sufficient power.  The amount of biogas required per year is estimated to be 290 PJ (equivalent to 116% of natural gas consumed in electricity generation and 37% of total gas consumption in the eastern states in 2009-10).  But most of this is required over just a few short periods in winter.

The cost of electricity from the biogas plants is crudely estimated to be $563/MWh based on the 13% capacity factor assumed in the simulations.  Unlike natural-gas-fired gas turbines, which utilise low capital cost generators with readily available fuel, the biofuel proposal also requires capital intensive biofuel plants, year-round feedstock harvesting, and large-scale biogas storage and distribution infrastructure.

Given that the biogas option is so expensive, a cost estimate below was done for an alternative using natural gas instead of biogas.  All other assumptions are unchanged.

However, even this alternative would be much more expensive than a system that uses gas throughout the year.  In the baseline simulation, most of the gas generation would occur over a few short time spans each year.  That requires either the gas supply lines be sized to deliver the gas volumes needed over the short periods, or the gas must be stored at site for use when needed.  Either option will have a significant impact on the price of the delivered fuel and, therefore, on the cost of electricity.  The baseline simulation has 24 GW of gas generation capacity supplying 28.1 TWh of electricity per year.  However, EDM-2011’s Figure 3 shows that 26 GW is needed to provide a supply with no unserved energy and no unmet hours.  This capacity in the EDM-2011 baseline simulation is about 4 times the capacity of the existingNEMgas generators.

We should expect the generators’ fuel costs would increase by more than a factor of four.  One reason is that there is a small total consumption of gas over the year, but high usage rate for just a few short periods.  The gas supply system would have to provide the infrastructure to deliver the peak capacity demanded, but it would be paid for by a small quantity of gas sold per year.  So the gas price during the winter peak demand would have to be increased significantly.  A second reason the gas price would increase is that there would be a much higher demand for gas in winter at the same time as the gas demand peaks for winter heating.


EDM-2011 assumes the water could be saved through most of the year and used on the few short periods in winter when the renewable energy generators cannot meet the demand.  This is not how our hydro schemes are designed to operate, nor capable of operating.  Here are some reasons why they cannot be operated in this way:

  1. The generators would not be able to generate throughout the year to sell electricity at the time of peak demand.  Therefore, their revenue would be much less over the year.  So they would not be economically viable without a significant increase in the price they could charge for their electricity.
  1. The hydro generation is needed throughout the year to balance the power surges in the system.  That is one of the most valuable functions of the hydro system and it will almost certainly be required to continue to serve that role.
  1. Hydro cannot be stored all year and released in a massive river flush over a few days in winter.  To generate a great deal of energy over just a few days would mean large water releases which would compromise the management of storage and releases for irrigation and can cause flooding and unacceptable erosion to the river banks downstream.
  1. If the management of storage and irrigation releases is compromised the water would be released in winter and not available for irrigation in summer.

Hydro generation is constrained by the average water inflows and the water storage capacity to level out the fluctuation in water inflows over the long term.  Snowy Hydro’s capacity factor is about 14%.  Total generation by hydro in theNEMin 2009-10 was 12,522 GWh, and less in 2008-09 and 2007-08.  This places an upper limit on the amount of hydro generation the simulation should generate.

It should be assumed the hydro generators will operate much as they do now.

Pumped hydro

The simulation assumes there will be no increase in the existing hydro and pumped hydro energy storage (PHES) capacity in the NEM.  The existing pumped hydro plants have a maximum energy storage capacity of 20 GWh (Lang, 2010).  There are also limits on the amount of energy that can be stored per hour and the time of day when pumping can occur.

The EDM-2011 simulation does not appear to limit the amount of energy that can be stored per day by the pumped hydro plants.  I estimate the upper limit on the rate of storing recoverable energy with the pumped hydro plants is (MWh stored per hour):

Tumut 3 394
Wivenhoe 328
KangarooValley& Bendeela 157

Furthermore, there is a minimum duration for which the pumps must be able to operate continuously once started (e.g. 4 hours).  So days when the pumps will not be able to run continuously for the minimum duration will not be able to store energy.

There is also a limitation on the hours of the day when pumping and generating can occur.  They cannot occur at the same time.  Since most of the excess power that would otherwise be spilled occurs during daylight hours when the CST plants are able to generate excess energy, it would seem that, in the simulation, pumping must be reserved for daylight hours when there is excess solar generating capacity.

It is not clear from the EDM-2011 paper how the model handles the distinction between the energy generated by hydro versus pumped-hydro in the two Australian facilities that are both hydro and pumped-hydro (i.e. Tumut 3 and Kangaroo Creek & Bendeela).  EDM-2011’s Figure 2 shows pumped hydro generating at 2.2 GW for 40 hours on 9 and 10 January – a total of 88 GWh.  This is not possible.  There is only 20 GWh of storage and the pumps can store energy at about 4.5 GWh per day.  The existing system would need to pump for about 7 hours with all pumps operating to be able to generate for 5 hours at 0.9 GW.  So, the maximum daily generation, on consecutive days, would be about 4.5 GWh (excluding draw down from storage).

It would seem, with EDM-2011’s assumption of pumped-hydro being dispatched first, the 20 GWh of available storage would not be recharged each day since only about 4.5 GWh could be recharged each day.  In the simulation, pumped hydro contributes little during the critical winter days shown in Slide 12 (Elliston et al, 2011b) and generates nothing on some days, e.g. July 1, 2, 5 and 6.

Only Wivenhoe is a ‘pure’ pumped hydro facility.  The other two facilities are mostly hydro, with a small pumped hydro capacity.  Therefore, it is more realistic for the EDM-2011 simulation to assume the hydro capacity is 6.6 GW and the pumped hydro can generate about 4.5 GWh per day at up to 0.9 GW on consecutive days (more for a short time if drawing down from 20 GWh of stored energy).

Concentrating Solar Thermal (Parabolic Trough)

EDM-2011 assumes a 60% capacity factor for CST. The details underpinning this are sparse, thus a number of questions arise.  Is the assumed capacity factor a realistic average for the life of the plant?  What is the basis for the assumed capacity factor for CST?  Does it take into account:

  1. The system performance and reliability that is likely to be achieved over the full book life of the facilities?
  1. Spilled energy?
  1. Scheduled and unscheduled outages?
  1. Outages in the long transmission lines (which are mostly in remote areas far from the major service centres, so repairs will take longer than for the existing system)?  Inevitably, these transmission lines will have lower reliability than theNEMaverage.  Therefore, the capacity factor of the wind and CST plants would be reduced because of transmission line outages.


What would be the average capacity factor for a fleet of 14.6 GW of roof-top, fixed plate PV over a 30 year life?

  • How much would have to be spilled because the distribution system cannot handle the peak power output and power surges?
  • How much would the assumed 16% capacity factor be reduced over the 30 year assumed life of each installation as a result of, for example:
  • Performance deterioration of the solar panels
  • Performance deterioration due to collecting dirt and lack of cleaning
  • Some PV installations stop working or are disconnected, for whatever reason, and are never fixed or reconnected
  • Buildings are sold, new owners are not interested in maintaining the system; some don’t keep it connected
  • Buildings are knocked down and rebuilt without reinstalling the original PV system (the cost analysis assumes an average 30 year life for the original installations).

Is 14.6 GW of roof top solar PV realistic?  That would be the equivalent of 1 kW for every man woman and child, or average of over 2 kW per dwelling.  The PV is assumed to be on residential dwellings many of which could be on apartment blocks with limited roof space.  Many of the houses may have tree shading and many will not have sufficient north facing roof space for a 2 kW system.

While the inclusion of 14.6 GW of rooftop solar may be theoretically possible, theNEMcould not accommodate such a concentrated non-dispatchable and variable energy supply without large-scale distributed storage and advanced ‘smart-grid’ management.  All of which is expensive, but no attempt has been made to cost this


The assumed capacity factor of 30% for wind seems too high for a 100% renewable system.  Although this is a valid figure for individual wind farms, much of the wind energy from a large-scale network of farms would have to be spilled.  So the system wide average capacity factor for wind would be less than 30% in an all renewable energy system comprising primarily solar and wind generation.


The EDM-2011 simulation assumes a ‘copper-plate’ transmission and distribution system (“power can flow unconstrained from any generation site to any demand site”).  To achieve this assumption would require extensive additions to the existing transmission and distribution systems.  The additions would need to have the capacity to carry the full peak power output from each generator plant.

The distribution systems would have to be upgraded to carry the peak power output of the PV systems in each area, or have smart grids to curtail the power output of the PV systems when they exceed the capacity of the distribution and transmission systems.

The additions to the transmission system would incur additional energy losses.  Therefore, the 204.4 TWh of electricity generated in 2010 must be increased to account for the extra transmission and distribution losses.  Appendix 2 contains more about the ‘copperplate’ transmission system assumptions, options and the basis for the cost estimates.

Winter peak demand reductions

EDM-2011 suggest methods to reduce the peak demand in winter so the renewable energy system can meet the demand.  However, this approach is inconsistent with the stated objective which is to find a 100% renewable energy solution that can meet the 2010NEMdemand.

The relationship between energy efficiency and peak load is complex. As such, caution needs to be exercised in assuming that energy efficiency measures will invariably lead to commensurate reductions in peak demand.  Indeed, electric vehicles and other unforeseeable new sources of demand may increase the peak.

Scenarios costed and compared

I have made a crude estimate of the capital cost, the Levelised Cost of Electricity (LCOE) and the CO2 Abatement Cost for the EDM-2011 baseline simulation.  I have included an estimated cost for needed additions to the transmission and distribution systems to allow them to approach the ‘copper-plate’ assumption.

I have also analysed three additional scenarios with changes to some of the baseline assumptions. The changed assumptions include: sufficient generating capacity to meet all demand and maintain about 20% capacity reserve (which is less than a typical level for modern electricity networks, and much less than in theNEM); natural gas instead of biogas; reduced system-wide capacity factors for CST, PV and Wind, and less capacity for additions to the transmission system. The reduced capacity factors of CST, PV and Wind are compensated for by increasing the amount of generation by natural gas.  Also included is additional generation to compensate for the increased energy loss in the additions to the transmission system.

The scenarios (detailed in Appendix 1) compared are:

  1. Baseline EDM-2011 simulation (i.e. gas turbines running on biofuels)
  1. Baseline with gas turbines running on natural gas
  1. Less renewable energy + more gas to improve reliability – Scenario 2 with most pumped hydro capacity reassigned to hydro, reduced pumped hydro capacity factor, reduced capacity factor of CST, Wind and PV, increased natural gas capacity and capacity factor.
  1. Reduced transmission capacity + more gas – Scenario 3 with half transmission capacity from wind farms, half transmission capacity of interstate interconnectors and reduced capacity factor of CST, PV, Wind and pumped hydro generation because of transmission constraints.

Capacity, capacity factor and generation assumptions

This section summarises the capacity, capacity factor, amount of generation contributed by each technology and each technology’s share of the total generation.  These data are presented for the baseline (Scenario 1) and the three varied scenarios identified above as Scenarios 2, 3 and 4.

1. Baseline (i.e. gas turbines running on biofuels)

Table 1 lists the capacity, capacity factor, annual generation and share of total generation for each technology in the baseline scenario.

The capacity factors for hydro and pumped hydro energy storage (PHES) are not explicitly stated in the EDM-2011 paper.  I have estimated the capacity factors for the baseline case by subtracting the energy generated by the other technologies from the total 2010NEMdemand (stated by EDM-2011 to be 204.4 TWh).

2. Baseline with gas turbines running on natural gas

Scenario 2 is the same as Scenario 1 but with the gas turbines running on natural gas instead of on biofuels.  Table 2 would be the same as Table 1 except the ‘biogas’ column would be renamed ‘natural gas’.

3. Less renewable energy + more gas to improve reliability

The capacity, capacity factor, annual generation, and share for Scenario 3 are:

The total capacity is not the sum of the individual capacities because all but 0.5 GW of the PHES capacity is included in ‘Hydro’. The total generation is increased from 204.400 GWh to 214,600 GWh for an assumed 5% energy losses in the additions to the transmission system.  The capacity of OCGT is increased from 24 to 33 GW to ensure 20% capacity reserve above peak winter demand.  From Slide 12 (Elliston et al, 2011b), on July 1 peak demand is about 32.5 GW. At the time of peak demand there is little wind, no solar and no pumped hydro generation (because the pumped hydro was not recharged during the day).  So, all the generation must be provided by hydro and gas.  To maintain 20% reserve capacity (in case of unavailable generators) we need about 39.6 GW of gas and hydro capacity.  We have 6.6 GW of hydro capacity, (excluding the 0.5 GW of ‘pure’ pumped hydro capacity because it may not have been recharged as was the case on July 1, 2, 5 and 6).  So we need about 33 GW of gas capacity to give a 20% capacity reserve on1 July 2010.

4. Reduced transmission capacity + more gas

The capacity, capacity factor, generation and share for Option 4 are:

In this option the capacity of the transmission line from the wind farms is arbitrarily halved. The capacity factor and generation for wind is reduced because the transmissions line capacity is reduced.  The capacity factor and generation for CST is reduced because the capacity of the intestate interconnector lines is halved, so less power can be transmitted from the solar plants, at times.  The capacity factor and generation of PHES is reduced because the reduced capacity of the interstate interconnectors will reduce the amount of excess power that can be transmitted to and stored in the PHES facilities.  The capacity factor and generation of OCGT is increased to compensate for the reduction in contribution from Wind and CST.

To clarify the differences between these assumptions for the four scenarios, the capacity of the technologies is compared in Figure 1, the capacity factor in Figure 2 and the annual generation in Figure 3.



Transmission and Distribution assumptions

For estimating the cost of the transmission system additions needed to achieve the ‘copper-plate’ assumption (Scenarios 1, 2 and 3), I assumed the transmission lines from each CST plant and wind farm will be sized to carry the rated power output of each facility.  The transmission lines are assumed to run from the plant to the closest capital city or to the nearest entry point to the interstate interconnector lines.

The capital cities would have to be linked with interconnector transmission lines. For this crude cost estimating exercise I assumed their capacity must be sufficient to transmit the lesser of the peak demand at the receiver end or generation capacity minus demand at the sender end.

Figure 4 provides a graphic summary of the estimated capacities for the interstate transmission lines, as well as the renewable energy generating capacity (excluding biofuelled gas turbines) and the winter peak demand for each state.

For Scenario 4, the capacity of the transmission lines from the wind farms is half the rated capacity of the wind farms.  The capacity of the interstate interconnectors is half the capacity assumed for the ‘Copper-plate’ scenario (shown in Figure 4).  The capacity factor of the PV, CST and wind farms is reduced because of the transmission capacity constraint.  Increased generation from gas compensates for the reduced generation from the CST and Wind generators.

The distribution system must allow the 14.6 GW of roof top solar PV, which is located in the residential areas, to supply their peak output without curtailment.  It is assumed the transmission network would need to be ungraded to achieve this.

CO2 emissions intensity

Figure 5 compares the CO2 emissions intensity of the four scenarios with the 2010 NEMemissions intensity (DCCEE, 2010).  The emissions intensities for the scenarios are for fossil fuel combustion only.  Importantly, they are for gas turbines running on natural gas and operating at optimum efficiency.  They do not take into account the higher emissions produced when the gas turbines are operating at less than optimum efficiency, for example during start up, shut down, spinning reserve, part load and when their power is cycling up and down to respond to changes in demand and changes in the output of the PV panels and wind farms.  If these were included the emissions intensity for the three scenarios that use natural gas would be higher. They would also be higher if fugitive emissions were included.  The emissions intensity figure for the NEMincludes fugitive emissions.  None of the emissions intensities are life-cycle emissions so they do not include the emissions embodied in the plants.  The emissions intensity used for the calculations is 0.622 t CO2/MWh ‘sent out’ (EPRI, 2010).  See Appendix 1 for basis of estimates of CO2 emissions intensity.

Cost estimating methodology and assumptions

This section explains how the capital cost, Levelised Cost of Electricity (LCOE) and CO2 abatement cost for each scenario was estimated.

Except where otherwise stated, unit costs are derived from the Department of Resources Energy and Tourism (DRET, 2011b).

All costs are in 2009-10 Australian dollars.

Capital costs are ‘Total Plant Cost’ and do not include ‘Owner’s Costs’ and ‘Interest During Construction’ (IDC).

The inputs and intermediate calculation steps for each scenario are presented in Appendix 1.

Capital cost


The capital cost for each generator technology is the capacity times the unit cost ($/kW) for that technology.  The capacity of each generator technology for each scenario is in Tables 1, 3 and 4.  The unit cost for each technology, except gas turbines running on biofuels, CST and hydro, is the average of the high and low ‘Total Plant Cost’ in the DRET (2011c, 2011d) spreadsheets, converted to “sent out”. The central estimates are also presented in ACIL-Tasman (2010).  The costs in the DRET spreadsheet are ‘$/kW installed’, so they must be converted to ‘$/kW sent out’:

$/kW ‘sent out’ = $/kW ‘gross’ / (100% – ‘Auxiliary Load %’)

DRET unit costs for CST are for 6 hours thermal storage.  The EDM-2011 simulations assume 15 hours storage.  The capital cost for CST is factored up by 1.53 to account for the increase of solar field and thermal storage size to increase energy storage from 6 hours to 15 hours.  The factor of 1.53 was derived from the DRET (2011c) costs for CST without storage and CST with 6 hours storage, assuming a linear upscaling.

The DRET costs for PV are for 5 MW commercial installations.  However, the simulations assume residential, roof-top, solar PV panels.  These would normally be around 1 to 6 kW (say average 2 kW), not the 5 MW to which the DRET cost figures apply.  The capital cost for PV should possibly be factored up by about 1.5 or 2.  I have not done this in these analyses.

The DRET spreadsheets do not include ‘gas turbines running on biofuels’.  There is very little commercial experience or cost information available for this technology.  The capital cost and LCOE for gas turbines running on biofuels are based on $5,051/kW.  This was derived from (IEA, 2007), IEA (2010), Grattan Institute (2012) and considerations of what would be needed to provide a secure supply of biofuels inAustralia.   The cost estimate for gas generators running on biofuels has high uncertainty.

There is no capital cost for the hydro and pumped hydro plants because they already exist and there are no plans in the EDM-2011 baseline or the additional scenarios to build additional hydro plants.

Transmission additions and distribution enhancements

The capital cost estimate for the transmission system additions is the product of the transmission line length, the transmission line capacity and the unit cost ($/  The unit cost for additional transmission lines is estimated at $1,500/  This is derived from the AEMO (2011) cost estimates for the South Australian Interconnector feasibility study assuming a mix of AC andHVDC transmissions lines.  The cost estimate assumptions and intermediate computation results are presented in Appendix 2.  The largest uncertainty is in the transmission line capacity for the interstate connectors.

The capital cost for the distribution system enhancements to carry the PV generation is estimated at 20% of the asset value of theNEMdistribution system.

Cost of electricity

The Levelised Cost of Electricity (LCOE) for the generator technologies was calculated using the NREL LCOE calculator.  The capital cost and capacity factor for each technology and each scenario are in Tables 1, 3 and 4.  The other input values are as per DRET (2011c, 2011d) spreadsheets for all except the gas turbines running on biofuels, hydro and pumped hydro.  Table 5 lists the other inputs.

The estimates of LCOE for generation using gas turbines running on biofuel assumes capital costs of $5051/kW (‘sent out’) and fuel price of $10/GJ to account for the costs involved with production, storage and transport.  All other inputs for calculating LCOE are the same as for natural gas fuelled OCGT.

The assumed LCOE for hydro is $50/MWh and for PHES is $300/MWh[1].

The LCOE for the additions to the transmission network were calculated using the NREL calculator.  The inputs are the capital cost (estimated as described above and shown in Figure 7) and the O&M costs.  The O&M costs were estimated from the 2010 NEMO&M cost for transmission factored in proportion of the line length of the new additions compared with the total length of existing NEMtransmission lines (AER, 2011). Book life was assumed to be 40 years and discount rate as per Table 5.

The LCOE for the enhancements to the distribution system assumed the capital cost to be the equivalent to 20% of the 2010 value of the NEM’s distribution system assets.   The O&M costs are assumed to be 20% of the NEM’s 2010 O&M costs (AER, 2011).

Costs not included in the cost estimates are:owner’s costs and interest during construction

  1. biofuel generating costs may be understated
  1. higher costs for natural gas to include the cost of building larger capacity gas pipes to supply 24 to 33 GW of peak gas generation (depending on the scenario), but with only 13% capacity factor to pay for the pipes (this means higher gas prices would have to be charged to pay for the high volume gas pipe system but with gas sales much less than the pipes could deliver).
  1. Increased O&M costs for CST with 15 h storage instead of the 6 h for which the DRET O&M costs apply.
  1. Costs for solar PV are probably too low (for kW sized, roof top, solar PV).
  1. Cost of electricity for the existing NEM transmission and distribution network.  (Only the cost of the transmission additions and distribution enhancements are included.  If the LCOE for the existingNEM network was included it would increase the cost of electricity for all options and make no change to the capital cost or CO2 abatement cost.)

CO2 abatement cost

The CO2 abatement cost is the cost to reduce emissions intensity from the CO2 emissions intensity in theNEMin 2010 to the emissions intensity that would exist with the new scenario implemented; it is expressed as ‘cost per tonne CO2 abated’ ($/t CO2).

CO2 abatement cost = (LCOE2 – LCOE1) / (EI1 – EI2)


LCOE1 = LCOE for theNEM in 2010

LCOE2 = LCOE for the scenario

EI1 = Emissions intensity for theNEM in 2010

EI2 = Emissions intensity for the scenario

The LCOE and CO2 emissions intensity for theNEMin 2010 are taken as:

LCOE1 = $45.40/MWh (AER, 2011; Chapter 1, Table 1.4)

EI1 = 1.0 tonne/MWh (DCCEE, 2010, Table 5, weighted average forNEM)

The LCOE and CO2 emissions intensity for each scenario are in Appendix 1 (and charted in Figure 5 and Figure 6).

The inputs and intermediate calculation results for the CO2 abatement cost estimates are in Appendix 1.

Uncertainties in cost estimates

The greatest uncertainties in the cost estimates are in:

  1. the fuel costs, capital costs and O&M costs for the gas turbines running on biofuels,
  1. the cost of the solar thermal plants with 15 hours of thermal storage and their lifetime average capacity factor, and
  1. the amount of additional transmission and distribution capacity needed.


Capital cost, LCOE and CO2 abatement cost of the scenarios

Figure 6 compares the four scenarios on the basis of capital cost, cost of electricity and CO2 abatement cost.

Figure 7 compares the capital cost and cost of electricity for the ‘copper-plate’ additions to the transmission system (Scenarios 1, 2 and 3) and the scenario with reduced additions to the transmission system (Scenario 4).



The EDM-2011 study reveals a great deal about the difficulty and cost of a largely renewable energy electricity system forAustralia’sNEM.

The study is more realistic than Beyond Zero Emissions’ “Zero Carbon Australia – Stationary Energy Plan” (critiqued by Nicholson and Lang, 2010; Diesendorf, 2010; Trainer, 2010; and others), especially because their approach, as they say, “is limited to the electricity sector in a recent year, providing a more straight forward basis for exploring this question of matching variable renewable energy sources to demand.”  As the authors say, “this approach minimises the number of working assumptions”.

Despite the lack of cost estimates – a deficiency rectified in this paper – the EDM-2011 study is a useful contribution.  It demonstrates clearly that, even with highly optimistic assumptions, renewable energy cannot realistically provide 100% of our electricity generation with currently available technology.  The baseline scenario does not have sufficient capacity to meet peak winter demand, has no capacity reserve and is dependent on a technology – gas turbines running on biofuels – that exist only at small scale and at high cost. Furthermore,Australia’s hydro and pumped hydro facilities cannot be used in the way assumed in the simulations.

Reliability of supply

The system simulated by EDM-2011 would not provide a reliable electricity supply.  The gas turbines running on biofuels and hydro-electricity provide nearly all the power, outside sun hours, on some winter days, e.g. July 1 to 6 for 2010 (Elliston et al., 2011b, Slide 12). However, the gas turbines running on biofuels system does not currently exist at commercial scale. Furthermore,Australia’s total hydro capacity cannot be run at full power for days and weeks at a time as is assumed in the simulation.  As such, without the assumed generation from these two technologies, the system simulated has near zero generating capacity for many hours in winter.  This would mean load shedding or rolling blackouts across theNEM, with no electricity for most consumers during those times.

If we substitute natural gas for biofuel for the gas turbines, we’d need capacity about equal to the winter peak demand (33 GW) to provide a reliable electricity supply with about 20% capacity reserve.  That means, nearly all the generation would be by natural gas on some days in winter.  The plants would be ‘peaker’ plants, not ‘baseload’, so they would be open cycle gas turbines (OCGT), which are the inefficient, high cost of electricity, high CO2 emissions type of gas technology.


For the baseline scenario (Scenario 1) the electricity supply would be unreliable and the costs for a system built in the current decade are estimated to be around $568 billion capital cost, $336/MWh cost of electricity and $290/tonne CO2 abatement cost (Figure 6).

That is, the wholesale cost of electricity for the simulated system would be seven times more than with the existing system, with an abatement cost that is 13 times the starting price of the Australian carbon tax (Energetix. 2011) and 30 times the European carbon price (European Energy Exchange, 2012).  (The cost of electricity does not include the costs for the existing electricity grid).

For Scenario 2 (natural gas substituted for biofuel in the baseline scenario) the cost of electricity is estimated at $280/MWh (Figure 6), which is about six times the 2009-10 average cost of electricity generation in theNEM.  The power supply would still be unreliable, but less so than with gas turbines running on biofuels.

For Scenario 3, where the assumptions are changed to provide a more reliable, mostly renewable electricity supply (although still not as reliable as we have now), more gas would be used and the cost of electricity is estimated at $286/MWh.  CO2 abatement cost is estimated at $306/MWh (Figure 6).

Scenario 4 – If the transmission capacity is reduced the capital cost and cost of electricity are further reduced (Figure 6) but more gas is used and more CO2 emitted (Figure 5).  This scenario has the lowest capital cost and lowest cost of electricity.

The assumed ‘copper-plate’ transmission system (Scenarios 1 to 3) adds $107 billion to the capital cost and $58/MWh to the LCOE (Figure 7).  The reduced additions to the transmission system (Scenario 4) adds $67 billion to the capital cost and $37/MWh to the cost of electricity (see Figure 7).  These costs are included in the capital costs, cost of electricity and CO2 abatements costs.

The transmission system additions are a high cost, especially when we consider there is no increase in demand driving these extra costs.  These costly transmission upgrades are only required if the policy objective is to implement renewable energy, rather than to provide low emissions electricity at least cost..


EDM-2011 conclude “Achieving 100% renewable electricity also entails a radical 21st century re-conception of an electricity supply-demand system.”  They make their point succinctly in the last slide in their slide presentation where they state “Baseload plant is an outmoded concept” (Elliston et al. (2011b).

However, since the cost of electricity from the renewable energy option is some seven times the current cost of electricity, their study does not refute the fact that the “baseload plant” is still by far the least cost way to supply most of our electricity needs, and is far from being an “outmoded concept”.

The least cost way to meet the demand and reliability requirements is with a mix of generators that are located close to the demand centres, connected by relatively short transmission lines to the main demand centres and capable of supplying the power to meet baseload at all times, intermediate load during day time on week days and peak demand whenever it occurs.

The least cost option to match generation to the demand profile in most countries where large hydro capacity is not available such as inAustralia, is usually with coal, gas or nuclear for baseload, gas and hydro for intermediate load, and gas and hydro for peak load.

Bayless (2010) in “The case for baseloadprovides “an engineer’s perspective on why not just any generation source will do when it comes to the system’s capacity, stability and control”.   He says:

The electric system is more than just the delivery of energy—it is the provision of reliability. First, the system must have capacity, that is, the capability to furnish energy instantaneously when needed. The system also must have frequency control, retain stability, remain running under varied conditions, and have access to voltage control. Each of those essential services for reliability must come from a component on the system. Those components are not free, and they don’t just happen. They are the result of careful planning, engineering, good operating procedures, and infrastructure investment specifically targeting these items.

The simple cost analysis presented here demonstrates that the renewable electricity system simulated by EDM-2011 cannot meet these requirements at anywhere near the cost of a conventional system.


I have reviewed and critiqued “Simulations of Scenarios with 100% Renewable Electricity in the Australian National Electricity Market” by Elliston et al. (2011a).  That paper does not analyse costs, so I have also made a crude estimate of the cost of the scenario simulated and three variants of it.  I conclude:

The costs for the simulated 100% renewable electricity system are estimated to be $568 billion capital cost, $336/MWh cost of electricity and $290/tonne CO2 abatement cost.  That is, electricity would cost seven times more than now, and CO2 abatement cost would exceed current carbon prices by 13 times the starting price for the Australian carbon tax and 30 times the European carbon price (at time of writing).

The electricity supply would be unreliable.

Any largely renewable electricity system for theNEMwould be high cost, as demonstrated here.  The changes made to the assumptions make little difference to the estimated capital cost, cost of electricity and CO2 abatement cost.


I recommended the simulation be rerun with the following changes:

  1. Use natural gas instead of biofuel
  1. Increase the gas generation capacity so there is sufficient capacity in the system to meet all peak demand and ensure 20% capacity reserve.
  1. Check that the system can meet demand at the 5 minute time scale, not just the average demand over 1 hour.
  1. Introduce constraints on hydro generation, pumped hydro energy storage rate, times of day for pumping and for generating and minimum number of continuous hours of pumping that match the actual constraints on the actual plants in theNEM.
  1. Reduce the capacity of transmission lines from the wind farms to a percentage of their rated power output and reduce the maximum output of the wind farms accordingly; optimise (roughly) the transmission line capacity and generating capacity to achieve the least overall cost of electricity from the system.
  1. Limit the peak output of the PV generators at a percentage of their peak power output to fit within the constraints of the distribution system; optimise (roughly) to achieve the least overall cost of electricity from the system.
  1. Limit the capacity of the interstate transmission interconnectors (this would reduce the output of the renewable energy generators at some times and reduce the pumped hydro storage rate).
  1. Do a loss of load probability (LOLP) analysis to check that the system being simulated meets the Australian Energy Regulator’s reliability requirements.
  1. Do a simulation with a nuclear power scenario to provide an objective comparison of the cost for an alternative way to provide a low-emission electricity supply.

Estimate the costs of all scenarios and compare them on the basis of:

  1. CO2 emissions intensity
  1. capital cost
  1. cost of electricity
  1. CO2 abatement cost


I would like to thank Professor Barry Brook, Dr. Jani-Petri Martikainen DrJohn Morgan, DrIan Nalder, Martin Nicholson, Graham Palmer, Dr. Gene Preston, Dr. Ted Trainer and two others in the electricity industry whom I cannot name, for their input and assistance with this analysis and reviewing this document.


ACIL-Tasman (2010), Preparation of energy market modelling data for the Energy White Paper

AEMO (2011), South Australian Interconnector Feasibility Study

AER(2011), State of the Energy Market 2011

Australian Natural Resources Atlas, Land Use – Australia

Bayless, B. (2010) The case for baseload

Beyond Zero Emissions (2010), Zero Carbon Australia – Stationary Energy Plan

DCCEE (2010), National greenhouse accounts (NGA) factors, Table 5

Diesendorf, M. (2010), Ambitious target does not measure up.

DRET (2011a), Energy in Australia – 2011

DRET (2011b), Fact Sheet – Australian Electricity Generation Technology Costs – Reference Case

DRET (2011c), Data – Renewable Performance and Cost Summary 2011

DRET (2011d), Data – Fossil Fuel Plant Performance and Cost Summary 2011 

Electropaedia, Electricity Generation with Biofuels

Elliston, B., Diesendorf, M. and MacGill, I.(2011a), Simulations of Scenarios with 100% Renewable Electricity in the Australian National Electricity Market

Elliston, B., Diesendorf, M. and MacGill, I.(2011b), Simulations of Scenarios with 100% Renewable Electricity in the Australian National Electricity Market. (Slide presentation)

Energetics (2011), Carbon price impact on energy prices

EPRI (2010), Australian electricity generation technology costs – Reference case 2010

European Energy Exchange (EEX) (2012), European Emission Allowances

Grattan Institute (2012), No easy choices: which way to Australia’s energy future? Technology Analysis

IEA (2007), IEA Energy Technology Essentials – Biomass for Power Generation and CHP

IEA/OECD (2010), Projected costs of generating electricity

Lang, P. (2010), Australia‘s pumped hydro energy storage capacity, Oz Energy Analysis

Nicholson, M. and Lang, P. (2010), Zero Carbon Emissions – Stationary Energy Plan – Critique

NREL (2011), Levelised Cost of Energy Calculator

Simms, R. et al (2009) “IEA’s report on 1st to 2nd Generation Biofuel Technologies

Trainer, F. (2010) Another ZCA 2020 Critique

[1] Crude estimate of LCOE: PHES plant would buy renewable energy when it would otherwise be spilled and would have to sell at about 4 times the buy price for PHES to be economically viable.  If we assume electricity is bought at average $75/MWh, then LCOE for generation from PHES would be 4 x $75/MWh = $300/MWh.


By Barry Brook

Barry Brook is an ARC Laureate Fellow and Chair of Environmental Sustainability at the University of Tasmania. He researches global change, ecology and energy.

155 replies on “100% renewable electricity for Australia – the cost”

Peter Lang wrote:

Furthermore, the costs for wind have been rising sharply in Australia over the past few years. ABARES reports, every 6 months, the average cost of electricity generation plants under construction. In April 2009, i.e. one year earlier than the $2,896/kW figure, the cost of wind farms under construction was $2,317/kW and in October 2009 it was $2,591. So the cost had increased by $565/kW (i.e. 24%) in one year.

Elsewhere you write about the importance of using the DRET – EPRI projections for technology capital and energy costs in Australia (and other numbers having “much less credibility”). This is a pretty terrific and well reasoned study. For future wind costs, they look at anticipated improvements by 2030 (operation and efficiency, larger turbines, higher hub heights, improvement in power electronics and drive systems, wind sensing equipment, etc.). They write: “The cumulative impact of these anticipated improvements is estimated to decrease the capital cost of wind turbine installations by 35% in 2030 relative to 2015 technology” (6-64).

You have not indicated a time frame for this model build-out in your cost projections, will you be using such cost reductions for learning curves, technology development, and roll-out in your estimates? Given the high amount of wind energy projected in the EDM-2011 model, a 35% reduction (even a portion thereof) would be significant reduction in future energy costs.


Michael Goggin,

Moreover, grid enhancements provide a number of widely shared economic and reliability benefits for power consumers, which is why in most of the U.S. the costs of transmission upgrades are allocated to consumers and not to generators.

Is not the sole consumer benefit of the grid the provision of electricity? The grid is a necessary evil, not a boon. We would do without it if we could, and would avoid expanding what we must already live with if we can.

If we must make a choice between say nuclear, for which the existing grid is approximately adequate, and wind or solar which require substantial grid development, why we would not directly allocate those very large transmission costs and other depredations to the wind or solar scenario?


Michael Goggin.

1. Just to be clear, the $1000/kW is a rough rule of thumb used in the early planning stage in the USA (I understand) and here. It covers all the costs of enhancements to the grid needed to allow the grid to handle the unreliable electricity supply from intermittent renewable energy sources. I did not use this figure in my estimates, as you will see in Appendix 2 in the attached PDF document. The $300/kW was a figure NREL came up with in a study a couple of years ago, but my understanding is it is considered in the industry to be unrealistic, and influenced by renewable energy advocacy, as is much of the work produced by the NREL. (There have also been some posts on BNC this very subject by US specialists in network planning). So I would not place much credence in the $300/kW figure. As I said, I did not use the $1 000/kW figure. The figure I used is based on studies contracted by AEMO to estimate the cost of interconnectors from Adelaide to Melbourne and Sydney. My figure assumes a mix of HVDC and AC.


On wind capital costs, it would seem curious that while wind turbine costs are plummeting around the globe, they are increasing in Australia.

And therein lays the misleading statement. A wind power station is not just the cost of the turbines. It comprises much more than just the turbines. The total cost of wind farms has been going up, as the authoritative costs I provided for the actual wind farms under construction in each 6 month period show.


3. Linearly scaling up wind output to model future installed wind capacity is not an acceptable shortcut.

No (i.e. I agree), not if you are at a more advanced stage of estimating. But at this stage, and to provide an estimate of the cost of electricity from a renewable energy system to power Australia, it is an excellent first step. Refinements in the estimate may raise or lower the costs, but certainly will not lower it by the amount required to make renewable energy anywhere near a viable option. Being able to understand scale is an important competency. You may also want to look at the EPRI (2010) report referenced above to see the costs EPRI estimated for wind farms of different sizes, and different average wind speeds.

If wind is being built in new regions that have been opened up by transmission expansion, you are also likely to see capacity factors and capacity value increase as diverse, high quality wind resources are opened up.

That is an unquantified, unsubstantiated statement. . I want to know what is the total cost? What is the total system cost? Without such quantification, this is just more of what David Mackay calls “emissions of twaddle”.

Furthermore, I doubt your statement is true for extension of wind farms to more inland parts of Australia. See the Gattan Institute report for a good summary of this:


4. Renewable output was actually quite high in much of Europe during the recent cold spell.

We are in Australia. The best sites for wind farms have already been developed. The 1,200 km by 800 km area in which the wind farms are located is the best resource. Any more wind farms in that area will suffer from the same wind speed correlation that the existing wind farms suffer – e.g. up to a week of near zero output at times. Outside this area, the wind resource is not as good – unless you are going to build a transmission interconnector to Western Australia. That would be prohibitively expensive.

Michael Goggin, can I urge you to read the Elliston et al. paper or the slide presentation (this provides a succinct summary), then read the PDF version of my paper (linked above). Until you have done that I think you may not be understanding the scope, wind’s role in it, and the relatively low sensitivity of the total system cost to the costs contributed by the wind component. There is little point arguing about fine details of the wind component when the largest uncertainties by far are in biofuels, CST and transmission costs.

And, please, can we focus on the costs if we are going top make suggestions about how to improve this analysis. I’ve provided an Excel spreadsheet you can down load and change inputs to see the sensitivity of your suggestion before point them. Can I urge you to try that so you can quantify the impact of your proposals on the capital cost, cost of electricity and CO2 abatement cost of the system.

Unless your suggestions will significantly change the conclusions, they are really not worth a lot of effort. The main conclusion to take fro this paper is:

For the EDM-2011 baseline simulation, and using costs derived for the Federal Department of Resources, Energy and Tourism (DRET, 2011b), the costs are estimated to be: $568 billion capital cost, $336/MWh cost of electricity and $290/tonne CO2 abatement cost.

That is, the wholesale cost of electricity for the simulated system would be seven times more than now, with an abatement cost that is 13 times the starting price of the Australian carbon tax and 30 times the European carbon price. (This cost of electricity does not include costs for the existing electricity network).


Mark Duffett, @14 February 2012 at 10:52 PM

Yes. I agree. Michael Goggin, plese see Mark Duffett’s comment. I suggest the effect he has aluded to offestes the effects your are suggesting. It is intersting to note that EAMO has recently significantly reduced the expected capacity factor for future wind farms. I seem to recall (may have this wrong) Gattan Institute report says something about that.



Elsewhere you write about the importance of using the DRET – EPRI projections for technology capital and energy costs in Australia

I get the impression you just want to argue for the sake of arguing. You still haven’t provided any numbers to back up your earlier statements.

What is the point you are trying to make in the quoted bit. Yes, I used the EPRI/ACIL-Tasman/DRET figures for the estimates. They are a set of figurs that have been produced on a set of consistent inputs across the technologies, they are applicable for Australia, recent, constant 2009-10 Australian dollars. And they are the costs used in the Governmen’ts recently realeased Energy White Paper and used in the government’s modelling. What more could you ask for?

Then Michael Goggin said he felt they were to high and quoted a recent US figure of $2,000/W. I said, if anything, I felt the DRET figures were more likely to be an underestiate rather than an over estimate and provided the basis for that opinion – ie the actual costs of wind farms under construction at the time the DRET figures were applicable (ie in a consistent basis). I also showed hoe that actual cost of wind farms under construction had increased 24% in the year to that date.

EL, I find you comments to be simply argument for the sake of argument. No serious attempt to provide credible costs on a basis that is properly comparable, an not real attempt attempt to relate to what is important.

I hope you will understand if I sometimes don’t respond to your comments.


I wish to clarify a comment by Michael Goggin to the effect that increasing the number of wind farms improves capacity factors. Obviously the capacity facotr of any given wind farm remains what it is. [Around here several years of data show an averagve of just under 26% despite the standard claim that the Columbia Basin area has a calcfulated capacity factor of 30%.]

Wht does happen with new wind farms further downwind is that the aggrigate energy from all the wind farms shows a smoother profile. This means the same balancing agent (hydro around here)can accomodate slightly more wind energy before the CCGTs have to kick in. I will point out that, as the legacy hydro cfannot be enhanced further, as more wind farms come in so do more CCGTs to act as balancing agents. Thus, like elsewhere, more wind promotes more natgas; or rather that is who I see the matter.


DBB your model seems to assume growing demand that has to be met by the wind-gas combination from a low wind starting point. Assume that peak demand is fixed and wind has a firm capacity of 5% for all sites taken together. Then a 20X overbuild of the peak demand will guarantee meeting that peak with curtailment most of the time.

Example; assume peak demand is 40GW and the firm wind credit is 5% then 800 GW of wind capacity will always cover it. Of course if actual demand is 20 GW and the wind is blowing hard producing say a possible 600 GW then 580 would be curtailed. At $2/w that 800 GW would cost $1.6 trillion which is the flaw in the massive overbuild solution.



I think you have a misunderstanding of what “firm capacity” means. It does not mean the wind blows all the time and you can rely on power all the time from wind farms. As we know all wind farms can be becalmed. What the firm power is is statistical measure that the planners use for planning the amount of capacity needed.


John Newlands — Peter Lang has the right of it; sometimes, indeed quite a bit of the time, the entire fleet of wind turbines with BPA as the balancing authority are completely becalmed. Indeed, this condition is often associated with both the hottest and coldest periods. Thus no amount of overbuilding can make any difference except for synoptic scale transmission [which doesn’t exist anywhere at any meaningful scale].

The so-called firm capacity allotment only makes some sense because there are also reserve requirements imposed upon the reliable (dispatchable) generators. I personally assume the worst case for wind + solar (none for extended periods) and plan enough reserve to cover that as well as the more traditional reserve requirements. Therefore I am unable to find any cost effective way to utilize wind or solar thermal in a paln for reliable, on-demand, low carbon electricity generation.


This comment demonstrates clearly what Ender (Stephen Gloor) is about.
(Deleted inflammatory comment)
I posted this reply:
The comments on other blogs by posters (including yourself) on BNC are subject to the comments policy of that blog. BNC has a Comments Policy which is applied to posts to keep the blog relevant and civil.


Peter Lang wrote:

I get the impression you just want to argue for the sake of arguing. You still haven’t provided any numbers to back up your earlier statements.

Not at all, I’m very interested in your final result (and would like to encourage you to get the best possible estimate, as much as is possible given the early stages of this research). There are other ways to ask and answer a question without reference to a specific figure. I’m simply asking: 1) do you intend to follow the DRET – EPRI projection for a 35% cost reduction in wind capital costs by 2030 (page 6-64)? In effect, what is the timeline for the buildout in your model projections (you don’t appear to have one)? If you intend to depart from DRET – EPRI estimates, and assume that costs will remain flat or rise for installed wind energy over time, I assume you will want to amend the following:

Peter Lang wrote:

Any other nubers you come up with will have much less credibility than these [i.e., the figures in the EPRI (2010) report]. So I would not be interested in discussing whether these numbers are right or wrong. These are the numbers the government is using for its modelling, so they are the numbers I will use too.

Using DRET – EPRI figure of $2,744/kW (as capital costs for Australia in 2010), which you correctly reference, and assuming total build over next 18 years to 2030 (and linear cost reduction of 35% as suggested by DRET – EPRI analysis), I get a combined average of around $2263.85/kW for total buildout.


EL, if you want to do the whole analysis based on unit costs for 2030, or for half way between, or some other assumption, then I suggest you go ahead and do it. But I suggest you have to do the whole analysis on a consistent basis. You can’t just pick and choose numbers that suit you. If you do it properly and write it up you could offer it to Barry as a post for BNC.


EL, further to my previous comment, you will need to project the hourly demand profile out to 2030, and do the EDM simulation for those years, or for the year for which you select to estimate the costs. You will have to develop wind and solar power output profiles at 1 hour intervals. Then run the EDM simulation program to estimate the output from each generator.

If you want to project ahead to future years you will get into the same guess work that BZE tried.

BZE tried that approach, made what to many were unrealistic assumptions about demand reductions in future and, as a result, their analysis was largely discredited.

EDM-2011 wisely avoided that pitfall by using the actual NEM 2010 demand data. And we have the current costs for technologies, presented in 2009-10 A$ and projected to 2015. And we have those for all the technologies and prepared on a consistent basis.

I’d argue that is as good as we can do without access to the EDM model and the skills needed to drive it. But if you think there is a large error in what I’ve done, you should be able to demonstrate it, quantitatively. You haven’t done so yet, and nor has anyone else.

Of course I am making many simplifying assumptions in the crude analysis, but after 110 comments, no one has yet pointed out a significant error or provided a reasonable alternative method and substantiated it.

I urge you to have a go yourself. You make lots of suggestions about how to do the analysis better, but you haven’t thought through the implications of what you are suggesting. Until you have a go at it yourself, you will never get your head around all this.


Peter Lang wrote:

The greatest uncertainties in the cost of electricity (proportion of total LCOE in brackets), and therefore the place to focus attention are:

– the solar thermal plants (34%)

– gas turbines running on biofuels (23%)

– transmission and distribution systems (17%)

I haven’t followed the entire debate between you and Ender, but a less expensive single tank thermocline TES system is envisioned by many parabolic trough developers, rather than the more expensive two tank approach referenced by DRET – EPRI (with 6 hours of storage). Sargent and Lundy (2003) have provided a costing for such an approach, and parabolic trough CST that incorporates many of these current and future development trends and efficiency gains.

For their base model … their technology assessment with projected cost reductions for 2020 come to a 56.2 % capacity factor, USD $3,220/kW capital cost, 12 h TES storage (and 24 hour operation). They build on an earlier National Laboratory “SunLab” study for their assessment and methodology (and reach a higher cost for their study). Solar Two is seen as a precursor to future TES development trends at the time (more here on future TES options): molten salts and ionic fluids for heat transfer (operating at 500°C or above), two tank molten salt storage system (high cost), single-tank direct molten salt thermocline system (lower cost). Sargent and Lundy also envision future cost reductions from better solar field optical efficiency, minimizing receiver and piping and storage thermal losses, EPGS efficiency, electric parasitic loads, reduction of forced and scheduled outages, O&M reductions, and more.

Take from it what you will. Sargent and Lundy envision a cost reduction of 33% between 2004 and 2020 (as a consequence of above and more). This is similar to the 30% cost reduction envisioned in DRET – EPRI analysis for solar thermal capital costs by 2030 (see page 6-56). As you have suggested, there is an asterisk near many of your projections (and uncertainties in range of 17 – 34%). With solar thermal, particularly since you aren’t looking at lower cost TES options, or cost reductions for timeline and technology development trends, it’s worth noting that this uncertainty may be larger than the amount you have indicated for the case of CST. I’m out of town next 5 days, so keep in mind when anticipating follow-ups.



You have not yet produced any costs for what you suggest is a cheaper scenario? You haven’t made any attempt to provide alternative costs on an equivalent basis to the other technologies so they can be used in a comparative analysis

As I’ve said before, suggestions are just twaddle if you support your suggestions. If you are still using the Sargent and Lundy (2003) cost projections as your source for solar costs, after it has been totally debunked (by all except the renewable advocates who still clutch to it), then your comments have little credibility.

What is the cost of the scenario you are proposing? What figures do you suggest need to be changed in the tables in Appendix 1 and 2 of the PDF? What is the justification for changing them?

The figures in the thread above clearly demonstrate that renewable energy is totally uncompetitive. You need to find a way to reduce the system cost by a factor of about seven, and make the proposed system reliable, before it could be considered a possible option.
(Inflammatory comment deleted)

You can also extrapolate from the figures in this analysis to see that renewables are probably not viable at any level of penetration. They are not justifiable


Peter Lang wrote:

(The first part of this quote has been edited out)The figures in the thread above clearly demonstrate that renewable energy is totally uncompetitive. You need to find a way to reduce the system cost by a factor of about seven, and make the proposed system reliable, before it could be considered a possible option.

Who has debunked the Sargent and Lundy (2003) report, and on what basis? They cite a Nextant projection “that a 35% cost reduction can be achieved going from a two-tank system to a thermocline system” (p. 4-19). This is the same amount discussed in more recent peer reviewed literature: “In cost comparisons, the thermocline system is about 35% cheaper than the two-tank storage system, due to reduction of storage volume and elimination of one tank” (p. 68). You can choose to use any numbers that you want. This is your study. But to my mind, holding capital costs steady, or assuming that they will rise in the indefinite future (as you do for CSP) flies in the face of available facts, and it also flies in the face of the DRET – EPRI analysis for Australia that you recommend so highly (and which forecasts large decreases in capital costs for renewables over time due to learning curves, volume production, plant scale-up, technology development, and more). (Inflammatory remark deleted.)



You still. have not proveded a clear statement of what figures you suggest be changed in the Tables in the PDF, what they should be changed to justificatoion for whey they should be changed, nor the effect on the total system cost. Until you have a go at ti yourself, you will not understand what you are doing. Heve a go at it yourself and then the readers can discuss what you are proposing. I think waht you are suggesting is jut twaddle (as per David Mackay).


I am not persuaded, by any of the arguments presented so far, that the EPRI / ACIL-Tasman / DRET estimates for solar thermal costs are too high.

On the contrary, I suspect they are more likely to be too low rather than too high. Here are some reasons:

1. There is no allowance for the higher cost of construction and operation and maintenance which must be added because of the remote locations of the solar plants. This could conceivably add 50% to the estimated cost of electricity from these plants.

2. History shows that the projected costs of solar are continually understated. NEEDS (2007) projected that the costs of solar thermal would decrease by 30% by 2010. In fact, the opposite happened. The costs increased by 25%.

3. The expected economic life of the plants is probably greatly overstated. Ender, or was it Bilb, argued on the “Solar Power Realities” thread (or the Addendum), that the solar power output figures from Queanbeyan solar PV power station should not be used because the solar panels were too old to be relevant. They were a few years old at that stage. He said they were out of date and had been superseded by newer and improved technologies. That is, they had been superseded within just a few years. That shows how quickly these new technologies become out of date and superseded. This further indicates that the economically viable life of these technologies will be short. The same general principal applies to solar thermal, although the rate of becoming superseded and not economically viable may be a little slower.

4. Another example showing how quickly these new technologies become out of date and have to be replaced was reported this morning. Today it is reported that the NBN boxes rolled out to the NBN customers in Tasmania (the first installations) have to be replaced. They’ve been superseded in just 1 year. That is likely to happen throughout the life of the NBN (but hopefully at a slower rate). The same is inevitable with all the new solar PV, solar thermal and energy storage devices being continually dreamed up.

5. These new technologies have a short economic life and then have to be replaced. So the capital cost, accumulated through the expected 30 year life of the plant, can be expected to be much higher than the initial capital cost we are currently using. Therefore, the capital cost figures we are using are likely to be too low. I suspect much too low. So the LCOE we are calculating are also likely to be too low.

6. The O&M and replacement costs will also be much higher than the renewable energy advocates are stating.

7. There is still no publically available performance and cost data for existing, commercial, solar thermal power stations (and that is despicable given the public is paying for them).

Therefore, I suspect the costs for solar thermal are more likely to be higher than lower than the DRET figures.

Given we have no more authoritative costs to use, that are properly comparable across all the technologies being considered, I can see no justification for changing the unit cost figures for either Wind or solar thermal. I can see a justification for increasing the cost of PV, by a factor of about 1.5 to 2, as explained in the post.


The Elliston et al. claims for the potential for bioenergy are taken from Diesendorf, 2007, Greenhouse solutions with sustainable energy (book), but for those without the book, the following report contains the same information on page 80 & 81:

Click to access Clean_Energy_Future_Report.pdf

Kelleher (1997) has estimated that the harvestable stubble residues from Australian grain crops (mostly wheat) and cotton in 1996-97 amounted to 68 Mt. Previously, stubble used to be burned off and this led to the structural degradation of soil, erosion and fertility decline in many areas. Nowadays conservation farming methods are prevalent and so crop residues are retained in many areas to protect the soil surface and conserve nutrients. Since the area under all agricultural crops (not trees) in 1997 was about 20 million ha (Mha), this is equivalent to 3.4 green t/ha. Kelleher assumes that 1 green t/ha would be retained on the land to maintain sustainability of the soil. This leaves 48 Mt green residue, which is approximately equivalent to 24 dry Mt. Given that this has an energy content of about 20 GJ/ dry tonne, we obtain total energy available in the fuel of 480 PJ. Assuming that this is all converted to bioelectricity by direct combustion at 35% efficiency, it would generate 47 TWh (169 PJ), which is about 23% of Australia’s electricity generation in 2001.

There is little reason to doubt that there is substantial untapped potential for agricultural residues, and given the right market conditions, I would agree that perhaps a substantially larger market for bioenergy could be developed. Arguably Finland is the world leader in bioenergy, which uses mostly trees and forest residues for space and water heating, and increasingly for boilers in CHP (combined heat and power plants). This is similar to other leading bioenergy users in Scandanavia and Europe. As an aside, I looked at the viability of marketing wood chip space heaters a few years ago and concluded that they weren’t economic and would face enormous market challenges. However commercial appliances can be purchased in Melbourne, but few are sold and the cost of the bulk pellets is too high (pellets were $360/tonne in 2006, $475 in 2008 and $600 in 2009), which worked out at 3 to 4 times the running cost of natural gas.

Click to access FINLAND-bioenergy.pdf

The Elliston approach is quite different from the Scandavian bioenergy industry and appears to be novel (although technically feasible) and untested on a commercial scale. The Elliston energy claims are based on a simple theoretical calculation of taking the product of area x yield x energy density. Without further consideration of costs, technology, ecological impacts, economic benefits and consideration of farmers, harvesting, transport costs and logistics, processing, storage, EROI, seasonal variations, droughts, and other considerations, it is a purely theoretical exercise, and really no different to the sort of non sequitur frequently used in these exercises such as “a square 50km x 50km with solar panels could supply all of Australia’s annual energy.” What does this tell us, and what does it contribute to a serious debate about energy? Not a lot.


@Graham Palmer: Finland does get around quarter of its primary energy from forests which is roughly similar to the share of coal and gas combined. However, most of this is from byproducts of the forest industry and unlikely to be economically viable on their own (without subsidies). Also, the use of wood for CHP is rather limited to the country side. In bigger cities and especially in the Helsinki region (where I live, and which is pretty much surrounded by forests) the CHP plants run on coal and natural gas. There is some discussion of using more bioenergy in those plants, but the required amounts of biomass are so large that the area required extends much further than the usual harvesting areas in the country side.


With ‘waste’ biomass we have to ask what has been done with it up to now. I think the answer is that very little of it has been wasted. A lot of combustible material has been left to rot in situ to regenerate the soil and only the best bits taken away. That gives us timber offcuts, sawdust, vegetable oil, bagasse, chicken litter, straw, incinerator garbage and so forth. Their harvesting, million and disposal has been paid for by other objectives so they are a sideline. If they become the main objective the economics completely changes. It means using diesel and fertiliser to get a decent net energy return with EROEI > 8 if proponents of that theory are right.

On wood pellets I’ve wondered if every home with a chimney should contain a suitable stove for emergencies. If for example a frost hit Sydney the power draw for electric heating would be enormous. Every house would have several sealed bags of pellets on standby, too pricey to be used regularly. Thus the biomass would be distributed not burned in a central location.


A comprehensive study titled THE ENERGY BALANCE OF MODERN WIND TURBINES was published by the Danish wind industry in 1997. Hardly an unbiased source but the material is very detailed if rather dated.

Click to access doc1249_971216_wind.fiche37.pdf

The result was that for onshore wind turbines the energy payback period was 3-4 months including scrapping the turbine at the end of its life. It seems unlikely that modern turbines would be less efficient than those of 1997. Assuming wind turbines last say 20 years and the paper is not serious flawed this would be an EROEI of 60:1.


EROEI is off topic for this thread. I hope you can move these last three comments to the Open Tread or the EROEI thread.

Can we please focus on trying to find errors in the lead article. To date no one, as far as I can see, has tried using the Excel spread sheet linked up thread to check the effect of their ideas on the total system costs.

I’ve had other input that suggests the area required to support the biofuel would be far higher than I’ve estimated. Perhaps six time higher. The reason being that my figures are based on UK land productivity. If someone want to look into that a start might be to look at page 8-9 in the Grattan Institute report and factor from 30 MW at 70% capacity factor to 24 GW at 13% capcity factor.

I suspect if someone wanted to think carefully about the assumptions I’ve made for estimating the transmission capacity required (see Appendix 2 in the PDF version), they could come up with a different way of looking at it. That would be a helpful contribution.


Kind of off topic, but I’m quite impressed and surprised to see Mark Diesendorf criticising the Beyond Zero Emissions “study” and acknowledging many of its blatant flaws.

Now they can’t just come back with the usual predictable retort and claim that all us scientists criticising them are all just part of the big mean nuclear conspiracy!


Luke Weston,

I agree. There was quite a heated on-line discussion between Mark Diesendorf and Matthew Wright, lead author of ZCA2020, on a number of other blog sites. In one of those he accused the BZE team (the group who produced the ZCA2020 report) of having a preconceived view of what was needed and then doing all the analysis to fit their preconceived idea.


Graham Palmer @ 16 February 2012 at 9:56 PM and
Jani-Petri Martikainen @ 16 February 2012 at 10:42 PM

Thank you for your excellent comments. Both of you cut through to the heart of the issue. And you explain it very well.

I think Graham Palmer’s comment is very relevant to the Australian situation. It seems Diesendorf and the EDM-2011 study are assuming that most of the biofuel would come from crop residues. Graham has explained the basis of the Diesendorf assumptions. This indicates that most of Australia’s crop stubble would have to be collected and converted to biofuels, stored until needed and transported to the biofuel power stations. Given that we have long droughts (the last one was 15 years), the amount of biofuel storage required might be two to five times the average annual demand.

Two other estimates have been pointed out to me. These use the figures in the Grattan Institute report. Both show that we would need to collect all the crop residue from all the grain crops in Australia to meet the EDM-2011 fuel requirements.


Graham Palmer and anyone else,

Could you offer an independent estimate of the capacity of the interstate transmission interconnectors that would be needed to achieve the EDM-2011 assumption of a [near] copper-plate transmisison system. I’ve described my approach and assumptions in Appendix 2 (in the PDF).


Peter Lang wrote (lead article):

DRET unit costs for CST are for 6 hours thermal storage.  The EDM-2011 simulations assume 15 hours storage.  The capital cost for CST is factored up by 1.53 to account for the increase of solar field and thermal storage size to increase energy storage from 6 hours to 15 hours.  The factor of 1.53 was derived from the DRET (2011c) costs for CST without storage and CST with 6 hours storage, assuming a linear upscaling.

Looking a little closer at some of your assumptions, the storage costs in the DRET – EPRI assessment appear to be significantly more expensive than current estimates (and by a factor of some 500 – 1600%). Six hours of storage with a total capital cost of $2767/kW is some $461/kWh AUS (or $499.5/kWh USD). Looking at two available sources for cost estimates on storage for parabolic trough CSP plants in 6 – 15 hour range (one from EPRI), we get one source calculating these costs in $116 – 89/kWh USD range, and another in $40 – 30/kWh USD range (factoring in total direct costs for nitrate salt inventory, storage tanks, tank insulation, tank foundations, oil-to-salt heat exchanger, nitrate salt pumps, and balance of system). Do you have any explanation for why these costs are so high in the DRET – EPRI assessment for Australia?

Let’s do a “best case” sensitivity analysis using your spreadsheet for 1) updated CST costs with 15 hours storage, 2) system costs in 2030 as suggested in Diesendorf response to Lang and DRET-EPRI cost reduction factors, and 3) lower discount rate of 8.1% as suggested here (and in ATSE and University of Melbourne analysis).


1) CST costs: plant cost is listed as $5109/kW in your account. For updated storage cost, let’s use $82/kWh AUS (converted from $89/kWh USD) in more recent EPRI assessment (estimate for 3500 MWh storage system). For a 233MW plant with 15 hours storage (3500 MWh), total plant cost is $1.477 billion (or $6340.76/kW).

2) 2030 system costs: DRET-EPRI forsees 35% cost reduction (relative to 2015 technology) for solar PV (page 6-60), 35% reduction for wind (page 6-64), and 30% reduction for CSP (page 6-56).

3) Discount rate: 8.1% (recommended in University of Melbourne assessment to comply with ATSE analysis, 75-25 debt-equity split, 7.3% debt cost, and 17% pre-tax equity cost in Australia).

Result: $174/MWh AUS (total system LCOE in 2030, relative to 2015 costs, and using lower EPRI cost estimate for TES storage, DRET-EPRI cost reduction factors for 2030, and ATSE recommended discount rate).


EL wrote:

Result: $174/MWh AUS (total system LCOE in 2030, relative to 2015 costs, and using lower EPRI cost estimate for TES storage, DRET-EPRI cost reduction factors for 2030, and ATSE recommended discount rate).


4) OCGT: also includes $801/kW input for OCGT (from DRET – EPRI assessment page 7-14).


Graham Palmer wrote:

There is little reason to doubt that there is substantial untapped potential for agricultural residues, and given the right market conditions, I would agree that perhaps a substantially larger market for bioenergy could be developed.

One recent study considers native grasses on pasture land as an alternative feedstock to food crops for biofuel production in Australia: “The non-cleared land in this extensive agricultural zone shows a promising technical production potential (266 Mt y−1) and if 15% of this land’s NPP were to be transformed into ethanol, it could replace a significant part (54%) of current Australian petrol demand” (Herr, et. al 2012).

Preliminary national resource estimates for agricultural feedstocks in Australia can be found here: “Preliminary estimates show that upper limits for second generation biofuels to replace petrol may be between 10 – 140% of our current petrol usage” (p. 12), and additional research and models are being developed with specific attention spatial distribution, climactic variability, and transportation issues (as they relate to costs), but further research is needed (based on my quick look at literature).


John Newlands wrote:

Grass fuel to replace half of petrol?

“Half of petrol” is a measure of resource availability. You’d convert grass feedstock into biogas for use in OCGT plants (as with agricultural residues in a 100% renewables EDM option).



I haven’t tried to follow through your calculations and assumptions. I’d make the following points:

1. I am not clear if your cost is for the storage component only or includes the solar field multiplier. If you look at the NREL SAM spreadsheet (link provided in previous comments) they provide a breakdown of representative costs. Using those the multiplier from 6 h to 15 h storage for CST parabolic trough is 1.75, i.e. higher than the 1.53 I derived (thanks to Martin Nicholson’s elegant method) from the DRET figures. From memory, this multiplier is less than we get using the NEEDS (2008) figures. All the links are provided in the lead article and my previous comments on this thread.

2. As I’ve stated before, if you want to argue to change the figures for one technology in a suite of technologies being compared, you need to make the appropriate changes to all the technologies to keep them comparable. The figures used in comparisons must be produced using the same methodology and a consistent set of inputs. I raise this because I’ve noticed you suggesting on another thread that the discount rate of 10.1% is too high and I should use 8.1%. If you want to suggest that, then you need to understand why it AEMO, DRET, ACIL-Tasman and the entire stakeholder group involved in updating the EPRI figures for use in the 2011 Energy White Paper and the Treasury’s modelling, decided to increase the discount rate from the 8.4% E PRI used, to the 10.1% now considered to be the correct figure to use for 2009-10 costs. EL, I suggest you need to do some homework on the basis for the existing figures, before suggesting changes.

3. If you want me to spend time on your alternative calculations and assumptions, I’d urge you to lay out the assumptions, inputs, sources and calculations clearly so I can follow them. I am not going to waste time going through material that is not explained clearly and completely. At this point, I am convinced I’d be wasting my time.



4) OCGT: also includes $801/kW input for OCGT (from DRET – EPRI assessment page 7-14).

That is the capital cost for the OCGT generator plant. The fuel cost, including the gas delivery system, is included in the price of the gas. However, for the biofuel system we need to develop the infrastructure to get the fuel to the OCGT plants. So we need to include the capital cost to set up the biomass collection, transport, storage system, the conversion system to biofuel, the biofuels storage and distribution systems. On top oif that you have the O&M cost which is included in the fuel costs. I presume, since this is envisaged to be long term system, then something will have to be paid to the farmers for not just the collection and handling of biomass, but also for the degrading of the land and the fertilisers to partly replenish the nutrients removed.

Can you provide an authoritative cost estimate (from an authoritative, non partisan source) for the capital and O&M costs for the biofuel system which captures virtually all the residue from Australia’s grain crops – i.e. Western Australia’s too to feed eastern Australia’s electricity system.

Tell Western Australians about that idea :)


EL I’ll keep an eye out for more reports on German grass based biogas because I suspect the economics are bogus. Some questions
1) did they get a subsidy?
2) did they use diesel powered machines to harvest the grass?
3) how much effort does CO2 (typically 25%) removal take?
4) why sell the sludge when it could go back to the field?
5) when will a large (200+MW) OCGT plant run on biogas?

Call me cynical but everything about the German energy scene is suspect. I made an 80L digester based on grass clippings inoculated with cow manure with a mini gasometer for low pressure storage . After a few weeks I realised the smell and the work involved didn’t justify the weak gas output. it really helps if the sludge comes to you (eg via sewer or landfill) while oil and coal based energy are on tap. Any ‘green’ subsidy is the cherry on top.


EL wrote:

Result: $174/MWh AUS (total system LCOE in 2030, relative to 2015 costs, and using lower EPRI cost estimate for TES storage, DRET-EPRI cost reduction factors for 2030, and ATSE recommended discount rate).

IEA provides a bit more guidance on costs (current and future) for large scale biomass gasification plants in their following technical summary: “Biomass for Power Generation and CHP.” Current capital costs in the US are listed at $2,000-$3,000/kW, and future target costs at $1,000/kW. They reference a delivered biomass price of $3/GJ (which presumably factors in many collection and handling costs).

Making adjustment to input #4 on “best case” EDM cost model above for biogas generation ($931.6/kW AUS for plant cost, converted from 1,000/kW USD) one gets a final result: 164/MWh AUS (total system LCOE in 2030, relative to 2015 costs, and using lower EPRI cost estimate for TES storage, DRET-EPRI cost reduction factors for 2030, target IEA biomass plant and fuel cost, and ATSE recommended discount rate).

Here is relevant quote from IEA technical summary:

The capital cost of power plants with biomass gasification in the United States is about $2000-$3000/kW and generation cost is in the order of $90/MWh. Such plants may be cost-effective in CHP mode if connected to district heating schemes. The cost of biomass combustion steam cycle and CHP plants can be lower, with $1000/kW as the cost target. In Europe, the investment cost of biomass plants varies considerably from $1000 to $5000/kW, depending on plant technology, level of maturity and plant size (Table 1). Assuming a delivered biomass price of $3/GJ, the generation costs from biomass gasification plants, even at higher efficiencies, are expected to be some $100-$130/MWh, more than twice the cost of fossil-fuel power plants. These costs may be significantly reduced by technology learning and then represent a low-cost option for renewable electricity (page 3)


EL,’I’ve already referenced that document. Bits and pieces of data that are not put together in a coherent manner are meaningless to me.

The Gattan Institute Report gives a cost of about $5,500/kW for small plants of about 5 MW, To scale up to 30 MW plants, especially running on grain crop residues, has not been demonstrated as logistically feasible in Australia. We’d need 5000 x 5 MW plants, plus the storage for several years to get through the periods of drought and crop failures. We’d alos need massive over build.

I’d urge you to just apply sone engineering judgement to your ideas before putting them forward. The concept of the biomass generation proposed by EDM is ridiculous.


Did anyone notice the satelite map showing cloud cover over Australia yesterday. All the EDM proposed solar thermal power stations sites except Roma and Longreach were under cloud at the same time.


Peter Lang wrote:

We’d need 5000 x 5 MW plants, plus the storage for several years to get through the periods of drought and crop failures.

That sounds about right. “The number of biogas plants in Germany has increased by about 90% (2300 plants) in the last 5 years, with an average capacity of 500 kW compared to 60 kW in 1999. The introduction of economic incentives aimed at enhancing the deployment of renewable energies via the Renewable Energy Sources Act (EEG) has led to the proliferation of biogas production from large-scale plants (greater than 500 kW) organized in industrial parks, and with elaborate feedstock logistics” (page 185).

I don’t see where Grattan gives installed costs for gas/combustion turbine burning biogas at $5,500/kW. How expensive is it, after all, to put a PM filter on a OCGT plant? EPA gives installed costs for a CHP system to 40MW at $700-2,000/kW USD, and O&M costs at 0.08-0.11/kWh. The economics of larger biogas plants improve with size: less than $3,000/kW AUS (converted from euros) for plants exceeding 350 kW in European Biomass Association Roadmap.

I agree with you, the energy picture with biogas looks challenging until we get more experience with larger plants and have a better understanding of resource limits and availability in Australia. The links I have provided above suggest this is forthcoming (and may come up short for a full 100% biogas compliment and with a high degree of reliability). I don’t see any merit to adding fuel development costs to inflated capital cost for power plants (as you have done in your analysis). In fact, you have a fuel cost variable in your cost model, it seems reasonable to put these costs there (don’t you think)? The $10/GJ figure you have included seems reasonable to me based on other estimates I have seen. There’s a fairly good paper on grassland for biogas production Prochnow, et. al. 2009 perhaps worth a look for anybody who is interested.


The $5500/kWe presumably includes the cost of the biogas digester, the logistic infrastructure and assorted equipment. A large plant would also require a desulpurization unit to deal with hydrogen sulphide. Any good references on full cost breakdown for larger biogas units?


Cyril R.

The $5500/kWe AUS presumably includes the cost of the biogas digester, the logistic infrastructure and assorted equipment.

All three sources I have provided (one of which was previously used by Peter Lang and disregarded) provide total installed costs for digester, associated infrastructure, PM filtration, turbine, etc., for a combined biogas power plant or CHP plant. IEA ($2000-3000/kW USD in US), EPA ($700-2,000/kW USD for installed cost as CHP system to 40MW), and European Biomass Association reporting results for Germany (less than $3300/kW USD), and higher costs for Italy ($4250/kW USD). Frankly, it doesn’t make a lot of sense to build these things any bigger at this point in time. While the capital cost of doing so would be less, you’d be running up costs transporting feedstock, and you might as well put your agricultural waste in a landfill and just use more affordable natural gas. The research paper by Herr and Dunlop (2011) identifies about 17 areas in Australia where agricultural feedstock densities are sufficient for producing 500kt of stubble in less than 100 km radius, and numerous others where 200 km is needed. If Peter Lang wishes to continue to use the $5500/kWe AUS figure he should provide a source for doing so. Otherwise, using a high fuel cost value, as well as an unsupported capital cost for biogas plant, would lead some to disregard his final result as artificially high (for projected current costs of plants today).

If OCGT capital costs are $801/kW (DRET – EPRI, page 7-14), I have a hard time seeing how adding biogas production would result in an increase of 686% to the capital cost of the plant? If Lang would like to use a higher fuel cost than $10/GJ in his assessment for biogas, then he should provide a source for this as well.



You asked for the Grattan Institute reference. I don’t know why you can’ look it up yourself, especially since it has been discussed on at least two recent threads. But here it is again:
Gigure 8.6,

The logistics for 30 MW plants, espeically using cereal crop stubble, are not demonstrated to be feasible in Australia.

The logistics to collect the stubble from all Australia’s grain crops to power the poposed gas turbines in Eastern Australia has certailny not been demonstrated to be viable.

Perhaps EL would like to attempt to provide costs for the proposed biofuel system to meet the following requirements:

– 24 GW power (but actally about 33 GW is needed to provide reliable power supply)

– equivalent of 290 PJ of gas fuel energy per year

– reliable supply of this energy through successive years of failed grain crops and decades of droughts

– biomass storage and biofuel storage sufficent to supply reliable electricity throughout all years and all seasons

– biofuel distribution system to the generating plants

– transmissions from the biofuel plants to the demand centres

I’d be seeking Capital, Fixed O&M, Variable O&M and fuel costs for the total proposed system of ‘gas turbines running on biofuels’. You need to explain how the crop residues will be collected.

At the moment I find your bits and pieces or unrelated and mostly irrelevant clippings as of little use for the many reasons I’ve already explained.


EL and Ender have argued in numerous comments on this thread that the cost estimates I used are too high for Concentrating Solar Thermal (CST) parabolic trough, with 15 h storage, and the ‘gas turbines running on biofuels’. They have not presented alternative costs which are derived with a consistent methodology and assumptions across all the technologies. So the suggestions they have made so far cannot be applied. I remain satisfied that the costs used in Lang (2012) are the best available at this time for estimating the cost of the EDM-2100 simulated scenario and the variations of it.

EL also argued to use a different, lower, discount rate for the analyses. But it would be wrong to do this without fully understanding the basis of calculation of the discount rate used for the DRET LCOE figures and the proposed alternative (lower) discount rate, and presenting a valid argument to justify making the change. The discount rate was decided in AEMO and DRET sponsored stakeholder meetings, with Treasury and ABARE and other key players included, including the various renewable energy advocacy groups. I believe the figure is as good as we can get for now.

Despite me being satisfied the costs used are consistent between the technologies, are derived for Australia and are the best we have available, I have been looking at other approaches to these estimates. I’ve done some other estimates. These are not as well justified but they do show that even using other figures the rankings are the same, the conclusions are unchanged, and the revised figures make little difference to the absolute numbers.

First I substitute the US DOE/EIA (2011) capital and operating costs for biomass generation for the EPRI (2010), ACIL Tasman (2010), DRET (2010) costs. The new DOE/EIA costs are in 2009 US$ whereas the DRET costs are in 2009 A$. I have not made the necessary adjustments. Also, I do not know some of the inputs needed for calculating the DOE/EIA LCOE figures so I’ve adjusted the discount rate to calculate the correct LCOE figure for the capital and Fixed O&M component. What I’ve done is not strictly correct, but will do as a rough approximation.

The DOE/EIA LCOE for biomass generation assumes the fuel is wood and the plant runs at 83% capacity factor (average for its whole life) – so it is a base load plant. Conversely, the EDM analysis assumes the fuel is residue from Australia’s grain crops and the plants run at 13% capacity factor, i.e. strictly peaker plants, with most of the generation in winter. So almost a year of fuel must be stored for average years, and possibly many years of fuel must be stored to last through droughts. Therefore, clearly, the US costs cannot be applied to Australia. Therefore, I’d argue the Grattan Institute (2012) capital cost for 5 MW plants (Figure 8.6) is as good as we have available. I expect it is more likely to be too low than too high when all the costs are included.

But let’s do an exercise and apply the US capital and O&M costs, without making the conversion to 2009 A$, and see what difference it makes to the LCOE.

14. Biomass Bubbling Fluidised Bed (p14-1)

Click to access electricity.pdf

50 MW net.
Requires 2000 tonnes per day of wood (at 50 % moisture content)
Water consumption = (not stated but much higher than for a coal or nuclear plant)
Waste water is sent to the municipal waste water system or other wastewater delivery point – (i.e. the cost for such a facility is not included in the cost of the plant)
Adjacent substation nearby (i.e. not included in the costs)

2010 costs in 2009 US$
Capacity Factor = 83%
Capital cost = $3,724/kW (2009 US$) (excluding project finance costs)
Fixed O&M = $99.30/kW-year
Variable O&M = $6.94/MWh
Fuel = $35.36/MWh
Fuel = $2.50/GJ
Heat rate = 13,500 Btu/kWh
Thermal efficiency (HHV) = 25%

Points to note. These costs are for a wood burning, baseload plant. These costs cannot be compared with the cost for a system that is to operate on crop residue from Australia’s grain crops.

Compare LCOE at 83% and 13% capacity factor:
At 83% capacity factor, LCOE computes to US$111.6/MWh
At 13% capacity factor, LCOE computes to US$483.6/MWh

However, these are based on fuel cost of $2.5/GJ
This is less than half the cost of natural gas for electricity generation in eastern Australia. It is clearly much too low if we include the cost of the biomass system to produce, collect, transport, produce the biofuel, store the biofuel, distribute the biofuel and/or transmission cost from remote small power stations.

At a fuel cost of $10/GJ, the LCOE becomes:
At 83% capacity factor, LCOE computes to US$218.5/MWh
At 13% capacity factor, LCOE computes to US$590.4/MWh

However, all these figures are guesswork without a design basis and proper cost estimates for the proposed system.

Grattan Institute (2012) (p 8-9) states:

“For a 30 megawatt power plant at a 70% capacity factor the land area would be around 240,000 hectares and involve nearly 500 average sized wheat farms.”

For 24 GW power plant at 13% capacity factor the land area would be around 36,000,000 hectares and involve nearly 75,000 average sized wheat farms.

We can double or triple this figure to get us through long droughts and seasons of failed crops. We can also add the cost of storage to last for years of below average biofuel production. And we should add the cost of transport facilities used to move biomass from one location to another for when the crops succeed in one region but fail in another. We’d need roads, trucks, railway lines and rolling stock, all of which is to have sufficient capacity for the worst conditions but would be used rarely. The capital costs and the O&M costs must be included in the cost of the biofuel.

The costs just keep on increasing the more you think about the biomass idea.

Furthermore, Australia’s total area under grain crops is about 20,000,000 ha, so the EDM-2011 study needs twice as much land area under grain crop as we have. The 20,000 ha figure includes Western Australia’s grain crops. So we need to collect and transport all of Western Australia’s crop residue to eastern Australia to help to feed just half the EDM-2011’s demand for biofuel.

EL also argued we should extend the analysis to 2030 and use the projected costs for the various technologies for 2030. To extend the analysis to projection of the estimated costs in 2030 is fraught with uncertainties.


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